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Repowering combined cycle power plants by a modified STIG configuration
Energy Conversion and Management 48 (2007) 1590–1600 www.elsevier.com/locate/enconman
Repowering combined cycle power plants by a modified STIG configuration Roberto Carapellucci *, Adriano Milazzo Dipartimento di Ingegneria Meccanica, Energetica e Gestionale, Faculty of Engineering, University of L’Aquila, Monteluco di Roio, 67040 L’Aquila, Italy Received 27 July 2004; received in revised form 18 May 2006; accepted 26 November 2006 Available online 30 January 2007
Abstract An innovative repowering concept for combined cycle power plants is presented. The design concept consists in adding one or more gas turbines to the combined cycle, integrated by steam injection into the existing gas turbine. The steam is produced in a simplified heat recovery steam generator fed by the additional turbine’s exhaust gas. The scheme is quite simple and easy to adapt to various types of combined cycles. The efficiency of the repowered plant compares favorably with that of the original combined cycle and far surpasses that obtained by simply adding the gas turbine with no integration. Furthermore, the additional gas turbine enhances the plant operating flexibility as any power output intermediate between the original and the repowered capacity can be readily attained with no significant efficiency penalty. A thermodynamic and economic evaluation of the system feasibility is presented. 2006 Elsevier Ltd. All rights reserved. Keywords: Repowering; Combined cycles; Gas turbines; Steam injection
1. Introduction Almost all industrialized countries are now facing some degree of electric power shortage. The major problem is probably the lack of suitable sites for building new power plants of whatever type or size. Moreover, increasing environmental awareness has resulted in more demanding requirements in terms of preliminary analysis, prolonging and complicating the plant commissioning process. This is especially true of those countries, like most European ones, with high population density and a large number of conservation sites of historic interest or natural beauty, where there is increasing public opposition to new plants, even for low emitting, natural gas fuelled, combined cycles (NGCC). All these problems have led many utilities to consider extending the life of existing plants by repowering [1,2]. Basically, these interventions have been done on oil fired
*
Corresponding author. Tel.: +39 0862434320; fax: +39 0862434303. E-mail address: [email protected] (R. Carapellucci).
0196-8904/$ - see front matter 2006 Elsevier Ltd. All rights reserved. doi:10.1016/j.enconman.2006.11.024
steam plants by addition of a natural gas fired turbine. This reduces specific emissions of the existing steam plant while maintaining or even slightly improving its efficiency. As a rule, a repowered plant can be expected to give a lower cost per kW h produced as well as per kW installed. Repowering of steam plants can be achieved in two ways: feed water repowering and boiler repowering. The first option uses heat from the turbine exhaust to raise the feed water temperature instead of bleeding steam. This means that increased steam flow has to be managed by the low pressure section of the original steam turbine, requiring either extensive modification of the steam turbine or impairing the repowered plant performance. The other option, boiler repowering, entails major steam generator redesign. As gas turbine exhaust is used as oxidant for combustion, the combustion air preheater is no longer required. This increases stack temperature, thus limiting efficiency improvements. In spite of the above limitations, repowering has been performed on various steam plants. The object of the work presented herein is to explore the possibility of also repowering combined cycle power plants. To this aim, the steam generated by an additional gas tur-
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Nomenclature Symbols A heat transfer area a, b exponents in Eq. (3) C constant in Eq. (3) h specific enthalpy M mass flow Nu Nusselt number p pressure P power Pr Prandtl number q heat flux Re Reynolds number T temperature U overall heat transfer coefficient v specific volume x, y, z exponents in Eq. (5) Acronyms CC combined cycle CoE cost of electricity GT gas turbine HRSG heat recovery steam generator IGV inlet guide vane NGCC natural gas combined cycle
bine is injected in the existing combustion chamber. The performance of the proposed system has been evaluated for various configurations at full and part load operation. The results are promising in terms of increased power and energy efficiency and also demonstrate the additional electricity generated is cost competitive. An application for a PCT international patent has been issued for the proposed scheme [3]. 2. Repowering of combined cycle power plants Many utilities in Europe installed NGCC plants in the 1990s, and because of their high efficiency and low emissions [4–7], these plants are increasing their market share. The high residual value and long life expectancy of these plants poses the question whether their output can in some way be increased without compromising efficiency. To answer this question, one has to consider the characteristics of existing plants so as to identify those that may be advantageously improved. For this purpose, it may be useful to briefly review the evolution of NGCC plants and group them into homogeneous subsets. 2.1. Existing CC plants According to Ref. [8], up to now, there have been four generations of combined cycle (CC) plants. The early versions were basically repowered steam plants with fired
SCR STIG O&M
selective catalytic reactor steam injected gas turbine operation and maintenance
Greek letter g efficiency Subscripts a approach des design condition e electrical i inlet I incremental (referred to efficiency) is isentropic o outlet pp pinch point RCC repowered combined cycle SI injected steam t thermal TE turbine exit Superscript reference value *
steam generator. These steam generators had bare tubes, heat exchange being ensured by the high process temperatures. They had a single or two pressure levels with no reheating. The last of these first generation plants were installed as late as 1968. In 1958, with the advent of an economically feasible technology for welding continuous fins to tubes, the second generation of combined cycles began to take shape. Improved heat exchange made it possible to recover heat from the gas turbine exhaust, which was then used for feed water heating. The first applications in the 1960s were for power and heat generation. By the 1970s and 1980s, the technology had matured in the utility sector for mid-range loads. Two or three pressure level steam generators were employed but still with no reheating. Nitrogen oxide control techniques were also introduced in this period, basically by water or steam injection in the combustion chamber. These second generation plants were still being installed at the end of the 20th Century. The gas turbine of these plants was not specifically designed for use in a CC configuration. Therefore, it was usually characterized by a rather high compression ratio in order to achieve relatively good efficiency in an open cycle configuration. This is actually a drawback for CCs, as it means a lower exhaust temperature and, hence, less energy available for the steam cycle. As soon as CCs had established a primary foothold in the power industry, the need arose to design a gas turbine
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specifically for use in a CC with an optimized compression ratio. On the other hand, gas turbines have seen a steady increase in firing temperature due to extensive materials research and especially to refrigeration. A high firing temperature is particularly important for CCs, as it raises the exhaust temperature for a given compression ratio. These two factors prompted the development of a third generation of CCs. The first plants entered into commercial operation in 1990. The heat recovery steam generator (HRSG) usually has three pressure levels and reheat [9,10]. NOx emission control is mandatory, and the plants are equipped with dry low NOx combustion systems for use with natural gas, while a selective catalytic reactor (SCR) is also required to comply with emission regulations. The latest advance in CC technology consists in the introduction of closed loop refrigeration of the first stage nozzle, the fourth generation, currently being introduced into the market. These plants are designed to reach a 60% efficiency target [11,12], as results of the further increase in firing temperature, the reduction of temperature drop across the first stage nozzle and the elimination or reduction of the loss of compressed air achieved by open loop refrigeration. Many third generation plants have recently been installed. These plants have high power output, high efficiency, low emissions and a fairly long life expectancy, as opposed to the older plants whose remaining useful life does not justify the cost of repowering. Therefore, the proposed concept focuses on a typical plant installed in the last decade. Obviously, this is not to be intended as a limitation to the concept: repowering can be done whenever technically and economically feasible, evaluating the cost and energy efficiency of the additional power in the specific case at hand [13,14]. 2.2. The repowering concept The proposed repowering scheme is based on the addition of a gas turbine and of a HRSG to a baseline CC. These new components are integrated within the existing
G.T.
plant by injecting the steam produced by the additional HRSG into the existing gas turbine. In this way, the original turbine is transformed into a STIG (steam injected gas turbine), thereby increasing power. CC power augmentation is, thus, the sum of the power generated by the new gas turbine and the additional power of the original plant, comprising both the gas turbine and steam cycle. Obviously only a limited amount of steam can be injected into the original gas turbine [13]. The calculations that follow are done considering a maximum of 10%. Even so, because of the thermodynamic properties of steam, a substantial power increase can be achieved. The exhaust flow through the existing HRSG is also increased, thus benefiting the steam cycle [14,15]. The pressure required to inject this steam into the turbine is relatively low compared to that usually employed in steam turbines. So the HRSG can be of very simple design, with a single pressure level and a low pinch point, thus reducing the stack temperature and increasing heat recovery. The proposed scheme is shown in Fig. 1. As can be seen, the steam line feeding the original gas turbine connects the plant to the added section, that comprises a gas turbine and a heat recovery steam generator. However, many other subsystems may be shared to reduce the repowering cost such as, for examples, flue gas treatment, electric power conditioning etc. One major addition to the plant is the water flow entering the new HRSG, which is inevitably lost at the stack. This can be a major drawback in certain situations and limits the applicability of the present scheme to sites with large fresh water availability, though the specific water requirements are fairly low, as will be shown later. If a low temperature thermal load is available nearby the power plant, the steam in the exhaust could eventually be condensed and the water could be recovered. Obviously, the very large size and the very low temperature level of such a heat sink restricts this option to quite uncommon cases, and its feasibility has to be carefully evaluated. Another significant feature of the proposed repowering scheme is its operational flexibility. Because of the inherent
G.T.
Added Section
L.P. H.P. I.P. Existing Combined Cycle Power Plant Fig. 1. Scheme of the repowered plant.
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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. At full load, the efficiency does not differ substantially, as will be demonstrated by the thermodynamic simulation. Fitting both the new and original gas turbines with variable intake guide vanes (IGVs) should provide a fairly wide operating range with efficiency close to rated. 3. System modelling The scheme outlined above has been numerically studied using a modular simulation code already adopted by the authors elsewhere [16]. The code is based on fundamental thermodynamic relations, including real gas behavior and pressure losses. Using this general purpose code, it is possible to simulate practically any power plant component in design conditions, including gas and steam turbines, steam generators, condensers, heat exchangers or even fuel cells. Each component is modeled by mass and energy balances. For the sake of generality, all components are represented as modules, characterized by a set of indices describing the type of module and its operating conditions. A vector provides the list of the composing modules. Each module has a number of nodes, characterized by other indices: they indicate the position of the node in the module and its absolute position in the overall plant scheme, as well as the type of node, i.e. mass, mechanical energy or heat exchange node. In this way, the plant configuration can be described by the match between the absolute and relative position indices. In this work, the original code has been extended to off design operation. The description will cover only those components actually contained in the proposed plant. 3.1. Gas turbine unit Each gas turbine is modeled as a single module. The operating condition is determined by matching the compressor and turbine pressure and flow rate. Once the design point is found, the efficiency can be calculated by mean line analysis. Turbine refrigeration is taken into account by including a cooling transformation prior to and following the adiabatic expansion. Concerning the combustors, the code calculates the thermodynamic properties of the combustion products in chemical and thermodynamic equilibrium. Part load conditions are obtained by varying the IGVs at the compressor intake and, for greater departure from design conditions, the fuel–air mass ratio in the combustor. 3.2. Steam cycle The steam turbines are divided into sub-units by the sections, which introduce discontinuities into the expansion, that is bleeding or steam injection. The thermodynamic conditions at the exit of each sub-section k is determined
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pffiffiffiffiffiffiffi by setting the reduced flow rate M v=p constant irrespective of operating conditions and solving the system: ( pffiffiffiffiffiffiffiffiffiffiffi pffiffiffiffiffiffiffiffiffiffiffi ðM vo =po Þk ¼ ðM vo =po Þk ð1Þ ðho hi Þk ¼ gk ðho;is hi Þk for given rated conditions, mass flow rate M and actual conditions at the sub-section inlet. Efficiency gk for rated conditions is determined from the correlations proposed in Ref. [17] depending on the turbine size and configuration. The efficiency of the first and last sub-sections are corrected for different operating conditions, taking into account the modified thermodynamic conditions of the fluid entering and exiting the turbine. Intermediate sub-sections are unaffected, due to fluidynamic similarity of the operating conditions. As for the condenser, operating conditions are strongly influenced by the steam mass flow rate at the turbine exit. This affects both the steam condensation temperature and the cooling water outlet temperature. 3.3. Heat recovery steam generator The HRSG is modeled for the design condition by setting the pinch point temperature difference DTpp, the approach temperature difference DTa and the pressure levels. For each section, the heat transfer can be written: q ¼ UA DT
ð2Þ
where U is the overall heat transfer coefficient, A is the heat exchange surface area and DT is the temperature difference. The heat transfer is dominated by the gas side convective resistance. As flow over the tubes is fully turbulent, the heat transfer coefficient can be found using the Nusselt number: Nu ¼ C Rea Prb
ð3Þ
Based on the energy and mass balance on each section of the HRSG, we can calculate the flow rates for each pressure level, the exchange surfaces of each section and the stack temperature. Once the surfaces are determined, the off design behavior can be studied. Heat exchange in off design conditions can be written: a b U Nu Re Pr ¼ ¼ ð4Þ U des Nudes Redes Prdes Substituting Re and Pr gives: x y z U M T p ¼ U des M des T des pdes
ð5Þ
The influence of M is much more pronounced than T and p, being the exponents y and z are negligible. 3.4. Model validation The above described model has been extensively validated against published experimental results since its first
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development. To show its capability in the specific field of the present study, it has been tested on some of the power plants that will form the baseline in the subsequent discussion. In Table 1, the calculated performance of two widely used gas turbine models are compared with published measurements [17], showing very close agreement both for a heavy duty unit (Siemens V94.2) and for an aeroderivative unit (GE LM6000). Table 2 follows, showing good agreement also in the case of combined cycle plants. They are a second generation, three pressure level plant (S107EA) without re-heat and a third generation plant (S109FA) fea-
Table 1 Comparison of calculated and simulated results for gas turbine units
GT model designation Pressure ratio Exhaust gas temperature (C) Exhaust gas mass flow (kg/s) Net output (MW) Net efficiency (%)
Model results
Ref. [17]
Model results
Ref. [17]
Siemens V94.2 11.1 540.4
Siemens V94.2 11.4 547.0
GE LM6000 29.4 450.0
GE LM6000 30.0 449.0
519.0
509.0
127.0
131.0
158.9 34.5
159.4 34.3
43.4 41.3
43.1 41.3
Table 2 Comparison of calculated and simulated results for combined cycle plants
CC model designation GT model designation GT output (MW) ST output (MW) CC net output (MW) CC net efficiency (%)
Model results
Ref. [17]
Model results
Ref. [17]
S107EA
S107EA
S109FA
S109FA
MS7001EA
MS7001EA
PG9351FA
PG9351FA
82.4 47.1 127.8
83.5 48.7 130.2
256.3 136.5 387.7
254.1 141.8 390.8
50.4
50.2
56.6
56.7
turing three pressure levels and reheat. The latter will be the one selected for repowering. The model has also proven able to track the off design behavior of a combined cycle. Fig. 2 shows how the published [19] heat rate vs. percentage of the base rating is not far from the model results marked by small circles. Here, the combined cycle is the GE S209E, featuring two MS9001 gas turbines coupled with a single steam turbine. Specifically, the model is capable of simulating precisely the favorable off design behavior achieved by IGV variation. 4. Results The analysis consisted in simulating the proposed repowering scheme using real data from present day power generating plants. Several gas turbine models have been tested to assess the feasibility of repowering, the power augmentation attainable and its influence on energy conversion efficiency, accounting for off design behavior. A preliminary economic analysis is also attempted, estimating the cost of electricity produced. 4.1. Design and part load performance of the baseline combined cycle The modular code has been applied to a NGCC plant type GE S109FA based on a single General Electric gas turbine type PG9351FA. The design performance of this plant is summarized in Table 3. Part load operation has been obtained by varying the compressor IGV angle from 0 to 30 in 5 increments. Further load reductions are obtained by decreasing the fuel mass introduced into the combustor, that is by reducing the combustor exit temperature from the design value in 50 C steps. Fig. 3 shows the performance calculated for the base configuration of the combined cycle. The part load efficiency diagram shows two well defined ranges. The first range, down to about 75% of rated power, is obtained through IGV control and is characterized by moderately decreasing efficiency. In this range, a mass flux reduction at the compressor inlet impairs the gas turbine efficiency but results in a steady increase in turbine exhaust temperature. Therefore, the efficiency loss in the gas turbine is largely recovered in the steam cycle. Further power reductions result in a decrease in turbine firing temperature. In this case, the exhaust temperature of the gas turbine decreases along with efficiency, making heat recovery unfeasible. 4.2. Performance of repowered combined cycle
Fig. 2. Combined cycle part load performance – manufacturer’s data [18] and model results for S209E plant.
Various types and numbers of gas turbines have been added to the baseline plant, as shown in Table 4. Four of these are heavy duty units, while the last is an aeroderivative turbine. In the latter case, three units have been used to accommodate the difference in power level. The most conspicuous difference between aeroderivative and heavy duty
R. Carapellucci, A. Milazzo / Energy Conversion and Management 48 (2007) 1590–1600 Table 3 Design performance of baseline combined cycle CC model designation Number and model of GT
GE S109FA 1 · PG9351FA
Gas turbine Pressure ratio First rotor temperature (C) Exhaust gas temperature (C) Exhaust gas mass flow (kg/s) Net output (MW) Net efficiency (%)
15.5 1310.7 611.1 625.1 256.3 37.4
Steam cycle HP steam pressure (bar) HP steam temperature (C) HP steam mass flow (kg/s) IP steam pressure (bar) IP steam temperature (C) IP steam mass flow (kg/s) LP steam pressure (bar) LP steam temperature (C) LP steam mass flow (kg/s) Condenser pressure (kPa)
125.1 565.6 71.9 28.0 321.2 14.0 4.2 202.4 8.8 5.1
Net CC output (MW) Net CC efficiency (%)
387.7 56.6
gas turbines is the exhaust temperature, which is reflected by the lower temperature and mass of steam available for injection into the original CC plant for the aeroderivative units. The power increase for the CC is correspondingly smaller. However, this difference is not so pronounced when considering the overall repowered plant performance,
as the three aeroderivative gas turbines contribute significantly to power augmentation. The maximum steam flow rate is set at 8–10% of the compressor inlet air flow to avoid compressor and turbine matching problems. The thermodynamic conditions of the steam injected into the CC combustor are related to the gas temperature at the added gas turbine (GT) exhaust and to the pressure ratio of the combined cycle GT. In order to ensure excess pressure for injection and mixing, the steam pressure has been fixed at 50% higher than the combustor inlet air pressure. As far as efficiency is concerned, the results obtained for the steam injected CC are fairly impressive, owing to the heat input from the added component. However, the most significant and promising results were obtained for the repowered plant as a whole. The efficiency of the baseline plant, already very high, is practically maintained, although the additional section itself is not so efficient. All the values compare favorably with the vast majority of present day power plants. The best results are achieved when the more efficient aeroderivative gas turbines are employed. The last two rows of Table 4 summarize most significantly the effect of repowering: additional power produced is very high, always more than half that generated by the original plant. Moreover, the energy conversion efficiency for the additional power does not differ substantially from that of a conventional NGCC, even if the added section is less complex and expensive.
P [MW] 200
250
300
P [MW] 350
400
150
200
250
300
350
400 58 56
550
54 500
52
TTE [˚C]
450 400
50
700
38
650
36
600
34
550
32
500 150
η CC [%]
MTE [kg/s]
600
30
200
250
300
P [MW]
350
400
150
200
250
300
P [MW]
Fig. 3. Part load performance of the baseline combined cycle.
350
400
ηGT [%]
150 650
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Table 4 Nominal performance of the repowered combined cycle Added gas turbine Number/manufacturer Model designation Pressure ratio Exhaust gas temperature (C) Exhaust gas mass flow (kg/s) Net output (MW) Net efficiency (%)
1/GE PG9171E 12.3 538.5 403.6 123.4 33.8
1/Siemens V94.2 11.1 540.4 519.0 158.9 34.5
1/ABB GT11N2 15.0 524.1 375.1 115.4 34.9
1/GE PG7221FA 15.0 589.5 417.7 159.0 35.9
3/GE LM6000 29.4 450.0 127.0 43.4 41.3
Combined cycle with steam injection Injected steam temperature (C) Injected steam mass flow (kg/s) GT pressure ratio GT exhaust gas mass flow (kg/s) HP steam pressure (bar) HP steam temperature (C) HP steam mass flow (kg/s) LP steam pressure (bar) LP steam temperature (C) LP steam mass flow (kg/s) Condenser pressure (kPa) Net output (MW) Net efficiency (%)
504.9 53.7 17.5 680.9 142.9 544.7 84.1 4.9 206.6 10.3 6.0 493.6 62.3
506.6 69.3 18.1 697.2 147.8 536.6 87.7 5.1 207.7 10.8 6.2 524.8 63.7
491.8 47.9 17.3 674.9 141.3 547.4 82.8 4.8 206.3 10.1 5.9 482.5 61.7
551.1 63.1 17.9 690.5 145.8 540.1 86.2 5.0 207.3 10.6 6.1 511.9 63.7
425.1 38.2 17.0 664.9 138.2 551.8 80.6 4.7 205.6 9.9 5.7 463.5 60.3
Integrated plant DPGT (MW) DPCC (MW) Net output (MW) Net efficiency (%)
123.5 105.9 617.0 53.3
159.0 137.1 683.8 53.2
115.4 94.8 597.8 53.7
159.0 124.2 670.9 53.8
130.3 75.8 593.8 54.8
Marginal output (MW) Marginal efficiency (%)
229.4 48.5
296.1 49.3
210.2 49.1
283.2 50.4
206.1 51.7
Worthy of note is the fact that with the addition of just one GE LM6000 turbine, the power increase is obviously fairly small (68.5 MW), but the additional power is generated with a very high efficiency (51.8%), comparable with that obtained by adding three GE LM6000s. 4.2.1. Part load operation More interestingly, the proposed scheme offers a variety of control strategies and, hence, the possibility of achieving good part load behavior. If both the existing and the added gas turbines are equipped with adjustable IGVs, one can decide the sequence of operation of the two IGV sets, even moving them simultaneously. Various possibilities have been simulated on the model, and it has been found that a good compromise between efficiency and simplicity is the following: (a) compressor IGV angle of added gas turbine is changed from 0 to 30 in 5 steps; (b) compressor IGV angle of repowered CC gas turbine is changed from 0 to 30 in 5 steps; (c) fuel mass introduced into the combustor of the added gas turbine is reduced, hence reducing combustor exit temperature (from design value by 50 C). As shown in Fig. 4, if repowering is accomplished by the addition of a single gas turbine, the power control sequence can be readily identified. Given the high power required, a
heavy duty gas turbine is installed and the new HRSG produces a steam flow close to the maximum manageable by the combustor of the existing turbine (about 10% of the compressor intake air flow). By varying the IGV angle of the new gas turbine and then that of the existing CC gas turbine, the power of the integrated plant can be reduced to about 75% of the rated value. Further power reduction requires lower fuel–air mass ratio. This clearly penalizes efficiency, but if instead,the additional gas turbine is completely shut down, the combined cycle returns to its original design point. Aeroderivative turbines maximize flexibility (Fig. 5). In this case, more than one GT/HRSG unit has to be installed to exploit the full steam reception capacity of the existing gas turbine. This provides another degree of freedom, namely the number of GTs operating at any one time. Hence, the maximum variations indicated above are attained only for the IGVs of the new turbines, while those of the existing GT are operated over a limited range (up to 5 or 10) and a reduction of combustor exit temperature is unnecessary. Lower power outputs are obtained, at higher efficiency, by shutting down one of the added GTs and operating the others at full load. This clearly emerges in Fig. 5 where, moving from right to left, the upper curve shows how the additional power produced by the new gas turbine decreases with IGV angle (0, 5, . . . , 30). For further power reductions, one also has to move the IGVs of the existing turbine, but above 5, a second curve
R. Carapellucci, A. Milazzo / Energy Conversion and Management 48 (2007) 1590–1600
P [MW] 400 150
450
500
550
600
650
ΔP [MW]
100 50 CC
0
GT -50 11
MSI/MAIR[%]
9 8 7 6 450
500
550
600
650
P [MW] Fig. 4. Part load strategy of the combined cycle GE S109FA repowered using steam injection by a heavy duty gas turbine (GE PG9171E).
is available for the same plant working with just two extra turbines. Repeating the same procedure for the second gas turbine, the plant can be controlled over a large power P [MW] 400 150
450
500
550
– the simple cycle gas turbine; – the gas turbine, the HRSG + piping + auxiliary equipment, plus the steam turbine with condenser and alternator for the existing combined cycle; – the gas turbine plus the HRSG + piping + auxiliary equipment for the repowering facility. The capital costs considered in the economic analysis are summarized in Table 5, which also shows, in addition to specific cost, the base size and scaling factor. No scaling factor is given for GTs, as the specific cost ($/kW) is dependent upon the technology and manufacturer. The following data for capital costs of gas turbines used for utility repowering have been taken from the literature [20,21] and web sites [22,23]: 195 $/kW for GE PG9171E,
50
CC
0
The aim of this section is to assess the economic feasibility of the repowering facility itself, irrespective of the NGCC taken as baseline. Therefore, the results will be expressed in terms of incremental variables, i.e. incremental power, incremental capital costs and incremental operating costs. For comparative purposes, the cost of electricity produced (CoE) is evaluated also for the baseline combined cycle and for the same gas turbine used for repowering operated in a simple cycle. The capital costs for these three situations are given by:
600
100
ΔP [MW]
range while maintaining high performance. The percentage of injected steam per intake air flow is lower for the aeroderivative turbines than for the heavy duty ones. Part load performance of the repowered plant is summarized in Fig. 6, where design conditions are taken as reference values. The two cases of single heavy duty GT incur a heavier efficiency penalty, maintaining high performance only within a 10% power reduction. On the contrary, the option with three aeroderivative GTs shows increasing efficiency, whereas gradually shutting down the new turbines restores the plant to its original configuration. 4.3. Economic analysis
10
400
1597
GT -50
104
ηRCC [% of design]
MSI/MAIR [%]
8 6 4 2 0 400
450
500
550
600
P [MW] Fig. 5. Part load strategy of the combined cycle GE S109FA repowered using steam injection by three aeroderivative gas turbines (GE LM6000).
1 GT
102 100 98 GE P G9171E GE P G7221FA
96
GE LM 6000
94 60
70
80
90
100
PRCC [% of design] Fig. 6. Part load performance of the combined cycle GE S109FA repowered using steam injection by gas turbines.
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Table 5 Capital costs and scale parameters adopted for the economic analysis
Steam turbine + generator + condenser HRSG + piping + auxiliary equipment Gas turbine
Scaling parameter
Base specific cost
Base size
Scaling factor
Thermal power Electric power Electric power
350 ($/kWe) 90 ($/kWt) 200–300 ($/kWe)
200 (MWe) 630 (MWt) 200–300 ($/kWe)
2/3 2/3 1
200 $/kW for Siemens V94.2, 225 $/kW for ABB GT11N2, 210 $/kW for GE PG7221FA and 295 $/kW for GE LM6000. Table 6 summarizes the assumptions made in the economic analysis of the repowering process. Table 7 presents the results of the economic analysis, showing the different contributions to the total capital requirement and to the CoE (capital recovery, O&M, fuel). For comparison, the cost of electricity produced by reference plants has also been estimated: the CoE of the baseline combined cycle is 35.7 mill$/kW h against a CoE of 41.7–46.7 mill$/kW h for simple cycle GTs. The lower cost can be achieved with an aeroderivative GT (GE LM6000) and the higher cost with a low efficiency heavy duty GT (GE PG9171E). As Table 7 shows, the CoE of the repowered cycle is very close to that of the baseline combined cycle. Specifically, the CoEs are slightly lower for heavy duty GTs and a little higher for aeroderivative GTs. It would appear that the lower fuel costs of the highly efficient aeroderivative turbines do not offset their higher capital recovery cost. In all cases, the reduction in the CoE with respect to simple cycle GTs is significant. This clearly emerges from Fig. 7, which shows the histogram for the various contributions to the CoE for simple cycle GTs and for the same turbines used in a repowering configuration. Note that the fuel related CoE is reduced dramatically, owing to the increased energy efficiency, whereas the capital recovery and maintenance show only modest increments.
Table 6 Assumptions for the economic analysis of the repowering option Plant lifetime (yr) Yearly operating hours (h/yr) Fuel cost ($/GJ) Discount rate (%) Annual cost escalation rate (%) Construction time (yr) Fixed O&M ($/kW yr) Variable O&M (mill$/kW h) Insurance costs (%) Balance of the plant (%) Cost of engineering (%) Contingencies (%) Pre-production cost (%)
25 7000 3.3 10 1.5 2 12.0 0.5 1 12 8 5 2
This analysis indicates a higher CoE for the aeroderivative repowering option on account of the higher capital requirement. This is easily explained by the higher specific cost of aeroderivative GTs and the negative scaling effect of splitting the HRSG into three units. However, the above considerations apply to full load operation. It should be borne in mind that the option envisaging three aeroderivative gas turbines performs much better in part load operation (Fig. 6), as the incremental efficiency, i.e. the incremental power to incremental fuel consumption ratio, indicates (Figs. 8 and 9). Clearly, for a single heavy duty GT, the incremental efficiency decreases steadily and significantly (Fig. 8), while for the option with three aeroderivative GTs, it remains very high and practically constant up
Table 7 Cost of electricity for the five gas turbines used for repowering Gas turbine number and manufacturer Gas turbine model designation Gas turbine cost (M$) HRSG + piping + auxiliary equip. cost (M$) Total installed equipment cost (M$) Balance of the plant (M$) Cost of engineering (M$) Contingencies (M$) Overnight capital cost (M$) Interest during construction (M$) Pre-production cost (M$) Total capital requirement (M$) Specific capital cost ($/kW) Marginal power output (MW) Marginal efficiency (%) COE due to capital recovery (mill$/kW h) COE due to O&M (mill$/kW h) COE due to fuel (mill$/kW h) Total COE (mill$/kW h)
1 and GE PG9171E 24.07 29.36 53.43 2.89 4.27 2.67 63.26 1.85 1.27 66.38 289.40 229.36 48.52 4.55 2.84 27.90 35.29
1 and Siemens V94.2 31.79 34.04 65.83 3.81 5.27 3.29 78.20 2.29 1.56 82.05 277.14 296.07 49.34 4.36 2.82 27.44 34.62
1 and ABB GT11N2 25.96 27.13 53.09 3.11 4.25 2.65 63.11 1.84 1.26 66.21 315.06 210.15 49.11 4.96 2.89 27.56 35.41
1 and GE PG7221FA 33.39 32.59 65.99 4.01 5.28 3.30 78.57 2.30 1.57 82.44 291.08 283.21 50.39 4.58 2.85 26.86 34.29
3 and GE LM6000 38.42 35.14 73.56 4.61 5.88 3.68 87.73 2.56 1.75 92.05 446.70 206.07 51.67 7.03 3.10 26.20 36.33
R. Carapellucci, A. Milazzo / Energy Conversion and Management 48 (2007) 1590–1600
Fuel O&M
60
21 G
G
EP
G
EL
M
72
T1 G AB
B
s en Si em
FA
2 1N
2 V9
4.
71 91 G EP G
00
Capital
E
COE [mill$/kWh]
50 45 40 35 30 25 20 15 10 5 0
Fig. 7. Comparison of CoE for the five gas turbines operated in simple cycle (1st bar) and repowering facility (2nd bar).
50 45
1599
bine, raising both the GT power output and its exhaust temperature and, as a result, also raising the steam for the bottoming steam cycle. In this way, the CC power can be increased by well over 50%, with a decrease in efficiency of between 3% and 6%, depending on the specific additional GT used. This result has been achieved in spite of the relative simplicity of the added components, whose efficiency as stand alone units would be very low. Moreover, integration yields outstanding results in terms of part load operation, especially with the addition of a number of small aeroderivative gas turbines. In this way, by acting on the IGVs and sequentially shutting down the added GTs, plant power can be varied over an extensive range, without paying an excessive efficiency penalty. The CoE relating to the repowered facility, evaluated on the basis of literature data, compares favorably with and can actually be lower than that of the reference plant.
ηI [%]
40
References
35 30 25 20 400
450
500
550
600
650
P[MW] Fig. 8. Incremental efficiency of repowering vs. power for a single heavy duty gas turbine (GE PG9171E).
55
ηI [%]
52 49 46 43 40 400
450
500
550
600
P[MW] Fig. 9. Incremental efficiency of repowering vs. power for three aeroderivative gas turbines (GE LM6000).
to about 75% of rated power. Hence, the benefits of repowering with heavy duty GTs may well be offset by the greater operating flexibility of the aeroderivative option. 5. Conclusions A repowering scheme for combined cycle power plants has been proposed, featuring the addition of a gas turbine and a one pressure level HRSG. The latter feeds the output steam to the combustion chamber of the existing gas tur-
[1] Di Pasquale L, Torre A, Foglino E, Macchia C, Nicol W. Converting conventional plants to combined cycles: ENEL, Ansaldo and Siemens experience, POWER-GEN Europe, April 2002. [2] Heyena G, Kalitventze B. A comparison of advanced thermal cycles suitable for upgrading existing power plant. Appl Thermal Eng 1999;19:227–37. [3] Carapellucci R, Milazzo A. Scheme of power enhancement for combined cycle plants through steam injection. International Patent (PCT) Application No. PCT/IT2006/000332, issued at UIBM, Rome, 9 May, 2006. [4] GE Power Systems, Gas turbine and combined cycle products, March 2003. [5] Siemens power generation: combined cycle plant ratings, 2006, http:// www.pg.siemens.com/en/plantrating/index.cfm. [6] Ansaldo Energia, Combined cycle power plants on EPC contracts in Italy and Abroad, 2003. [7] Edison s.p.a., 2002 Environmental and safety report [in Italian]. [8] Pilavachi PA. Power generation with gas turbine systems and combined heat and power. Appl Thermal Eng 2000;20:1421–9. [9] Chase DL, Kehoe PT. GE combined-cycle product line and performance, GER-3574G, GE Power Systems, Schenectady, NY, November 2000. [10] Pelster S, Favrat D, von Spakovsky MR. The thermoeconomic and environomic modeling and optimization of the synthesis, design, and operation of combined cycles with advanced options. J Eng Gas Turbines Power 2001;123:717. [11] Smith RW, Polukort P, Maslak CE, Jones CM, Gardiner BD. Advanced technology combined cycles, GER-3936A. GE Power Systems, Schenectady, NY, May 2001. [12] Boss M. Steam turbines for STAGTM combined-cycle power systems, GER-3582E, GE Power Systems, Schenectady, NY, September 1999. [13] Johnston JR. Performance and reliability improvements for heavyduty gas turbines, GER-3571H, GE Power Systems, Schenectady, NY, November 2000. [14] Franco A, Casarosa C. On some perspectives for increasing the efficiency of combined cycle power plants. Appl Thermal Eng 2002;22:1501–18. [15] Camporeale SM, Fortunato EB. Performance of a mixed gas–steam cycle power plant obtained upgrading an aero-derivative gas turbine. Energy Convers Manage 1998;39(16–18):1683–92. [16] Carapellucci R, Cau G. A modular system for performance calculation of energy systems. In: Proceedings of the 6th national congress on combined cycles: technical and economic perspective, Genova; 1992. p. 237–51 [in Italian].
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[17] Spencer RC, Cotton KC, Cannon CN. A method for predicting the performance of steam turbine-generators, GER-2007C, General Electric Co., 1974. [18] Brezonick MJ. (editor), Diesel and gas turbine worldwide catalog, Diesel and Gas Turbine Publications, vol. 68, Waukesha, WI, USA, 2003. [19] Chase DL. Combined-cycle development evolution and future, GER-4206, GE Power Systems, Schenectady, NY, April 2001.
[20] Northwest Power Planning Council, Natural gas combined-cycle gas turbine power plants. new resource characterization for the Fifth Power Plan, August 8, 2002. [21] US DOE. Market-based advanced coal power systems. Final Report, DOE/FE-040, May 1999. [22] Nye Thermodynamics. Turbine projects and custom components, http://gas-turbines.com/, 2006. [23] Power Technology. The web site for the power industry, http:// www.power-technology.com/, 2006.
Repowering combined cycle power plants by a modified STIG configuration Roberto Carapellucci *, Adriano Milazzo Dipartimento di Ingegneria Meccanica, Energetica e Gestionale, Faculty of Engineering, University of L’Aquila, Monteluco di Roio, 67040 L’Aquila, Italy Received 27 July 2004; received in revised form 18 May 2006; accepted 26 November 2006 Available online 30 January 2007
Abstract An innovative repowering concept for combined cycle power plants is presented. The design concept consists in adding one or more gas turbines to the combined cycle, integrated by steam injection into the existing gas turbine. The steam is produced in a simplified heat recovery steam generator fed by the additional turbine’s exhaust gas. The scheme is quite simple and easy to adapt to various types of combined cycles. The efficiency of the repowered plant compares favorably with that of the original combined cycle and far surpasses that obtained by simply adding the gas turbine with no integration. Furthermore, the additional gas turbine enhances the plant operating flexibility as any power output intermediate between the original and the repowered capacity can be readily attained with no significant efficiency penalty. A thermodynamic and economic evaluation of the system feasibility is presented. 2006 Elsevier Ltd. All rights reserved. Keywords: Repowering; Combined cycles; Gas turbines; Steam injection
1. Introduction Almost all industrialized countries are now facing some degree of electric power shortage. The major problem is probably the lack of suitable sites for building new power plants of whatever type or size. Moreover, increasing environmental awareness has resulted in more demanding requirements in terms of preliminary analysis, prolonging and complicating the plant commissioning process. This is especially true of those countries, like most European ones, with high population density and a large number of conservation sites of historic interest or natural beauty, where there is increasing public opposition to new plants, even for low emitting, natural gas fuelled, combined cycles (NGCC). All these problems have led many utilities to consider extending the life of existing plants by repowering [1,2]. Basically, these interventions have been done on oil fired
*
Corresponding author. Tel.: +39 0862434320; fax: +39 0862434303. E-mail address: [email protected] (R. Carapellucci).
0196-8904/$ - see front matter 2006 Elsevier Ltd. All rights reserved. doi:10.1016/j.enconman.2006.11.024
steam plants by addition of a natural gas fired turbine. This reduces specific emissions of the existing steam plant while maintaining or even slightly improving its efficiency. As a rule, a repowered plant can be expected to give a lower cost per kW h produced as well as per kW installed. Repowering of steam plants can be achieved in two ways: feed water repowering and boiler repowering. The first option uses heat from the turbine exhaust to raise the feed water temperature instead of bleeding steam. This means that increased steam flow has to be managed by the low pressure section of the original steam turbine, requiring either extensive modification of the steam turbine or impairing the repowered plant performance. The other option, boiler repowering, entails major steam generator redesign. As gas turbine exhaust is used as oxidant for combustion, the combustion air preheater is no longer required. This increases stack temperature, thus limiting efficiency improvements. In spite of the above limitations, repowering has been performed on various steam plants. The object of the work presented herein is to explore the possibility of also repowering combined cycle power plants. To this aim, the steam generated by an additional gas tur-
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Nomenclature Symbols A heat transfer area a, b exponents in Eq. (3) C constant in Eq. (3) h specific enthalpy M mass flow Nu Nusselt number p pressure P power Pr Prandtl number q heat flux Re Reynolds number T temperature U overall heat transfer coefficient v specific volume x, y, z exponents in Eq. (5) Acronyms CC combined cycle CoE cost of electricity GT gas turbine HRSG heat recovery steam generator IGV inlet guide vane NGCC natural gas combined cycle
bine is injected in the existing combustion chamber. The performance of the proposed system has been evaluated for various configurations at full and part load operation. The results are promising in terms of increased power and energy efficiency and also demonstrate the additional electricity generated is cost competitive. An application for a PCT international patent has been issued for the proposed scheme [3]. 2. Repowering of combined cycle power plants Many utilities in Europe installed NGCC plants in the 1990s, and because of their high efficiency and low emissions [4–7], these plants are increasing their market share. The high residual value and long life expectancy of these plants poses the question whether their output can in some way be increased without compromising efficiency. To answer this question, one has to consider the characteristics of existing plants so as to identify those that may be advantageously improved. For this purpose, it may be useful to briefly review the evolution of NGCC plants and group them into homogeneous subsets. 2.1. Existing CC plants According to Ref. [8], up to now, there have been four generations of combined cycle (CC) plants. The early versions were basically repowered steam plants with fired
SCR STIG O&M
selective catalytic reactor steam injected gas turbine operation and maintenance
Greek letter g efficiency Subscripts a approach des design condition e electrical i inlet I incremental (referred to efficiency) is isentropic o outlet pp pinch point RCC repowered combined cycle SI injected steam t thermal TE turbine exit Superscript reference value *
steam generator. These steam generators had bare tubes, heat exchange being ensured by the high process temperatures. They had a single or two pressure levels with no reheating. The last of these first generation plants were installed as late as 1968. In 1958, with the advent of an economically feasible technology for welding continuous fins to tubes, the second generation of combined cycles began to take shape. Improved heat exchange made it possible to recover heat from the gas turbine exhaust, which was then used for feed water heating. The first applications in the 1960s were for power and heat generation. By the 1970s and 1980s, the technology had matured in the utility sector for mid-range loads. Two or three pressure level steam generators were employed but still with no reheating. Nitrogen oxide control techniques were also introduced in this period, basically by water or steam injection in the combustion chamber. These second generation plants were still being installed at the end of the 20th Century. The gas turbine of these plants was not specifically designed for use in a CC configuration. Therefore, it was usually characterized by a rather high compression ratio in order to achieve relatively good efficiency in an open cycle configuration. This is actually a drawback for CCs, as it means a lower exhaust temperature and, hence, less energy available for the steam cycle. As soon as CCs had established a primary foothold in the power industry, the need arose to design a gas turbine
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specifically for use in a CC with an optimized compression ratio. On the other hand, gas turbines have seen a steady increase in firing temperature due to extensive materials research and especially to refrigeration. A high firing temperature is particularly important for CCs, as it raises the exhaust temperature for a given compression ratio. These two factors prompted the development of a third generation of CCs. The first plants entered into commercial operation in 1990. The heat recovery steam generator (HRSG) usually has three pressure levels and reheat [9,10]. NOx emission control is mandatory, and the plants are equipped with dry low NOx combustion systems for use with natural gas, while a selective catalytic reactor (SCR) is also required to comply with emission regulations. The latest advance in CC technology consists in the introduction of closed loop refrigeration of the first stage nozzle, the fourth generation, currently being introduced into the market. These plants are designed to reach a 60% efficiency target [11,12], as results of the further increase in firing temperature, the reduction of temperature drop across the first stage nozzle and the elimination or reduction of the loss of compressed air achieved by open loop refrigeration. Many third generation plants have recently been installed. These plants have high power output, high efficiency, low emissions and a fairly long life expectancy, as opposed to the older plants whose remaining useful life does not justify the cost of repowering. Therefore, the proposed concept focuses on a typical plant installed in the last decade. Obviously, this is not to be intended as a limitation to the concept: repowering can be done whenever technically and economically feasible, evaluating the cost and energy efficiency of the additional power in the specific case at hand [13,14]. 2.2. The repowering concept The proposed repowering scheme is based on the addition of a gas turbine and of a HRSG to a baseline CC. These new components are integrated within the existing
G.T.
plant by injecting the steam produced by the additional HRSG into the existing gas turbine. In this way, the original turbine is transformed into a STIG (steam injected gas turbine), thereby increasing power. CC power augmentation is, thus, the sum of the power generated by the new gas turbine and the additional power of the original plant, comprising both the gas turbine and steam cycle. Obviously only a limited amount of steam can be injected into the original gas turbine [13]. The calculations that follow are done considering a maximum of 10%. Even so, because of the thermodynamic properties of steam, a substantial power increase can be achieved. The exhaust flow through the existing HRSG is also increased, thus benefiting the steam cycle [14,15]. The pressure required to inject this steam into the turbine is relatively low compared to that usually employed in steam turbines. So the HRSG can be of very simple design, with a single pressure level and a low pinch point, thus reducing the stack temperature and increasing heat recovery. The proposed scheme is shown in Fig. 1. As can be seen, the steam line feeding the original gas turbine connects the plant to the added section, that comprises a gas turbine and a heat recovery steam generator. However, many other subsystems may be shared to reduce the repowering cost such as, for examples, flue gas treatment, electric power conditioning etc. One major addition to the plant is the water flow entering the new HRSG, which is inevitably lost at the stack. This can be a major drawback in certain situations and limits the applicability of the present scheme to sites with large fresh water availability, though the specific water requirements are fairly low, as will be shown later. If a low temperature thermal load is available nearby the power plant, the steam in the exhaust could eventually be condensed and the water could be recovered. Obviously, the very large size and the very low temperature level of such a heat sink restricts this option to quite uncommon cases, and its feasibility has to be carefully evaluated. Another significant feature of the proposed repowering scheme is its operational flexibility. Because of the inherent
G.T.
Added Section
L.P. H.P. I.P. Existing Combined Cycle Power Plant Fig. 1. Scheme of the repowered plant.
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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. At full load, the efficiency does not differ substantially, as will be demonstrated by the thermodynamic simulation. Fitting both the new and original gas turbines with variable intake guide vanes (IGVs) should provide a fairly wide operating range with efficiency close to rated. 3. System modelling The scheme outlined above has been numerically studied using a modular simulation code already adopted by the authors elsewhere [16]. The code is based on fundamental thermodynamic relations, including real gas behavior and pressure losses. Using this general purpose code, it is possible to simulate practically any power plant component in design conditions, including gas and steam turbines, steam generators, condensers, heat exchangers or even fuel cells. Each component is modeled by mass and energy balances. For the sake of generality, all components are represented as modules, characterized by a set of indices describing the type of module and its operating conditions. A vector provides the list of the composing modules. Each module has a number of nodes, characterized by other indices: they indicate the position of the node in the module and its absolute position in the overall plant scheme, as well as the type of node, i.e. mass, mechanical energy or heat exchange node. In this way, the plant configuration can be described by the match between the absolute and relative position indices. In this work, the original code has been extended to off design operation. The description will cover only those components actually contained in the proposed plant. 3.1. Gas turbine unit Each gas turbine is modeled as a single module. The operating condition is determined by matching the compressor and turbine pressure and flow rate. Once the design point is found, the efficiency can be calculated by mean line analysis. Turbine refrigeration is taken into account by including a cooling transformation prior to and following the adiabatic expansion. Concerning the combustors, the code calculates the thermodynamic properties of the combustion products in chemical and thermodynamic equilibrium. Part load conditions are obtained by varying the IGVs at the compressor intake and, for greater departure from design conditions, the fuel–air mass ratio in the combustor. 3.2. Steam cycle The steam turbines are divided into sub-units by the sections, which introduce discontinuities into the expansion, that is bleeding or steam injection. The thermodynamic conditions at the exit of each sub-section k is determined
1593
pffiffiffiffiffiffiffi by setting the reduced flow rate M v=p constant irrespective of operating conditions and solving the system: ( pffiffiffiffiffiffiffiffiffiffiffi pffiffiffiffiffiffiffiffiffiffiffi ðM vo =po Þk ¼ ðM vo =po Þk ð1Þ ðho hi Þk ¼ gk ðho;is hi Þk for given rated conditions, mass flow rate M and actual conditions at the sub-section inlet. Efficiency gk for rated conditions is determined from the correlations proposed in Ref. [17] depending on the turbine size and configuration. The efficiency of the first and last sub-sections are corrected for different operating conditions, taking into account the modified thermodynamic conditions of the fluid entering and exiting the turbine. Intermediate sub-sections are unaffected, due to fluidynamic similarity of the operating conditions. As for the condenser, operating conditions are strongly influenced by the steam mass flow rate at the turbine exit. This affects both the steam condensation temperature and the cooling water outlet temperature. 3.3. Heat recovery steam generator The HRSG is modeled for the design condition by setting the pinch point temperature difference DTpp, the approach temperature difference DTa and the pressure levels. For each section, the heat transfer can be written: q ¼ UA DT
ð2Þ
where U is the overall heat transfer coefficient, A is the heat exchange surface area and DT is the temperature difference. The heat transfer is dominated by the gas side convective resistance. As flow over the tubes is fully turbulent, the heat transfer coefficient can be found using the Nusselt number: Nu ¼ C Rea Prb
ð3Þ
Based on the energy and mass balance on each section of the HRSG, we can calculate the flow rates for each pressure level, the exchange surfaces of each section and the stack temperature. Once the surfaces are determined, the off design behavior can be studied. Heat exchange in off design conditions can be written: a b U Nu Re Pr ¼ ¼ ð4Þ U des Nudes Redes Prdes Substituting Re and Pr gives: x y z U M T p ¼ U des M des T des pdes
ð5Þ
The influence of M is much more pronounced than T and p, being the exponents y and z are negligible. 3.4. Model validation The above described model has been extensively validated against published experimental results since its first
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development. To show its capability in the specific field of the present study, it has been tested on some of the power plants that will form the baseline in the subsequent discussion. In Table 1, the calculated performance of two widely used gas turbine models are compared with published measurements [17], showing very close agreement both for a heavy duty unit (Siemens V94.2) and for an aeroderivative unit (GE LM6000). Table 2 follows, showing good agreement also in the case of combined cycle plants. They are a second generation, three pressure level plant (S107EA) without re-heat and a third generation plant (S109FA) fea-
Table 1 Comparison of calculated and simulated results for gas turbine units
GT model designation Pressure ratio Exhaust gas temperature (C) Exhaust gas mass flow (kg/s) Net output (MW) Net efficiency (%)
Model results
Ref. [17]
Model results
Ref. [17]
Siemens V94.2 11.1 540.4
Siemens V94.2 11.4 547.0
GE LM6000 29.4 450.0
GE LM6000 30.0 449.0
519.0
509.0
127.0
131.0
158.9 34.5
159.4 34.3
43.4 41.3
43.1 41.3
Table 2 Comparison of calculated and simulated results for combined cycle plants
CC model designation GT model designation GT output (MW) ST output (MW) CC net output (MW) CC net efficiency (%)
Model results
Ref. [17]
Model results
Ref. [17]
S107EA
S107EA
S109FA
S109FA
MS7001EA
MS7001EA
PG9351FA
PG9351FA
82.4 47.1 127.8
83.5 48.7 130.2
256.3 136.5 387.7
254.1 141.8 390.8
50.4
50.2
56.6
56.7
turing three pressure levels and reheat. The latter will be the one selected for repowering. The model has also proven able to track the off design behavior of a combined cycle. Fig. 2 shows how the published [19] heat rate vs. percentage of the base rating is not far from the model results marked by small circles. Here, the combined cycle is the GE S209E, featuring two MS9001 gas turbines coupled with a single steam turbine. Specifically, the model is capable of simulating precisely the favorable off design behavior achieved by IGV variation. 4. Results The analysis consisted in simulating the proposed repowering scheme using real data from present day power generating plants. Several gas turbine models have been tested to assess the feasibility of repowering, the power augmentation attainable and its influence on energy conversion efficiency, accounting for off design behavior. A preliminary economic analysis is also attempted, estimating the cost of electricity produced. 4.1. Design and part load performance of the baseline combined cycle The modular code has been applied to a NGCC plant type GE S109FA based on a single General Electric gas turbine type PG9351FA. The design performance of this plant is summarized in Table 3. Part load operation has been obtained by varying the compressor IGV angle from 0 to 30 in 5 increments. Further load reductions are obtained by decreasing the fuel mass introduced into the combustor, that is by reducing the combustor exit temperature from the design value in 50 C steps. Fig. 3 shows the performance calculated for the base configuration of the combined cycle. The part load efficiency diagram shows two well defined ranges. The first range, down to about 75% of rated power, is obtained through IGV control and is characterized by moderately decreasing efficiency. In this range, a mass flux reduction at the compressor inlet impairs the gas turbine efficiency but results in a steady increase in turbine exhaust temperature. Therefore, the efficiency loss in the gas turbine is largely recovered in the steam cycle. Further power reductions result in a decrease in turbine firing temperature. In this case, the exhaust temperature of the gas turbine decreases along with efficiency, making heat recovery unfeasible. 4.2. Performance of repowered combined cycle
Fig. 2. Combined cycle part load performance – manufacturer’s data [18] and model results for S209E plant.
Various types and numbers of gas turbines have been added to the baseline plant, as shown in Table 4. Four of these are heavy duty units, while the last is an aeroderivative turbine. In the latter case, three units have been used to accommodate the difference in power level. The most conspicuous difference between aeroderivative and heavy duty
R. Carapellucci, A. Milazzo / Energy Conversion and Management 48 (2007) 1590–1600 Table 3 Design performance of baseline combined cycle CC model designation Number and model of GT
GE S109FA 1 · PG9351FA
Gas turbine Pressure ratio First rotor temperature (C) Exhaust gas temperature (C) Exhaust gas mass flow (kg/s) Net output (MW) Net efficiency (%)
15.5 1310.7 611.1 625.1 256.3 37.4
Steam cycle HP steam pressure (bar) HP steam temperature (C) HP steam mass flow (kg/s) IP steam pressure (bar) IP steam temperature (C) IP steam mass flow (kg/s) LP steam pressure (bar) LP steam temperature (C) LP steam mass flow (kg/s) Condenser pressure (kPa)
125.1 565.6 71.9 28.0 321.2 14.0 4.2 202.4 8.8 5.1
Net CC output (MW) Net CC efficiency (%)
387.7 56.6
gas turbines is the exhaust temperature, which is reflected by the lower temperature and mass of steam available for injection into the original CC plant for the aeroderivative units. The power increase for the CC is correspondingly smaller. However, this difference is not so pronounced when considering the overall repowered plant performance,
as the three aeroderivative gas turbines contribute significantly to power augmentation. The maximum steam flow rate is set at 8–10% of the compressor inlet air flow to avoid compressor and turbine matching problems. The thermodynamic conditions of the steam injected into the CC combustor are related to the gas temperature at the added gas turbine (GT) exhaust and to the pressure ratio of the combined cycle GT. In order to ensure excess pressure for injection and mixing, the steam pressure has been fixed at 50% higher than the combustor inlet air pressure. As far as efficiency is concerned, the results obtained for the steam injected CC are fairly impressive, owing to the heat input from the added component. However, the most significant and promising results were obtained for the repowered plant as a whole. The efficiency of the baseline plant, already very high, is practically maintained, although the additional section itself is not so efficient. All the values compare favorably with the vast majority of present day power plants. The best results are achieved when the more efficient aeroderivative gas turbines are employed. The last two rows of Table 4 summarize most significantly the effect of repowering: additional power produced is very high, always more than half that generated by the original plant. Moreover, the energy conversion efficiency for the additional power does not differ substantially from that of a conventional NGCC, even if the added section is less complex and expensive.
P [MW] 200
250
300
P [MW] 350
400
150
200
250
300
350
400 58 56
550
54 500
52
TTE [˚C]
450 400
50
700
38
650
36
600
34
550
32
500 150
η CC [%]
MTE [kg/s]
600
30
200
250
300
P [MW]
350
400
150
200
250
300
P [MW]
Fig. 3. Part load performance of the baseline combined cycle.
350
400
ηGT [%]
150 650
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Table 4 Nominal performance of the repowered combined cycle Added gas turbine Number/manufacturer Model designation Pressure ratio Exhaust gas temperature (C) Exhaust gas mass flow (kg/s) Net output (MW) Net efficiency (%)
1/GE PG9171E 12.3 538.5 403.6 123.4 33.8
1/Siemens V94.2 11.1 540.4 519.0 158.9 34.5
1/ABB GT11N2 15.0 524.1 375.1 115.4 34.9
1/GE PG7221FA 15.0 589.5 417.7 159.0 35.9
3/GE LM6000 29.4 450.0 127.0 43.4 41.3
Combined cycle with steam injection Injected steam temperature (C) Injected steam mass flow (kg/s) GT pressure ratio GT exhaust gas mass flow (kg/s) HP steam pressure (bar) HP steam temperature (C) HP steam mass flow (kg/s) LP steam pressure (bar) LP steam temperature (C) LP steam mass flow (kg/s) Condenser pressure (kPa) Net output (MW) Net efficiency (%)
504.9 53.7 17.5 680.9 142.9 544.7 84.1 4.9 206.6 10.3 6.0 493.6 62.3
506.6 69.3 18.1 697.2 147.8 536.6 87.7 5.1 207.7 10.8 6.2 524.8 63.7
491.8 47.9 17.3 674.9 141.3 547.4 82.8 4.8 206.3 10.1 5.9 482.5 61.7
551.1 63.1 17.9 690.5 145.8 540.1 86.2 5.0 207.3 10.6 6.1 511.9 63.7
425.1 38.2 17.0 664.9 138.2 551.8 80.6 4.7 205.6 9.9 5.7 463.5 60.3
Integrated plant DPGT (MW) DPCC (MW) Net output (MW) Net efficiency (%)
123.5 105.9 617.0 53.3
159.0 137.1 683.8 53.2
115.4 94.8 597.8 53.7
159.0 124.2 670.9 53.8
130.3 75.8 593.8 54.8
Marginal output (MW) Marginal efficiency (%)
229.4 48.5
296.1 49.3
210.2 49.1
283.2 50.4
206.1 51.7
Worthy of note is the fact that with the addition of just one GE LM6000 turbine, the power increase is obviously fairly small (68.5 MW), but the additional power is generated with a very high efficiency (51.8%), comparable with that obtained by adding three GE LM6000s. 4.2.1. Part load operation More interestingly, the proposed scheme offers a variety of control strategies and, hence, the possibility of achieving good part load behavior. If both the existing and the added gas turbines are equipped with adjustable IGVs, one can decide the sequence of operation of the two IGV sets, even moving them simultaneously. Various possibilities have been simulated on the model, and it has been found that a good compromise between efficiency and simplicity is the following: (a) compressor IGV angle of added gas turbine is changed from 0 to 30 in 5 steps; (b) compressor IGV angle of repowered CC gas turbine is changed from 0 to 30 in 5 steps; (c) fuel mass introduced into the combustor of the added gas turbine is reduced, hence reducing combustor exit temperature (from design value by 50 C). As shown in Fig. 4, if repowering is accomplished by the addition of a single gas turbine, the power control sequence can be readily identified. Given the high power required, a
heavy duty gas turbine is installed and the new HRSG produces a steam flow close to the maximum manageable by the combustor of the existing turbine (about 10% of the compressor intake air flow). By varying the IGV angle of the new gas turbine and then that of the existing CC gas turbine, the power of the integrated plant can be reduced to about 75% of the rated value. Further power reduction requires lower fuel–air mass ratio. This clearly penalizes efficiency, but if instead,the additional gas turbine is completely shut down, the combined cycle returns to its original design point. Aeroderivative turbines maximize flexibility (Fig. 5). In this case, more than one GT/HRSG unit has to be installed to exploit the full steam reception capacity of the existing gas turbine. This provides another degree of freedom, namely the number of GTs operating at any one time. Hence, the maximum variations indicated above are attained only for the IGVs of the new turbines, while those of the existing GT are operated over a limited range (up to 5 or 10) and a reduction of combustor exit temperature is unnecessary. Lower power outputs are obtained, at higher efficiency, by shutting down one of the added GTs and operating the others at full load. This clearly emerges in Fig. 5 where, moving from right to left, the upper curve shows how the additional power produced by the new gas turbine decreases with IGV angle (0, 5, . . . , 30). For further power reductions, one also has to move the IGVs of the existing turbine, but above 5, a second curve
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P [MW] 400 150
450
500
550
600
650
ΔP [MW]
100 50 CC
0
GT -50 11
MSI/MAIR[%]
9 8 7 6 450
500
550
600
650
P [MW] Fig. 4. Part load strategy of the combined cycle GE S109FA repowered using steam injection by a heavy duty gas turbine (GE PG9171E).
is available for the same plant working with just two extra turbines. Repeating the same procedure for the second gas turbine, the plant can be controlled over a large power P [MW] 400 150
450
500
550
– the simple cycle gas turbine; – the gas turbine, the HRSG + piping + auxiliary equipment, plus the steam turbine with condenser and alternator for the existing combined cycle; – the gas turbine plus the HRSG + piping + auxiliary equipment for the repowering facility. The capital costs considered in the economic analysis are summarized in Table 5, which also shows, in addition to specific cost, the base size and scaling factor. No scaling factor is given for GTs, as the specific cost ($/kW) is dependent upon the technology and manufacturer. The following data for capital costs of gas turbines used for utility repowering have been taken from the literature [20,21] and web sites [22,23]: 195 $/kW for GE PG9171E,
50
CC
0
The aim of this section is to assess the economic feasibility of the repowering facility itself, irrespective of the NGCC taken as baseline. Therefore, the results will be expressed in terms of incremental variables, i.e. incremental power, incremental capital costs and incremental operating costs. For comparative purposes, the cost of electricity produced (CoE) is evaluated also for the baseline combined cycle and for the same gas turbine used for repowering operated in a simple cycle. The capital costs for these three situations are given by:
600
100
ΔP [MW]
range while maintaining high performance. The percentage of injected steam per intake air flow is lower for the aeroderivative turbines than for the heavy duty ones. Part load performance of the repowered plant is summarized in Fig. 6, where design conditions are taken as reference values. The two cases of single heavy duty GT incur a heavier efficiency penalty, maintaining high performance only within a 10% power reduction. On the contrary, the option with three aeroderivative GTs shows increasing efficiency, whereas gradually shutting down the new turbines restores the plant to its original configuration. 4.3. Economic analysis
10
400
1597
GT -50
104
ηRCC [% of design]
MSI/MAIR [%]
8 6 4 2 0 400
450
500
550
600
P [MW] Fig. 5. Part load strategy of the combined cycle GE S109FA repowered using steam injection by three aeroderivative gas turbines (GE LM6000).
1 GT
102 100 98 GE P G9171E GE P G7221FA
96
GE LM 6000
94 60
70
80
90
100
PRCC [% of design] Fig. 6. Part load performance of the combined cycle GE S109FA repowered using steam injection by gas turbines.
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Table 5 Capital costs and scale parameters adopted for the economic analysis
Steam turbine + generator + condenser HRSG + piping + auxiliary equipment Gas turbine
Scaling parameter
Base specific cost
Base size
Scaling factor
Thermal power Electric power Electric power
350 ($/kWe) 90 ($/kWt) 200–300 ($/kWe)
200 (MWe) 630 (MWt) 200–300 ($/kWe)
2/3 2/3 1
200 $/kW for Siemens V94.2, 225 $/kW for ABB GT11N2, 210 $/kW for GE PG7221FA and 295 $/kW for GE LM6000. Table 6 summarizes the assumptions made in the economic analysis of the repowering process. Table 7 presents the results of the economic analysis, showing the different contributions to the total capital requirement and to the CoE (capital recovery, O&M, fuel). For comparison, the cost of electricity produced by reference plants has also been estimated: the CoE of the baseline combined cycle is 35.7 mill$/kW h against a CoE of 41.7–46.7 mill$/kW h for simple cycle GTs. The lower cost can be achieved with an aeroderivative GT (GE LM6000) and the higher cost with a low efficiency heavy duty GT (GE PG9171E). As Table 7 shows, the CoE of the repowered cycle is very close to that of the baseline combined cycle. Specifically, the CoEs are slightly lower for heavy duty GTs and a little higher for aeroderivative GTs. It would appear that the lower fuel costs of the highly efficient aeroderivative turbines do not offset their higher capital recovery cost. In all cases, the reduction in the CoE with respect to simple cycle GTs is significant. This clearly emerges from Fig. 7, which shows the histogram for the various contributions to the CoE for simple cycle GTs and for the same turbines used in a repowering configuration. Note that the fuel related CoE is reduced dramatically, owing to the increased energy efficiency, whereas the capital recovery and maintenance show only modest increments.
Table 6 Assumptions for the economic analysis of the repowering option Plant lifetime (yr) Yearly operating hours (h/yr) Fuel cost ($/GJ) Discount rate (%) Annual cost escalation rate (%) Construction time (yr) Fixed O&M ($/kW yr) Variable O&M (mill$/kW h) Insurance costs (%) Balance of the plant (%) Cost of engineering (%) Contingencies (%) Pre-production cost (%)
25 7000 3.3 10 1.5 2 12.0 0.5 1 12 8 5 2
This analysis indicates a higher CoE for the aeroderivative repowering option on account of the higher capital requirement. This is easily explained by the higher specific cost of aeroderivative GTs and the negative scaling effect of splitting the HRSG into three units. However, the above considerations apply to full load operation. It should be borne in mind that the option envisaging three aeroderivative gas turbines performs much better in part load operation (Fig. 6), as the incremental efficiency, i.e. the incremental power to incremental fuel consumption ratio, indicates (Figs. 8 and 9). Clearly, for a single heavy duty GT, the incremental efficiency decreases steadily and significantly (Fig. 8), while for the option with three aeroderivative GTs, it remains very high and practically constant up
Table 7 Cost of electricity for the five gas turbines used for repowering Gas turbine number and manufacturer Gas turbine model designation Gas turbine cost (M$) HRSG + piping + auxiliary equip. cost (M$) Total installed equipment cost (M$) Balance of the plant (M$) Cost of engineering (M$) Contingencies (M$) Overnight capital cost (M$) Interest during construction (M$) Pre-production cost (M$) Total capital requirement (M$) Specific capital cost ($/kW) Marginal power output (MW) Marginal efficiency (%) COE due to capital recovery (mill$/kW h) COE due to O&M (mill$/kW h) COE due to fuel (mill$/kW h) Total COE (mill$/kW h)
1 and GE PG9171E 24.07 29.36 53.43 2.89 4.27 2.67 63.26 1.85 1.27 66.38 289.40 229.36 48.52 4.55 2.84 27.90 35.29
1 and Siemens V94.2 31.79 34.04 65.83 3.81 5.27 3.29 78.20 2.29 1.56 82.05 277.14 296.07 49.34 4.36 2.82 27.44 34.62
1 and ABB GT11N2 25.96 27.13 53.09 3.11 4.25 2.65 63.11 1.84 1.26 66.21 315.06 210.15 49.11 4.96 2.89 27.56 35.41
1 and GE PG7221FA 33.39 32.59 65.99 4.01 5.28 3.30 78.57 2.30 1.57 82.44 291.08 283.21 50.39 4.58 2.85 26.86 34.29
3 and GE LM6000 38.42 35.14 73.56 4.61 5.88 3.68 87.73 2.56 1.75 92.05 446.70 206.07 51.67 7.03 3.10 26.20 36.33
R. Carapellucci, A. Milazzo / Energy Conversion and Management 48 (2007) 1590–1600
Fuel O&M
60
21 G
G
EP
G
EL
M
72
T1 G AB
B
s en Si em
FA
2 1N
2 V9
4.
71 91 G EP G
00
Capital
E
COE [mill$/kWh]
50 45 40 35 30 25 20 15 10 5 0
Fig. 7. Comparison of CoE for the five gas turbines operated in simple cycle (1st bar) and repowering facility (2nd bar).
50 45
1599
bine, raising both the GT power output and its exhaust temperature and, as a result, also raising the steam for the bottoming steam cycle. In this way, the CC power can be increased by well over 50%, with a decrease in efficiency of between 3% and 6%, depending on the specific additional GT used. This result has been achieved in spite of the relative simplicity of the added components, whose efficiency as stand alone units would be very low. Moreover, integration yields outstanding results in terms of part load operation, especially with the addition of a number of small aeroderivative gas turbines. In this way, by acting on the IGVs and sequentially shutting down the added GTs, plant power can be varied over an extensive range, without paying an excessive efficiency penalty. The CoE relating to the repowered facility, evaluated on the basis of literature data, compares favorably with and can actually be lower than that of the reference plant.
ηI [%]
40
References
35 30 25 20 400
450
500
550
600
650
P[MW] Fig. 8. Incremental efficiency of repowering vs. power for a single heavy duty gas turbine (GE PG9171E).
55
ηI [%]
52 49 46 43 40 400
450
500
550
600
P[MW] Fig. 9. Incremental efficiency of repowering vs. power for three aeroderivative gas turbines (GE LM6000).
to about 75% of rated power. Hence, the benefits of repowering with heavy duty GTs may well be offset by the greater operating flexibility of the aeroderivative option. 5. Conclusions A repowering scheme for combined cycle power plants has been proposed, featuring the addition of a gas turbine and a one pressure level HRSG. The latter feeds the output steam to the combustion chamber of the existing gas tur-
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