Technological and economical analysis of water recovery in steam injected gas turbines

Applied Thermal Engineering 21 (2001) 135±156

www.elsevier.com/locate/apthermeng

Technological and economical analysis of water recovery in steam injected gas turbines M. De Paepe*, E. Dick Department of Flow, Heat and Combustion Mechanics, Universiteit Gent, St. Pietersnieuwstraat 41, B-9000 Ghent, Belgium Received 24 August 1999; accepted 1 February 2000

Abstract Steam injected gas turbines are an interesting technology for co-generation applications. In these gas turbines the heat of the exhaust gases is used to produce steam. This steam is injected in the combustion chamber, resulting in a high speci®c power and a high thermal eciency. A major disadvantage of steam injected gas turbines is the large water consumption. Placing a condenser in the cycle makes it possible to recover all the injected steam. An analysis is made of di€erent types of condensers. Condensers based on ®nned tubes and direct-contact-condensers are considered. The dimensions of the condensers are determined for existing steam injected gas turbines. Furthermore, the investment costs and the exploitation costs for each type are compared. 7 2000 Elsevier Science Ltd. All rights reserved. Keywords: Steam injection; Gas turbine; Water recovery; Condensers

1. Introduction 1.1. Steam injection in gas turbines In 1976 Cheng [1] proposed a gas turbine cycle in which the heat of the exhaust gas of the gas turbine is used to produce steam in a heat recovery steam generator (see Fig. 1). This steam is injected in the combustion chamber of the gas turbine, resulting in an eciency gain * Corresponding author. Tel.: +32-9-2643294; fax: +32-9-2643586. E-mail address: [email protected] (M. De Paepe). 1359-4311/01/$ - see front matter 7 2000 Elsevier Science Ltd. All rights reserved. PII: S 1 3 5 9 - 4 3 1 1 ( 0 0 ) 0 0 0 2 9 - 6

136

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

and a power augmentation. The cycle is commonly called the `CHENG-cycle' or the `Steam Injection Cycle'. General Electric (GE) dubbed its steam injected aeroderivative machines STIG2 (STeam Injected Gas Turbine) [2]. By introducing steam injection in a gas turbine an eciency gain of about 10 points and a power augmentation of about 50±70% are possible. Using a steam turbine to expand the steam, i.e. applying a combined cycle instead of a Cheng-cycle, gives higher eciency gains. Accepted eciency for the combined cycle is now a days 55%, with a power rise of about 30± 50% with respect to the simple cycle. Fig. 2 gives an overview of the eciency of current gas turbines as a function of power output ranging from 0.2 to 250 MWe, according to data found in [3,4]. The eciency is given for the simple cycle, the combined cycle (gas turbine and steam turbine) and the steam injection cycle. As expected, the simple cycle has the lowest eciency for the whole power range. Combined cycles were only found in applications producing 10 MWe and more. For that range, maximum eciency is obtained by this type of cycle. The eciency of the combined cycle deteriorates with lower power output because of the diminishing eciency of its components for low power. If the line of the combined cycle were to be continued in the lower power range, the eciency would be lower than for the Cheng-cycle. For high power ranges, it is more pro®table to use a combined cycle. For power output lower than 10 MWe, combined cycles are no longer ecient. Here steam injection becomes attractive because it gives a better performance than simple cycle and combined cycle machines. From the economic point of view, it is obvious that the Cheng-cycle has lower investment costs, because it does not require the steam turbine. As shown in Fig. 2 there are ®ve gas turbines in the market, which are adapted to the use of steam injection. The three bigger machines, all are constructed by General Electric and are the GE LM5000 STIG2, the GE LM2500 STIG2 and the GE LM1600 STIG2, producing respectively 50.7, 26.4 and 17 MWe. Without steam injection they produce 32.6, 19.2 and 13 MWe. The two smaller machines are the Allison 501KH and the Kawasaki M1A-13CC. Cheng and his team modi®ed the Allison 501 for steam injection, calling it the 501KH. It was also the

Fig. 1. The steam injection cycle.

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

137

®rst machine to use steam injection in an industrial environment, at the San Jose University in California, 1984. The most recent variant of the Allison 501 produces 4.9 MWe without steaminjection and 6.8 MWe with steam injection. The latest development in steam injected gas turbines is the Kawasaki M1A-13CC. With this machine Kawasaki aims at the low power cogeneration applications. The gas turbine produces 2.3 MWe in steam injection mode and 1.3 MWe without steam injection. Cheng founded International Power Technology (IPT), which exploited the patent obtained by Cheng in 1978. In 1991 IPT was acquired by an Austrian industrial holding company VA TECH. IPT became part of the division specialising in gas turbine based power generation systems, known as ELIN E.V., headquartered in Vienna, Austria. ELIN is the main supplier of co-generation systems based on the Allison 501KH and the Kawasaki M1A-13CC. 1.2. Water recovery A major disadvantage of steam injection is that the cycle consumes water. The injected steam is lost to the atmosphere through the stack. The GE LM5000 consumes about 16.76 kg/s of water in steam injection mode. For the Allison 501KH, producing 6.05 MWe, the steam ¯ow is 0.274 kg/s. Furthermore, the water used for the production of the injected steam has to be of high quality, to protect the steam generator and the turbine blades. The loss of this water

Fig. 2. Current gas turbine technology.

138

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

results in an extra exploitation cost which, according to Tuzson [4], is about 5% of the total fuel cost of the installation. Therefore, it seems reasonable to try to recover the injected steam by condensation of water out of the exhaust gases. This results in a ``closed'' steam injection cycle, as shown in Fig. 3. In the original patent of Cheng [1] a condenser was introduced into the cycle. Cheng proposed the use of ®nned tubes. He did not mention any methods for designing or sizing of the condenser. In the past, some tests were performed to prove the technical feasibility of water recovery. Several types of condensers were analysed. A ®nned tube type condenser was tested at the Universiteit Gent. No real gas turbine was used. Methane was burnt and steam was added to obtain a gas composition at the entrance of the condenser similar to the exhaust gases of a natural gas fuelled gas turbine. Full recovery was reached [5]. A second test rig was built in which a direct contact condenser was tested. Again full recovery was reached [6]. Due to the combustion of natural gas, water is produced. The extra water content in the exhaust gases results in a dew point of the gas of about 758C. For full recovery, the dew point of the exhaust gases has to be brought down to about 458C. This is a temperature which can be easily obtained. In the Harbin Marine Boiler and Turbine Research Institute [7] a spiral-type condenser made of stainless steel was tested on a test rig with a diesel oil fuelled Kawasaki gas turbine of 221 kW. On the same test rig a shell and tube condenser was installed with glass tubes [8]. In both cases complete recovery was possible with supplementary ®ring in the boiler. In 1992 Hguyen and den Otter [9] of the Nova Corporation proposed the installation of a shell and tube condenser with Te¯on-coated tubes, to protect the steel tubes against corrosion. Steam injection was to be implemented in a Solar Saturn T1300 turbine, using methane as fuel. The condenser was designed to give full recuperation if the ambient temperature is below 138C.

Fig. 3. The steam injection cycle with water recovery.

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

139

This was only the case during the winter period. During summer, storage tanks that have accumulated water in the winter period were to supply the water. This project has never left the design stage. Only one example was found in which the recuperation of the injected water is realised in an industrial environment: the ``Carrozzeria Bertone'' plant (Turin, Italy) [10]. In this plant the condenser is constructed using copper tubes with aluminium ®ns. Full recovery is reached. After 2.5 years in operation no corrosion was detected in the condenser [11]. Uptil now no thorough analysis has been made of the sizing and economics of the condenser. A major concern of water recovery is the quality of the condensation water. A major part of the water costs is the treatment of water upto boiler feed water quality. If the condensation water is too contaminated with combustion products, the costs for treating the water will be so high that the pro®t made due to the recovery will be marginal. Poggio and Strasser report measurements on condensation water composition in the condenser at the `Carrozzeria Bertone' plant [11]. Table 1 gives the analysis of the condensation water. The water can be easily put back into the cycle. Only little treatment will be needed. For example, the conductivity for a STIG of GE has to be 0.1 mS. By using classical ion exchangers this can easily be obtained. These results show that water recovery in a steam injection cycle is technically feasible. In this article, the design of di€erent types of condensers will be described. They will be compared on a technical and economical basis.

2. Plant design Three di€erent types of condenser are compared. Fig. 4 shows the layout of the ®rst plant type. The condenser is a ®nned tube type condenser, cooled with water. The exhaust gases ¯ow at the outside of the condenser tubes. The condensate is captured at the bottom of the condenser and pumped to storage tanks. From there it is pumped through the feed water treatment system to the economiser. The cooling water is circulated through a water to air cooler. The choice was made to install a water cooler, for it is now no longer possible to take Table 1 Analysis of water recovered in the Bertone Plant [10] Contaminants CaCO3 (ppm) pH Conductivity (mS) Chloride (ppm) Sulfates (ppm) Al+3 (ppm) Cu+2 (ppm) Fe+2 (ppm)

25 4 42 5.3 1.5 1 0.02 0.05

140

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

Fig. 4. Steam injection cycle with water-cooled condenser and water to air cooler.

water out of the environment for free, because of the severe environmental regulations in most countries. Fig. 5 shows the second type of condenser. Here a direct air to exhaust gas condenser is used. Of course the size of the condenser itself is larger than to the water-cooled one. Now the exhaust gases ¯ow inside the tubes. The moment condensation starts, a two phase ¯ow exists in the condenser tubes. The tubes of the condenser have to be tilted to evacuate the condensed water at the end. The gases escape into the stack, while the water is captured at the bottom. The third condenser is a direct contact condenser. As shown in Fig. 6, water is sprayed into the exhaust gas ¯ow. Due to the cooling e€ect, condensation will occur. The condensation

Fig. 5. Steam injection cycle with air-cooled condenser.

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

141

Fig. 6. Steam injection cycle with direct contact condenser and water to air cooler.

water is mixed with the cooling water. This water ¯ow is split into two di€erent streams. One part is going to the storage and treatment tanks, to be fed back into the steam generator. The second stream is cooled in a water to air cooler. This water is reused for cooling. The aforementioned types of condensers are sized for the ®ve existing gas turbines. The design input data consisted of gas temperature, mass ¯ow rate and composition after the H.R.S.G and the injected steam mass ¯ow rate. To be able to compensate for losses, the condensation mass ¯ow rate was taken to be 105% of the steam ¯ow rate. The data of the di€erent gas turbines are listed in Table 2. The LM5000 and the LM1600 have two pressure Table 2 Gas turbine dataa M1A-13CC

501KH

LM1600

LM2500

LM5000

Power (MWe) Eciency (%) TOT (8C) m_exhaust (kg/s) m_fuel (kg/s) m_air (kg/s) m_steam (kg/s)

2.3 34 590 8.4 0.153 6.9 1.37

6.8 40 554 28.6 0.356 15.5 2.72

26.4 39.5 523 81.5 1.4 68 5.6

p_steam (bar) T_steam (8C) m_condensation m_water (kg/s)

15.2 453

14.1 482

17 40 443 54.5 0.993 47.2 6.19 (2.61/3.58) 31/13.1 405/382

27.6 325

50.7 43 432 156.8 2.8 137 16.8 (9.8/7.0) 35.2/10.3 288/238

1.41

2.86

6.49

5.88

17.9

a

TOT: turbine outlet temperature; m_exhaust: exhaust gases mass ¯ow rate; m_fuel: fuel consumption; m_air: mass ¯ow rate through the compressor; m_steam, p_steam, T_steam: mass ¯ow rate, pressure and temperature of the injected steam; m_condensation, m_water: condensation water mass ¯ow rate needed (5% more than m_steam).

142

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

levels in their steam generator. The high-pressure steam is injected in the combustion chamber, the low-pressure steam before the low-pressure turbine. The data was derived from brochures published by GE [2] and Elin [1]. 3. Condenser design 3.1. Calculation method For the design of the ®nned tube condensers a calculation method was used according to [12]. The condenser consists of a matrix of tubes. The number of columns is the number of tubes in the direction of the ¯ow, the number of rows is the number of tubes perpendicular to this direction. This is illustrated in Fig. 7. The columns consist of several parallel tubes. Therefore, one tube is representative of the column. The tube is divided in several segments. For every segment the heat and mass transfer calculations are solved. The results of the calculation of one segment are used as input for the next segment. This way all the tubes are solved in the direction of the gas ¯ow. If the coolant ¯ows in counter current to the gas ¯ow, the condenser is solved iteratively. For the direct contact condenser a calculation method was developed. The condenser is treated as a channel, in which the cooling water and the exhaust gases are mixed. The channel is divided in several segments, in which a part of the coolant water is mixed. The heat balance for each segment is solved, supposing that the cooling water temperature at the end of the segment can reach a fraction of the exit temperature at equilibrium (see Fig. 8). It is assumed

Fig. 7. Schematic view of the ®nned tube condenser.

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

143

that the temperature increase of the coolant water is 75% of the temperature increase that would occur if cooling water and exhaust gases leave the segment at the same temperature. The resulting gas temperature is used as input for the next part. The water temperature at the exit of the condenser is the average of the cooling water temperature of every segment. The calculation methods were both validated on the test rigs referred to the introduction [5,6]. The relative error between calculations and measurements is maximum 3% for the exit temperature and 10% for the condensate mass ¯ow rate in case of the ®nned tube type condenser [13]. For the direct contact condenser these ®gures are respectively 4% and 1% [13].

3.2. Water-cooled condenser with water to air cooler For the water-cooled condenser, aluminium ®nned copper tubes were used with a diameter of 18 mm, 440 ®ns/meter and a ®n height of 18.6 mm. The cooling water enters at a temperature of 258C and the exhaust gases at 1508C. The average velocity of the cooling water in the tubes is 2.2 m/s. The entrance velocity of the exhaust gases is 10 m/s. At the exit the velocity has dropped to 6.8 m/s, due to the loss of mass. The condenser consists of three modules through which the exhaust gases and the cooling water pass in counter-¯ow. In each module eight tubes are put in the ¯ow direction, except for the Allison 501KH where nine tubes are necessary to obtain the condensation mass ¯ow rate. Depending on the exhaust gas mass ¯ow rate the number of tubes stacked in height is variable (6, 12, 34, 46 and 97 tubes for the M1A-13CC, 501KH, LM1600, LM2500 and LM5000, respectively). The tube length is 4 m for every machine. Fig. 9 shows a sketch of the condenser. The dimensions given in Table 3 are shown in Fig. 9.

Fig. 8. Calculation method of the direct contact condenser.

144

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

Fig. 9. Design of the water-cooled condenser.

3.3. Water to air cooler for the water-cooled condenser The water to air cooler uses the same tubes as the condenser. The length of the tubes is 11 m. The air¯ow is divided in two parallel streams. The water crosses the air in 2  2 passes, one in counter-¯ow, one in co-¯ow, as shown in Fig. 10. The tubes are stacked 6 high (2  3). The Table 3 Dimensions of the water-cooled condenser Water-cooled condenser

M1A-13CC 501KH

LM1600

LM2500

LM5000

Length (m) Width (m) Height (m) Tube length (m) Number of tubes

2.1 4.5 0.6 4 144 (3  8  6) 24

2.4 4.5 1.1 4 324 (3  9  12) 54

2.1 4.5 2.9 4 816 (3  8  34) 136

2.1 4.5 3.9 4 1104 (3  8  46) 184

2.1 4.5 8.2 4 2328 (3  8  97) 388

67.3

65.0

62.4

55.3

60.5

54.4

52.0

54.4

48.0

53.5

4.25

9.02

21.3

23.3

58.8

Cooling water mass ¯ow rate (kg/s) Cooling water exit temperature (8C) Exhaust gas exit temperature (8C) Power (MW)

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

145

Fig. 10. Design of the water to air cooler.

Table 4 Dimensions of the water to air cooler for the water-cooled condenser Water to air cooler

M1A-13CC

501KH

LM1600

LM2500

LM5000

Length (m) Width (m) Height (m) Tube length (m) Number of tubes

11.5 4.6 0.6 11 324 (2  (6  27)) 396

11.5 9.5 0.6 11 648 (2  (6  54)) 911

11.5 24.3 0.6 11 1740 (2  (6  145)) 2196

11.5 32.9 0.6 11 2352 (2  (6  196) 2584

11.5 69.1 0.6 11 4956 (2  (6  143)) 5752

25.3

24.8

24.9

24.0

24.7

4.42 2 116

9.1 4 288

21.3 10 650

23.4 12 792

57.8 28 1708

Cooling air mass ¯ow rate (kg/s) Cooling air exit temperature (8C) Power (MW) Number of fans Power of fans (kW)

146

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

number of tubes lying next to each other is adjusted to the mass ¯ow rate of water and air. The entering temperature of air is 158C. The velocity of the water inside the tubes is 2.2 m/s and the air velocity is 11 m/s. Table 4 presents the results for the air coolers needed to cool the water coming from the condenser. The width of the condenser is a principal ®gure. In practice the cooler will be built in several modules, which work in parallel. To move the air, fans are needed. In order to be able to estimate the costs, the size of these fans is determined. Fans with four blades and with a diameter of 4 m are chosen. The power consumption of the fans is also given in Table 4. 3.4. Air-cooled condenser Fig. 11 shows the design concept of the air-cooled condenser. The tubes of the condenser are placed vertically. The exhaust gases ¯ow from top to bottom at the inside of the tubes. The cooling air ¯ows in cross ¯ow over the tubes. Due to the lower local average temperature there

Fig. 11. Design of the air-cooled condenser.

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

147

will be more condensation in the ®rst tubes. The length of the tubes determines the amount of condensation in the tube. If 30 tubes are placed next to each other in the direction of the air¯ow, tubes of 3 m are needed. For the LM5000 is was seen that the tubes had to be 3.5 m and for the LM2500 only 2 m was necessary. The number of tubes in the direction of the exhaust gas ¯ow is determined by the mass ¯ow rate of the exhaust gases. The air-cooled condenser is built out of aluminium ®nned copper tubes with a diameter of 1 in., 440 ®ns/meter and a ®n height of 18.6 mm. The cooling air enters at a temperature of 158C and the exhaust gases at 1508C. Fig. 11 shows the dimensions given in Table 5. The fans used in this type of condenser were chosen to have a diameter of 2.5 m and six blades. The air-cooled condenser is bigger than the water-cooled one. If the water to air cooler is added, they are comparable. The air mass ¯ow rate needed for the air-cooled condenser is smaller. For the water-cooled condenser water is used at 258C. This water is cooled in a water to air cooler with air at 158C. In the air-cooled condenser, air is directly used at 158C, which makes the condenser more ecient. 3.5. Direct contact condenser The direct contact condenser is in principle a channel at the bottom of which spray nozzles are placed. The section of the channel is determined by the gas velocity necessary for a good development of the spray and a good contact between gas and ¯uid. This velocity lies between 1 and 3 m/s. The length of the channel depends on the number of sprays that have to be positioned in it. If the nozzles are too close to each other, the eciency of the spray will drop. A small average diameter of the droplets in the spray results in a better contact. Therefore, the

Table 5 Dimensions of the air-cooled condenser Air-cooled condenser

M1A-13CC

501KH

LM1600

LM2500

LM5000

Length (m) Width (m) Height (m) Tube length (m) Number of tubes

7.3 2.8 2.8 2.5 2220 (30  74) 110

14.6 2.8 2.8 2.5 4440 (30  148) 220

41.0 2.8 2.8 2.5 13050 (30  435) 520

62.0 2.8 2.3 2 19440 (30  648) 795

76.9 2.8 3.3 3 24390 (30  813) 1382

52.7

54.9

54.4

43.4

55.1

46.0

48.4

48.1

56.4

48.7

4.2 2 51.2

8.7 4 102.5

21.3 10 233.1

23.1 14 375.1

57.3 26 772.3

Cooling air mass ¯ow rate (kg/s) Cooling air exit temperature (8C) Exhaust gas exit temperature (8C) Power (MW) Number of fans Power of fans (kW)

148

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

Fig. 12. Design of the direct contact condenser.

sprays are operated at a pressure of about 10 bar, resulting in a characteristic droplets diameter of 1.6 mm with a Rosin±Rammler distribution parameter of 2.5. In Fig. 12 the direct contact condenser is shown. The cooling water enters at 258C, the exhaust gases at 1508C. The number of nozzles next to each other perpendicular to the gas ¯ow direction was determined by the need to cover the whole section with the sprays. The

Table 6 Dimensions of the direct contact condenser Direct contact condenser

M1A-13CC

501KH

LM1600

LM2500

LM5000

Length (m) Width (m) Height (m) Number of nozzles Nozzle pressure (bar) Cooling water mass ¯ow rate (kg/s) Cooling water exit temperature (8C) Exhaust gas exit temperature (8C) Power (MW)

10 2 3 12 (3  4) 12 40 51.0 42.2 4.4

12 3 3 25 (5  5) 10.5 86 50.3 41.8 9.1

14 5 5 54 (9  6) 13.5 225 48.5 41.3 22.1

16 6 6 77 (11  7) 10 276 45.1 38.5 23.1

22 9 8 170 (17  10) 11.5 655 47.6 39.9 61.9

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

149

number in the ¯ow direction depends on the necessary cooling water mass ¯ow rate to obtain the required condensation. The distance between the nozzles in the perpendicular direction is 0.5 m. Between each row of nozzles the distance is 2 m. The exhaust gases at the exit of the condenser are at a lower temperature in comparison with the other two condensers (Table 6). In the direct contact condenser the exhaust gases are cooled to dew point. In the ®nned tube condensers this equilibrium state is not reached, because the cold surfaces of the tubes are responsible for the condensation. Compared to the ®nned tube condenser the direct contact condenser needs more water. This is caused by the fact that the water in the ®nned tube condenser can reach a higher temperature. 3.6. Water to air cooler for the direct contact condenser The water cooler is of the same design as the one used with the ®nned tube condenser. The length of the tubes is 8.5 or 8 m for the larger machines. There is in all cases a larger water mass ¯ow rate, resulting in the need for more tubes. The fans have a smaller diameter of 2.8 m and use six blades. In Table 7 the results are presented. As the cooler uses more tubes, it is larger than the cooler for the ®nned tube condenser. As a result, the installation with a direct contact condenser with cooler is fairly large. 3.7. Conclusion The water-cooled condenser is the smallest of the three types. It occupies about 10% of the

Table 7 Dimensions of the water to air cooler for the direct contact condenser Water to air cooler

M1A-13CC

501KH

LM1600

LM2500

LM5000

Length (m) Width (m) Height (m) Tube length (m) Number of tubes

9 6.9 0.6 8.5 492 (2  (6  41)) 560

9 14.5 0.6 8.5 1032 (2  (6  86)) 1118

8.5 40.2 0.6 8 2880 (2  (6  240)) 3000

8.5 46.2 0.6 8 3312 (2  (6  276)) 3400

8.5 109.4 0.6 8 7860 (2  (6  655)) 8918

22.8

23.1

22.5

22.1

22.2

4.4 6 170

9.1 12 339

22.9 32 962

23.8 39 1111

62.6 105 2915

Cooling air mass ¯ow rate (kg/s) Cooling air exit temperature (8C) Power (MW) Number of fans Power of fans (kW)

150

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

volume of the air-cooled condenser. For the bigger machines the direct contact condenser is approximately 15±20 times bigger than the water-cooled condenser. Even with the addition of the water to air cooler the volume of the two heat exchangers is in all cases about 65% of the volume of the air-cooled condenser. The direct contact condenser is quite voluminous due to the large cross section and the need of space for the nozzles. This type of condenser needs more cooling water (the water-cooled condenser uses only 60% of the water needed in the direct contact condensers). The air-cooled condenser has the lowest fan power consumption. On average the power consumption is about 40% of that of the water to air cooler for the water-cooled condenser and 30% of that of the direct contact condenser. From the construction point of view the ®nned tube water-cooled condenser with water to air cooler is preferable, because it is the smallest one. In the next paragraph the construction costs will be compared.

4. Economics 4.1. Investment costs The investment costs of a steam injected gas turbine system consist of four parts. A major cost is the gas turbine with generator. The next large cost is the heat recovery steam generator. Finally there is the costs of the water treatment post and the piping. Gas turbine prices where found in [14]. For the Kawasaki and the Allison installation data were found in [15], for the GE machines costs were derived from [16]. For the data of the water treatment post and piping [17,18] were used. Table 8 gives an overview for steam injection cycles without water recovery. Table 9 gives the investment costs for the heat exchangers. Not only construction costs of the devices, but also installation costs are taken into account. All surfaces in contact with the condensation water are made of stainless steel. The other constructive elements are made of carbon steel. For the copper tubes with aluminium ®ns the prices were obtained via [18] and the prices for the fans were given by [19]. The water-cooled condenser, being the smallest, is also the cheapest to build. Even with the water to air cooler added, the cost is lower than the air-cooled condenser. The direct contact

Table 8 Investment costs of steam injection cycles without water recovery 1000 Euro

M1A-13CC

501KH

LM1600

LM2500

LM5000

Gas turbine HRSG Water treatment post Piping Total

1200 950 29 15 2194

1955 1915 56 41 3967

6475 9400 128 102 11900

9575 5880 115 72 15642

14225 15190 347 212 29974

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

151

Table 9 Investment costs of di€erent types of condenser installations 1000 Euro

M1A-13CC

501KH

LM1600

LM2500

LM5000

Water-cooled condenser Water to air cooler Total Air-cooled condenser Direct contact condenser Water to air cooler Total

79.7 126.4 206.1 210.7 142.3 131.4 273.7

115.0 208.3 323.3 414.0 191.4 221.9 413.3

199.7 478.4 678 979.2 338.6 552.8 891.4

250.1 659.4 909.5 1444.9 447.7 718.9 1166.6

422.3 1294.4 1716.7 2104.1 840.4 1569.2 2409.6

condenser is cheaper than the air-cooled condenser for the Allison, LM1600 and LM2500, though only for the LM1600 and LM2500 the di€erence is signi®cant. The air-cooled condenser for the M1A-13CC is 2% more expensive than the water-cooled condenser with cooler. If the gas turbines grow in size the di€erence in price grows. For the LM2500 the air cooled condenser is 59% more expensive than the water-cooled one. In Table 10 the relative additional costs of the condensers in comparison to the installation costs are listed. In general the relative costs diminish with growing size of the gas turbines. The water-cooled condenser is the most bene®cial from the investment point of view. 4.2. Exploitation costs Exploitation costs and pro®ts depend strongly on the gas prices and the electricity revenue. Both prices are highly variable, depending upon the country of installation. Data were obtained for gas and electricity prices for several European countries [20,21]. In this paper averaged ®gures are used, being representative for the European market situation. In all calculations 7000 h/year of continuous operation at full load was assumed. In Table 11 the price assumptions are summarised. The average price of natural gas for a co-generation installation in Europe is about 0.08 Euro/m3. The electricity revenue is an average electricity price for high power consumers. This is the price which is not to be paid if the electricity is produced by the customer itself [21]. Operations and Maintenance (O & M) costs vary with unit size according to [10,16]. Table 12 gives the exploitation costs under these conditions for the gas turbines without water recovery. It is interesting to notice that the pay back time of a steam injected gas turbine Table 10 Relative additional costs of the condensers %

M1A-13CC

501KH

LM1600

LM2500

LM5000

Water-cooled condenser with water to air cooler Air-cooled condenser Direct contact condenser with water to air cooler

9.4 9.6 12.5

8.2 10.4 10.4

5.7 8.2 7.5

5.8 9.2 7.5

5.7 7.0 8.0

152

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

Table 11 Assumptions exploitation costs (1 Euro = 1 $US) Costs Electricity revenue Natural gas O & M gas turbine O & M other components Water of boiler quality Condensation water to boiler quality Hours of operation

62.5 Euro/MWh 0.08 Euro/m3 4.5 Euro/MWh produced 3.5% of investment annually 2 Euro/m3 0.5 Euro/m3 7000 h/year

is about 2.2 year. The M1A-13CC has a larger pay back time. This is due to the fact that the gas turbine has low power production and high water consumption. The relative cost of the water varies from 15% to 7%. For the LM2500 this cost is low because only a relatively small steam mass ¯ow rate is allowed. In general the water cost diminishes when the power goes up. Adding a condenser to the installation does not simply result in the disappearance of the water costs. In the case of water condensation, the water still has to be treated. As a result the costs for buying fresh water drop out and, as mentioned above, water treatment is easier with condensation water, making it cheaper. The costs for water treatment are set at 1 Euro/m3 [21]. The O & M costs go slightly up because of the extra heat exchangers. Pumps are needed for the cooling water of the condenser. Furthermore, fans are used in the water to air cooler. These machines consume extra power. It is assumed that the power is coming from the electricity produced by the gas turbine. Therefore, the electricity revenue diminishes. Water recovery does not necessarily result in a gain in net pro®t, as is shown in Table 13 for the water-cooled condenser with water to air cooler. Due to the extra power consumption the electricity revenue diminishes. The gain due to water recovery is smaller than the loss in electricity revenue. The drop in net pro®t, though, is small in comparison with the net pro®t without recovery. That is why the pay back time only changes marginally. The water price for which the net pro®t with and without water recovery is equal, can be determined. These prices are given for all the installations in Table 13. For the LM2500 this Table 12 Exploitation costs without water recovery 1000 Euro/year

M1A-13CC

501KH

LM1600

LM2500

LM5000

Fuel O&M Water Electricity Net pro®t Pay back time installation (year) Costs water/total costs (%) Costs water/fuel (%)

ÿ395.1 ÿ36.9 ÿ69 1005.7 504.7 4.3 13.8 17.5

ÿ919.4 ÿ76.5 ÿ137.1 2973.5 1840.5 2.1 12.1 14.9

ÿ2564.4 ÿ207.1 ÿ312 7433.8 4350.3 2.7 14.9 19.8

ÿ3615.5 ÿ236.1 ÿ282.2 11544.3 7410.5 2.3 6.8 7.8

ÿ7230.9 ÿ597 ÿ846.7 22170.3 13495.7 2.2 9.7 11.7

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

153

Table 13 Exploitation costs with water recovery by water-cooled condenser with water to air cooler 1000 Euro/year

M1A-13CC

501KH

LM1600

LM2500

LM5000

Fuel O&M Water Electricity Net pro®t Pay back time installation (year) Turning point water price (Euro/m3)

ÿ395.1 ÿ44.1 ÿ17.3 951.0 494.5 4.9 2.1

ÿ919.4 ÿ87.8 ÿ34.3 2838.6 1797.1 2.4 2.4

ÿ2564.4 ÿ230.8 ÿ78 7127.1 4253.9 3.0 2.4

ÿ3615.5 ÿ267.9 ÿ70.6 11167.5 7213.5 2.3 3.0

ÿ7230.9 ÿ657 ÿ211.7 21359.1 13259.5 2.4 2.3

price has to be higher due to the lower water consumption. On average the water price should be 2.5 Euro/m3 to make water recovery bene®cial. This price is 25% higher than the assumed water price in the analysis. A totally di€erent picture appears if the cooling of the condenser can be done with water taken from the environment. Taking water out of the environment costs about 0.025 Euro/m3 [22]. In Table 14 the results are presented. The pay back time is lower now than without recovery. The pay back time of the condenser was determined by dividing the cost of the condenser by the annual gain in net pro®t. The pay back time of the condenser is about 1.5 year. If the water price drops beneath 0.73 Euro/m3, water recovery is no longer attractive. In Table 15 the results are shown for the air-cooled condenser. The net pro®t in this case is higher than without water recovery. Only for the LM2500 there is no gain in net pro®t. The cost reduction due to water recovery is smaller than the loss in electricity revenue. Using an air-cooled condenser is pro®table for all the other installations. Payback time of the whole installation changes only a little. If the gain in net pro®t is used to pay back the condenser, the pay back time of the condenser is 9.5 years. The turning point for the water price is now on average 1.4 Euro/m3. Though the air-cooled condenser has a higher investment cost, it is advantageous from the exploitation point of view. For the calculation of the economics of the direct contact condenser an extra complication Table 14 Exploitation costs with water recovery by water-cooled condenser without water to air cooler 1000 Euro/year

M1A-13CC

501KH

LM1600

LM2500

LM5000

Fuel O&M Coolant water Water Electricity Net pro®t Pay back time installation (year) Pay back time condenser (year) Turning point water price (Euro/m3)

ÿ395.1 ÿ39.7 ÿ1.5 ÿ17.3 1001.8 548.2 4.1 1.8 0.73

ÿ919.4 ÿ80.6 ÿ3.4 ÿ34.3 2964.6 1926.9 2.1 1.3 0.72

ÿ2564.4 ÿ214.1 ÿ8.6 ÿ78 7411.3 4546.2 2.7 1.0 0.73

ÿ3615.5 ÿ244.9 ÿ11.6 ÿ70.6 11513.8 7571.3 2.1 1.6 0.83

ÿ7230.9 ÿ611.7 ÿ24.4 ÿ211.7 22106.0 14027.3 2.1 0.8 0.73

154

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

Table 15 Exploitation costs with water recovery by air-cooled condenser 1000 Euro/year

M1A-13CC

501KH

LM1600

LM2500

LM5000

Fuel O&M Water Electricity Net pro®t Pay back time installation (year) Pay back time condenser (year) Turning point water price (Euro/m3)

ÿ395.1 ÿ44.2 ÿ17.3 983.4 526.7 4.6 9.6 1.3

ÿ919.4 ÿ91 ÿ34.3 2928.7 1884.0 2.3 9.5 1.3

ÿ2564.4 ÿ241.4 ÿ78 7331.9 4448.1 2.9 10 1.3

ÿ3615.5 ÿ286.7 ÿ70.6 11380.0 7407.2 2.3 ± 1.9

ÿ7230.9 ÿ670.6 ÿ211.7 21832.6 13719.4 2.3 9.4 1.4

has to be taken into account. The cooling water is mixed with the condensate in the condenser. It is not possible to treat all the cooling water up to boiler feed water quality before injection. Therefore, the treatment costs of water coming from a direct contact condenser are higher than for the other types. The water treatment price for the water going to the boiler is set at 1 Euro/m3 [22]. It is assumed that there is no cost for the treatment of the cooling water itself. It is clear that there will be a small cost, because accumulation of combustion products will occur if the cooling water is working in a closed loop. The net pro®t is lower than without water recovery (Table 16). The extra power consumption is mostly responsible for this. Pay back time of the whole installation grows signi®cantly. The turning point for the water price lies at about 4 Euro/m3, which is double the originally assumed value. Direct contact condensers are not useful for water recovery in steam injected gas turbines. 4.3. Conclusion Looking at the investment costs, the water-cooled condenser is the cheapest, even with the water to air cooler. The di€erence between air-cooled and water-cooled condenser is reduced with diminishing size. The direct contact condenser is comparable in price with the air-cooled condenser. Table 16 Exploitation costs with water recovery by direct contact condenser 1000 Euro/year

M1A-13CC

501KH

LM1600

LM2500

LM5000

Fuel O&M Water Electricity Net pro®t Pay back time installation (year) Turning point water price (Euro/m3)

ÿ395.1 ÿ46.4 ÿ34.5 904.4 428.3 5.8 3.8

ÿ919.4 ÿ91 ÿ68.6 2773.0 1694.0 2.6 3.8

ÿ2564.4 ÿ238.3 ÿ156 6841.1 3882.3 3.3 4.5

ÿ3615.5 ÿ277 ÿ141.2 10893.1 6859.6 2.5 5.3

ÿ7230.9 ÿ681.3 ÿ423.5 20441.1 12105.4 2.7 4.8

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

155

If water can be taken out of the environment the water-cooled condenser is the cheapest of all, in investment and exploitation. If water extracted from the environment is not available the air-cooled condenser is the most bene®cial in exploitation. A water to air cooler causes more power consumption than the air-cooled condenser. A direct contact condenser is not useful. Pay back time of the water-cooled condenser with water to air cooler is 1.5 years. The aircooled condenser is paid back in 9.5 years. Installing a condenser has no signi®cant in¯uence on the pay back time of the whole installation. 5. Overall conclusions Steam injected gas turbines are an interesting technology for power production and cogeneration in the power range of 1±50 MWe. The steam injection cycle has a high thermal eciency. A major drawback of the system is the consumption of water. In the past, it has been shown that complete recovery of all the injected steam is possible with di€erent types of condensers. In this article condensers with ®nned tubes and condensers based on the direct contact principle were designed. It was shown that the water-cooled condenser with ®nned tubes is the smallest. Even with a water to air cooler it stays that way. Installation of a water-cooled condenser requires lowest investments. From the exploitation point of view the air-cooled condenser is the most advantageous. Only if the water to air cooler can be omitted, the water-cooled condenser is better. The direct contact condenser is not suited for water recovery in a steam injection cycle. Acknowledgements The research reported here was funded with a fellowship granted by the Flemish institute for the promotion of scienti®c and technological research in the industry (IWT). References [1] F. Stadler, U. Schneider, ELIN Cheng Cycle, Elin Energieversorgung GmbH, 1997. [2] STIG2 Systems Steam Injected Gas Turbines, GE Aeroderivative Industrial Gas Turbines, GE Marine & Industrial Engines, AE-3164(11/88), 1988. [3] International Turbomachinery Handbook 37(6), 1996. [4] J. Tuzson, Status of steam-injected gas turbines, in: Proceedings of the 1991 ASME COGEN-TURBO, Budapest, Hungary, vol. 6, 1991, pp. 19±24. [5] M. De Paepe, E. Dick, Analysis of eciency and water recovery in steam injected gas turbines, in: Proceedings of ASME-IGTI TURBO, 97-GT-435, Orlando, USA, 1997. [6] M. De Paepe, E. Dick, P. Huvenne, Industrial application of water recovery in steam injected gas turbines, VDI Berichte 1438 (1998) 241±250 ISBN 3-18-091438-6. [7] W. Xueyou, Z. Jigou, F. Zheng, Y. Shikang, L. Lingbo, A test rig for the realisation of water recovery in a steam-injected gas turbine, in: Proceedings of ASME-IGTI TURBO, 96-GT-9, Birmingham, UK, 1996. [8] Q. Zheng, G. Wang, Y. Sun, S. Liu, Experiments on water and heat recovery of steam injection gas turbine (STIG) power plant, in: Proceedings of ASME-IGTI TURBO, 97-GT-434, Orlando, USA, 1997.

156

M. De Paepe, E. Dick / Applied Thermal Engineering 21 (2001) 135±156

[9] H.B. Hguyen, A. den Otter, Development of gas turbine steam-injection water recovery (SIWR) system, in: Proceedings of ASME-IGTI TURBO, 92-GT-87, Cologne, Germany, 1992. [10] E. Macchi, A. Poggio, A cogeneration plant based on a steam injection gas turbine with recovery of water injected: design criteria and initial operation experience, in: Proceedings of ASME-IGTI TURBO, 94-GT-17, The Hague, Netherlands, 1994. [11] A. Poggio, A. Strasser, Cheng cycle cogeneration system, application and experience of exhaust gas condensing unit, Technical Report Elin Energieversorgung GmbH, 1995. [12] VDI-WaÈrmeatlas BerechnungsblaÈtter fuÈr den WaÈrmeuÈbergang, 7. erweiterte Au¯age, VDI Verlag, ISBN 3-18401362-6, 1994. [13] M. De Paepe, Steam injected gas turbines with water recovery, Ph.D. Thesis, Universiteit Gent, Belgium, 1999 (in Dutch). [14] Http://www.gas-turbines.com (1999) (last updated Jan 11, 1999). [15] F. Stadler, A. Strasser, Elin Energieversorgung GmbH, Personal Communication, 1997. [16] E.D. Larson, R.H. Williams, Steam-injected gas turbines, Journal of Engineering for Gas Turbines and Power 109 (1987) 55±63. [17] J. De Ruyck, S. Bram, G. Allard, REVAP1 cycle: a new evaporative cycle without saturation tower, in: Proceedings of the Fourth National Congress on Theoretical and Applied Mechanics, Leuven, Belgium, 1997. [18] B.V. Niemann, Personal Communication, 1998. [19] Sirocco Howden Fans, Personal Communication, 1998. [20] J. Lane, Combined cycles projects continue to drive European power markets, Power Engineering International 6 (2) (1998) 24±26. [21] L.G. Martin, A. Vuorinen, Bene®ts of small and medium size power plants in an system and user points of view, in: Proceedings of Power-Gen'97 Europe, Madrid, Spain, 1997, pp. 315±329. [22] Electrabel, Personal Communication, 1999.