Cogeneration for power and desalination — state of the art review

ELSEVIER Desalination 134 (2001) 7-28

DESALINATION

www.elsevier.com/locate/desal

Cogeneration for power and desalination - state of the art review

Ali M. E1-Nashar A bu Dhabi Water and Electricity Authority, P.O. Box 41375, Abu Dhabi, UAE

Tel. +971 (50) 6614430 (mobile); Fax +971 (2) 4434-906; e-mail: [email protected]

Received 26 September 2000; accepted 10 October 2000

Abstract

This paper reviews the state of the art of cogeneration for power and distillation. The performance of several cogeneration options are considered in association with the MSF process for seawater desalination. Both full load and part load characteristics of each major commercial cogeneration process is reviewed both from a technical and economic viewpoint. A methodology for selecting the optimum cogeneration option to satisfy a given demand of power and water is described and an example is given for a cogeneration plant having a power rating of 300 MW and 50 MIGD of potable water. The life cycle cost analysis is used to select the optimum cogeneration system and the exergy analysis method is used for allocating the costs between electricity and water.

Keywords: Cogeneration; Desalination; Distillation; Dual-purpose plants for power and water; Economic analysis

I. Introduction

Most of the potable water and electricity in the Arabian Gulf countries are produced by cogeneration plants associated with multi-stage flash (MSF) desalination units operating on seawater. Although other distillation process such as thermal vapor compression and MED are started to find their way in the market, the MSF process is still considered as the workhorse of desalination industry. In spite o f its limitations, this process has proven its reliability and

flexibility over almost 50 years of plant design and operation. For large desalination capacity, say beyond 30 MIGD, the MSF process can be considered as the only candidate that can be considered commercially. However, on the cogeneration plant side, the situation is different in that several alternatives are commercially available to provide the required electrical power and steam for desalination. Among these alternatives are: • Gas turbines associated with heat recovery

steam generators (GT-HRSG),

Presented at the International Conference on Seca¢ater Desalination Technologies on the Threshold of the New Millennium, Kuwait, 4-7 November 2000.

0011-9164/015-- See front matter O 2001 Elsevier Science B.V. All fights reserved ~PII: S00 l 1-9164(01 )00111-4

8 A M El-Nashar / Desalination 134 (2001) 7-28

• Back-pressure steam turbines (BP-ST) with the discharge steam directed to desalination,

• Controlled extraction-condensing steam turbines (EC-ST) where the steam for desalination is bled from a location on the steam turbine which matches the steam pressure required by desalination,

• Combined gas/steam turbine cycles where a heat recovery steam generator (HRSG) is used to produce steam at medium or high pressure that is supplied to a back-pressure steam turbine discharging into the MSF desalination plant, this system is referred to as CC-BP,

• Combined gas/steam turbine cycles that are similar to the previous cycle except that a controlled extraction-condensing steam turbine is used, CC-EC.

Each of the above cogeneration plants has its own characteristics in terms of their part-load performance curves, fuel requirement and capital and O&M cost needs. The matching of a cogeneration plant with a given rated power capacity to an MSF plant designed to produce a given amount of desalted water require knowledge not only of the technical performance and economic data of the different technologies, but also data on the annual variation of electrical and water demand on the site on which the plant is to be constructed.

This paper reviews the technical and economic characteristics of the cogeneration plants currently commercially available as well as the cost parameters for both cogeneration and desalination plants. A methodology for selecting the optimal arrangement of cogeneration plant for a particular power and desalination capacity is described and an example is given to demonstrate the use of the method.

2. Performance indices of cogeneration plants

2.1. Power to water ratio

Typical power to water ratio for different cogeneration plants are shown in Table 1 [1]. The

PWR does not only depend on the type prime mover (type of cogeneration plant) but also on the performance ratio, PR, of the desalination plant. The lower the PR of the desalination plant, the higher will be the PAV ratio of the combined cogeneration/desalination plant and the reverse is true. The effect of the PR on the PWR of four cogeneration systems (namely, BP-ST, EC-ST, GT-HRSG and CC-BP) is shown graphically in Fig. 1. In this figure, three bands represent the range of change of PWR for the ST-BP, GT- HRSG and CC-BP configurations; the field of change for the EC-ST configuration is repre- sented by the total area above the ST-BP band.

Table 1 Typical design power to water ratio for cogeneration plants

Prime mover Power to water ratio

Backpressure steam turbine - 4-7 MSF (BP-ST)

Extraction/condensing steam 4-19 turbine- MSF (EC-ST)

Gas turbine - unfired HRSG- 6-13 MSF (GT-HRSG)

Combined gas turbine, HRSG, 9-18 backpressure steam turbine (CC- BP)

2.2. Fuel energy savings ratio

Another performance criterion developed for cogeneration plants involves comparison between the fuel required to meet the given loads of electricity and heat in the cogeneration plant with that required in separate conventional plant designed to meet the loads, say in a conventional boiler to meet the heat load for desalination and a conventional power station to meet the electrical load. For a cogeneration plant producing net electrical power, P, and an amount of process heat, Qp, and consuming an amount of fuel

A.M. EI-Nashar / Desalination 134 (2001) 7-28 9

"]

4 ~ 6 1 $ 9 Pefformanceratio, PR

Fig. 1. Power to water ratio for different cogeneration plants (note that the PWR range for the EC-ST plants covers the whole area above the BP-ST band).

energy (Qr)cog, the fuel energy saved, AQf, is

AQ: = Q--LP + P - (Q:)cog (1) rh rL

The fuel energy savings ratio (FESR) is def'med as the ratio of the saving (AQf) to the fuel energy required in the conventional plants.

AQ : rL I rlcog FESR = = 1 (2)

I Q p + P ) [1 + (Z~orL/r/b)]

r/b rL

where ~og = (Qp/P) is the heat to power ratio in MWacq~4Wel, r/c is the thermal efficiency of the conventional power plant, rkog = [P/(Q[)~og] is the efficiency of the cogeneration plant, r/n is the efficiency of the conventional boiler. Typical values of these parameters for different cogeneration plants are shown in Table 2.

2.3. Net heat rate

A cogeneration facility producing electricity and thermal energy for desalination (or other purposes) will use more fuel than would be required by a conventional electric power plant producing only its electric output, or by a conventional boiler producing only its thermal output, but less fuel than would be required by

both such conventional plants producing those outputs separately.

It is customary to treat the eogeneration system as if the energy required to produce steam is the same as if that steam had been produced in a conventional boiler supplying steam to a desalination plant. The incremental cogeneration fuel energy, over and above the amount that would have been required to produce the same amount of steam in a boiler, is considered to be used to produce electric power, and is referred to as the Net Heat Rate (NHR). This concept allocates all of the cogeneration fuel efficiency advantage to the electric generation portion of the eogeneration cycle. Thus, the NHR can provide an effective means of determining the incremental performance due to the addition of the power generation (cogeneration) system to a system producing only steam. This permits assessment of potential economic benefits of competing cogeneration technologies, provided that the cogeneration technology uses the same fuel as that used to generate process steam in the non-cogeneration case.

By defmition, the net heat rate is defined as follows:

P

Typical NHR values for different cogeneration plant types and the corresponding fuel savings are shown in Table 3 which clearly indicate that the potential fuel saving is largest for the back pressure steam turbine cogeneration plant and the combined cycle with back pressure steam turbine plant.

3. Commercially available cogeneration technologies and their performance

In the following sections the performance at different loads for each of the major cogeneration

10 A.M. El-Nashar / Desalination 134 (2001) 7-28

Table 2 Characteristics of different cogeneration plants

Plant type Efficiency r a n g e Heat/power ratio range FESR range

Backpressure steam turbine 20-25

Extraction/condensing steam turbine 25-30

Gas turbine/HRSG 25-35

Combines cycle 0.35-0.45

2-5 0.05-0.4

0-3 0-0.3 1.6-3.6 0.2-0.3

0.8-2.5 0.3-4).4

Table 3 Typical Net Heat Rate values for various cogeneration and power-only cycles

System configuration NHR (MWth/MW,0 Fuel savings per MW year* 1000's SCM of natural gas

Cogeneration systems

Backpressure steam turbine

Extraction/condensing steam turbine

Gas turbine/HRSG

Combined cycle with BP steam turbine

Combined cycle with extr./cond, steam turbine

Utility power-only systems

Boilers with steam turbines

Simple-cycle gas turbine

Combined cycles

1.2-1.4 1,300-1,400

1.5-3 0-1,200

1.6-1.9 800-1,100

1.5-1.8 1000-1,200

1.8-2.6 250-1000

He~ rate (MWt~VIWe0 2.7-3.5 NA 3.0-4.1 NA

2.32.7 NA

* Annual fuel savings (in thousands of standard cubic meter of natural gas) compared to 82% efficient gas-fired boiler, and heat rate of 2.9 MWtdMWel with steam turbine operating 8400 h per year. NA = not applicable

systems will be outlined. Six cogeneration options are chosen: • Back pressure steam turbine connected to

MSF desalination (BP-ST), • Controlled extraction steam turbine connected

to MSF desalination (EC-ST), • Gas turbine with unfired heat recovery steam

generator connected to MSF desalination (GT- HRSG),

• Gas turbine with supplementary fired heat recovery steam generator connected to MSF desalination,

• Combined cycle gas turbine with back pressure steam turbine discharging to MSF desalination (CC-BP),

• Combined cycle gas turbine with controlled extraction condensing steam turbine with extraction steam supplied to MSF desalination (CC-EC).


For each of these options, the part-load performance will be shown using data from typical plants using current technology. The desalination plant is assumed to operate at full load irrespective of the electrical load variation.

3.1. Back-pressure steam turbine connected to desalination plant (BP-ST)

Natural gas can be burned in a fired boiler to produce high-pressure superheated steam. This steam can be fed to a back-pressure steam turbine to produce power. The exhaust from the steam turbine will feed a desalination plant to produce desalinated water. Feed water heating utilizing extractions from the steam turbine are used to improve overall plant efficiency.

Part load performance can be achieved by bypassing some of the steam around the steam turbine. To reduce steam turbine load, steam turbine throttle valves must start to close to reduce the amount o f steam flowing through the turbine. This plant would require a dump condenser to allow maximum power production when a desalination unit is out of service. In a plant consisting of a series of boiler/turbine/desalination

unit trains, a common header feeding the desalination units is normally installed, with a single dump condenser being required to handle the excess steam supplied to the header in the event of a desalination unit outage.

Performance information for a typical CC-ST eogeneration plant is shown in Table 4. The plant has a rated power capacity of 98 MW and can produce about 18 MIGD from MSF units having a performance ratio, PR, of 8.0. The part-load heat rate ratio (defined as the heat load at any load divided by the design heat rate) for this plant is shown in Fig. 2, which shows the large drop in the heat rate as the plant load increases.

The NHR and PWR for different electrical loads for the BP-ST cogeneration plant are shown in Figs. 3 and 4. It is assumed that while the electrical load on the plant is allowed to vary, the thermal load, and hence the water production, remains constant at its rated value. The large increase in the NHR with decreasing the load is due mainly to the use of part of the boiler steam for desalination (after passing through a reducing valve to reduce its pressure). The PWR, as expected, increases linearly with the load but depend on the performance ratio, PR, of the desalination plant.

Table 4 Part-load performance of back-pressure steam turbine cogeneration plant (BP-ST) connected to desalination unit having a performance ratio PR = 8.0

ST gross output, kW Power auxiliary loads, kW Net power output, kW Load, % Fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV Exhaust steam to desal, lb/h Bypass steam to desal, lb/h Total steam to desal, lb/h Desal. production, MIGD Desal. auxiliary load, kW

97,950 82,725 52,100 25,250 13,130 5,500 5,050 4,010 2,790 2,010 92,450 77,675 48,090 22,460 11,120 100 84 52 24 12 1498.5 1437.9 1311.8 1202.5 1151.2 16,208 18,511 27,278 53,540 103,524 973,000 834,000 558,000 291,000 162,000 0 139,000 4 1 5 , 0 0 0 682,000 811,000 973,000 973,000 973,000 973,000 973,000 17.92 17.92 17.92 17.92 17.92 13,560 13,560 13,560 13,560 13,560


7

¢ 6 .p

d 5

4 2 =c li

0 0 2b ~0 6b dO 160

Percent load

Fig. 2. Heat rate ratio of backpressure cogeneration plant supplying constant steam flow to a desalination unit having a performance ratio 8.0.

t .4

~ 1 . 3 8

g ~ 1.3s

I D " . c ~ 1,32

z 1,28

0 20 40 60 ,80 100 Percent load

Fig. 3. Net heat rate for BP-ST cogeneration plant.

3.2. Extraction-condensing steam turbine connected to desalination plant

These units produce still more power by replacing the backpressure turbine with an extraction/condensing steam turbine. A controlled extraction port on the steam turbine will maintain proper steam flow and pressure for the desalination units. Desalinated water production is reduced by about 40% from the backpressure steam turbine case, since some steam flow is required to flow through the low-pressure condensing section of the steam turbine, and since additional feedwater heaters are used to further improve cycle efficiency. As in the case of a backpressure steam turbine, substantial turndown can be achieved by bypassing steam around the steam turbine. Performance information for this technology is found in Table 5 for a plant with a net power output of 116 MW connected to an MSF plant having a capacity of 12.6 MIGD (that is PWR = 9.2).

The heat rate ratio for different loads is shown in Fig. 5, which as for the BP-ST technology exhibits a dramatic increase in the heat rate at part load. The reason is the need for bypass steam to supplement the extraction steam, which for blade cooling reasons, has to be reduced at very small loads.

6

4 r,,

3 ¢L 2

1

o

. . . . Pe==e,o

20 40 60 io lOO Percent load

Fig. 4. Power to water ratio for BP-ST cogeneration

plant supplying constant steam to desalination.

14,

12" r. 2: 10,

_d 8"

-I- 2.

0 t ' " ' " ' " " " ' ' ' |

0 2b 4o eo io 10~ Percent load

Fig. 5. Performance of EC-ST cogvnvration plant with constant steam to desalination. (Performance ratio PR = 8.0)

A.M. El-Nashar / Desalination 134 (2001) 7-28 13

Table 5 Part-load performance of extraction/condensing steam turbine cogeneration plant (EC-ST) with constant steam supply to desalination. Performance ratio, PR = 8.0

Plant gross output, kW Power auxiliary loads, kW Net output, kW Load, % Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV Extr. steam to desal, lb/h Bypass steam to desal, lb/h Total steam to desal, lb/h Desal production, MIGD Desal auxiliary load, kW

125,000 93,200 72,700 54,350 - 8,730 7,920 7,490 7,720 4,000 116,270 85,280 65,210 46,630 4,000 100 73 56 40 3 1593.7 1291.4 1111.2 1196.7 726.1 13,707 15,143 17,041 25,664 181,527 683,417 6 8 3 , 4 1 7 6 8 3 , 4 1 7 418,836 0 0 0 0 264,581 683,417 683,417 6 8 3 , 4 1 7 6 8 3 , 4 1 7 6 8 3 , 4 1 7 683,417 12.59 12.59 12.59 12.59 12.59 9,520 9,520 9,520 9,520 9,520

The net heat rate and power-to-water ratio at part-load for this technology is shown in Figs. 6 and 7, respectively. It can be seen that the net heat rates are higher than the values for the BP-ST option. Also, as was shown before, higher PWR values can be obtained for the EC-ST plant compared to the BP-ST one.

Note that this plant is designed for a power to water ratio ( P W R ) of about 9 MW/MIGD, but lower PWR's are possible. However, as PWR approaches 5 MW/MIGD, they are reaching the PWR ofbackpressure steam turbine plants. Lower values of PWR can be achieved by reducing the

2.5

z

4 0 60 80 100 Percent load

Fig. 6. Net heat rate for a typical EC-ST cogeneration plant.

extraction steam flow and complementing it with bypass steam.

3.3. Gas turbine plus unfired heat recovery steam generator plus auxiliary boiler connected to desalination plant (G T-HRSG)

These units produce power in a virtually identical manner to simple cycle gas turbines. However, the waste heat exhausting from the gas turbine is captured in an unfh'ed HRSG, where steam is produced for export to a desalination plant. The amount of steam produced by the

10.

ei

6"

2.

0 ¸ 0 4b 8'0"'

Percent load

Fig. 7. Power to water ratio of extraction/condensing steam turbine cogeneration plant supplying constant steam to desalination.


HRSG is a function of the energy in the gas turbine exhaust. As gas turbine load is reduced to match reduced load demand, the corresponding HRSG steam production is reduced. Since desalinated water production must remain constant, auxiliary boiler steam must be produced to main a constant steam flow to the desalination unit. Performance information for this technology is

shown in Table 6 for a plant having a net power output of 94 MW connected to an MSF plant having a rated production of 10.8 MIGD.

The heat rate ratio, HRR, for a typical GT- HRSG cogeneration plant is shown in Fig. 8 which also shows a dramatic increase at part loads. The NHR is shown in Fig. 9.

Table 6 Part-load performance of a gas turbine, unfired HRSG, auxiliary boiler (GT-HRSG) with constant steam to desalination. Performance ratio PR = 8.0

Ambient temperature, °C 50 50 50 50 50 50

GT gross output, kW 95,730 8 3 , 5 4 0 6 5 , 7 0 0 4 7 , 1 8 0 27,480 6,740 Power auxiliary load, kW 1,910 1,780 1,580 1,340 1,020 510

Net output, kW 93,820 81 ,760 6 4 , 1 2 0 4 5 , 8 4 0 26,460 6,230

Load, % 100 87 68 49 28 7 GT fuel input, MMBtu/h HHV 1154.7 1027.2 847.4 680.3 517.3 361.7

Aux. boiler fuel input, MMBtu/h HHV 0 101.8 227.1 346.1 451.7 546.8

Total fuel input, MMBtu/h HHV 1154.7 1129.0 1074.5 1026.4 969.2 908.5

Heat rate, Btu/kWh HHV 12,308 13 ,809 16 ,758 2 2 , 3 9 0 3 6 , 6 2 8 145,828

HRSG steam to desal., lb.h 586,300 500,000 386,400 278,000 179,000 93,000

Aux. boiler steam to desal., lb/h 0 86,300 199,900 308,300 407,300 493,000

Total steam to desal., lb/h 586,300 586,300 586,300 586,300 586,300 586,300 Desal. production, MIGD 10.8 10.8 10.8 10.8 10.8 10.8

Desal. aux. load, kW 8,170 8,170 8,170 8,170 8,170 8,170


GT gross output, kW 113,000 102,410 82 ,900 6 2 , 2 7 0 4 0 , 5 8 0 17,290

Power auxiliary load, kW 2,260 2,200 1,980 1,710 1,380 900

Net output, kW 110,740 100,210 80 ,920 6 0 , 5 6 0 3 9 , 2 0 0 16,390

Load, % 100 90 73 55 35 15 GT fuel input, MMBtu/h HHV 1299.0 1186.8 986.4 797.6 616.6 441.7 Aux. boiler fuel input, MMBtu/h HHV 0 85.5 230.6 364.7 481.2 587.9


Heat rate, Btu/kWh HHV 11,730 1 2 , 6 9 6 15 ,040 19 ,192 2 8 , 0 0 5 62,821

HRSG steam to desal., lb.h 586,300 513,800 383,300 261,400 152,400 56,200

Aux. boiler steam to desal., lb/h 0 75,500 203,900 324,900 433,900 530,100 Total steam to desal., lb/h 586,300 586,300 586,300 586,300 586,300 586,300 Desal. production, MIGD 10.8 10.8 10.8 10.8 10.8 10.8

Desal. aux. load, kW 8,170 8,170 8,170 8,170 8,170 8,170

A.M. El-Nashar / Desalination 134 (2001) 7-28 15

12

n, lO . 3 :

d 8,

4,

"1". 0

4:o do Percent load

eb" 1'do

Fig. 8. Heat rate ratio of gas turbine, unfired HRSG, auxiliary boiler cogeneration plant with constant steam supply to desalination. Performance ratio, PR = 8.0.

3.4. Gas turbine plus supplementary-fired heat recovery steam generator connected to desalination plant

These units operate very similar to units with gas turbines and unfired HRSG's. However, as load is reduced on the gas turbine (and gas turbine exhaust energy decreases), gas-fired burners in HRSG inlet duct are fked to keep the steam production to the desalination unit constant. Gas turbines would be operated with their inlet guide vanes kept in the fully open position even as load is reduced. This will maintain exhaust flow from the gas turbine constant as gas turbine load drops. Gas turbine exhaust temperature will drop sub, stantially as gas turbine load drops, and thus the HRSG duct burner can be fired to increase the

12 • r4 ¢ 10. z

d

S.

~ 4.

,,p 2,

0 w ........ I~' 0 100

, , , , , , , r , , , , , , , , , , , , , , , , , ,

zo 40 6'0 8'o Percent load

Fig. 10. Heat rate ratio of gas turbine, supplementary fired HRSG cogeneration plant supplying constant steam to desalination. Performance ratio PR = 8.0.

12,

. ® 1 0 '

Z 2,

o o

, , , , , , / ,

20 4b Percent load

Fig. 9. Net heat rate for GT/unfired HRSG eogeneration plant.

gas turbine exhaust temperature up to its original full-load value. This maintains HRSG steam production at its original full-load value over the entire operating range of the gas turbine. Modu- lating dampers on the HRSG are not required. Performance information for this technology is given in Table 7. The HRR, NHR and PWR for this technology are shown in Figs. 10, 11 and 12, respectively.

3. 5. Gas turbine plus supplementary-fired heat recovery steam generator plus backpressure steam turbine connected to desalination plant (CC-BP)

These units produce additional power by adding a backpressure steam turbine. Desalinated

8"

5-

O ~ Z - r 2 "

Z t

0 Percent load

Fig. 11. Net heat rate of GT/supplementary-fired HRSG cogeneration plant.


water production is reduced by about 30% since higher pressure steam is generated in the HRSG to allow sufficient steam turbine power production. Substantial power turndown can be achieved by reducing gas turbine load and increasing HRSG duct burner firing. Steam turbine load remains essentially constant.

For a plant with a backpressure steam turbine, consideration needs to be given to a desalination unit going out of service. If it were desired to maintain maximum power production, a dump condenser would be required. In a plant consisting of a series of gas turbine/HRSG trains, a

Table 7

common header feeding a single steam turbine would be envisaged, with the steam turbine exhausting into a common header feeding the desalination units. A single dump condenser would be required to handle the excess steam supplied to the header in the event of a desalination unit outage. Performance information of this technology is given in Table 8. High power to water ratios of about 16 can be achieved with this technology. The part-load heat rate and net heat rate for this technology is shown in Figs. 12 and 13, respectively, and the power to water ratio is shown in Fig. 14.

Part-load performance of gas turbine, fired HRSG cogeneration plant with constant steam supply to desalination. Performance ratio PR = 8.0


GT gross output, kW 95,730 8 3 , 5 4 0 6 5 , 7 0 0 4 7 , 1 8 0 27,480 6,740 Power aux. load, kW 1,910 1,780 1,580 1,340 1,020 510

Net output, kW 93,820 8 1 , 7 6 0 6 4 , 1 2 0 4 5 , 8 4 0 26,460 6,230 % Load 100 87 68 49 28 7 GT fuel input, MMBRgh HHV 1154.7 1027.2 847.4 680.3 517.4 361.7 Duct burner fuel input, MMBtu/h HHV 0 83.9 190.0 289.1 377.2 454.2

Total fuel input, MMBtu/h HHV 1154.7 1 1 1 1 . 2 1037.4 969.4 894.7 815.9 Heat rate, Btu/kWh HHV 12,308 13,591 16,178 2 1 , 1 4 8 3 3 , 8 1 2 130,967

Steam to desal., lb/h 586,300 586,300 586,300 586,300 586,300 586,300 Desal. production, MIGD 10.8 10.8 10.8 10.8 10.8 10.8 Desal. aux. load, kW 8,170 8,170 8,170 8,170 8,170 8,170


GT gross output, kW 113,000 102,410 8 2 , 9 0 0 6 2 , 2 7 0 4 0 , 5 8 0 17,290 Power aux. load, kW 2,260 2,200 1,980 1,710 1,380 900

Net output, kW 110,740 100,210 8 0 , 9 2 0 6 0 , 5 6 0 3 9 , 2 0 0 16,390 Load, % 100 90 73 55 35 15 GT fuel input, MMBtu/h HHV 1299.0 1186.8 986.4 797.6 616.6 441.7 Duct burner fuel input, MMBtu/h HHV 0.0 68.8 189.6 299.5 397.1 483.1 Total fuel input, MMBtu/h HHV 1299.0 1 2 5 5 . 6 1176.0 1097.1 1013.6 924.8

Heat rate, Btu/kWh HHV 11,730 1 2 , 5 3 0 1 4 , 5 3 2 1 8 , 1 1 5 2 5 , 8 5 8 556,425 Steam to desal., lb/h 586,300 586,300 586,300 586,300 586,300 586,300 Desal. production, MIGD 10.8 10.8 10.8 10.8 10.8 10.8 Desal. aux. load, kW 8,170 8,170 8,170 8,170 8,170 8,170

A.M. El-Nashar ~Desalination 134 (2001) 7-28 17

Table 8 Gas turbine, supplementary fired HRSG, Performance ratio PR = 8.0

backpressure steam turbine supplying constant steam flow to desalination.


GT gross output, kW 95,730 8 3 , 5 4 0 6 5 , 7 0 0 4 7 , 1 8 0 27,480 6,740

ST gross output, kW 31,050 3 1 , 3 1 0 3 1 , 2 9 0 3 1 , 2 7 0 3 1 , 2 4 0 31,190

Plant gross output, kW 126,780 114,850 96 ,990 7 8 , 4 5 0 5 8 , 7 2 0 37,930

Power aux. load, kW 2,540 2,420 2,220 2,000 1,730 1,390

Net output, kW 124,240 112,430 94 ,770 7 6 , 4 5 0 5 6 , 9 9 0 36,540

Load, % 100 90 76 62 46 29

GT fuel input, MMBtu/h HHV 1154.7 1027.2 847.4 680.3 517.4 361.7

Duct burning fuel input, MMBtu/h HHV 0 86.7 192.7 290.9 379.1 455.1

Total fuel input, MMBtu/h HHV 1154,7 1113.9 1040.1 971.2 896.5 816.9

Heat rate, Btu/kWh HHV 9,294 9,908 10,975 12,704 15,731 22,355

Steam to desal., lb/h 428,298 428,298 428,298 428,298 428,298 428,298

Desal. production, MIGD 7.89 7.89 7.89 7.89 7.89 7.89

Desal. aux. load, kW 5,970 6,000 6,000 5,990 5,990 5,980


GT gross output, kW 113,000 102,410 82 ,900 6 2 , 2 7 0 4 0 , 5 8 0 17,290

ST gross output, kW 30,700 3 0 , 6 9 0 3 0 , 7 7 0 3 0 , 7 7 0 3 0 , 7 8 0 30,790

Plant gross output, kW 143,700 133,100 113,670 93 ,040 7 1 , 3 6 0 48,080

Power aux. load, kW 2,870 2,830 2,610 2,360 2,070 1,700

Net output, kW 140,830 130,270 111,060 90 ,680 6 9 , 2 9 0 46,380

Load, % 100 93 79 64 49 33 GT fuel input, MMBtu/h HHV 1299.0 1186.8 986.4 797.6 616.6 441.7

Duet brning fuel input, MMBtu/h HHV 0 72.3 193.8 303.5 401.1 487.2


Heat rate, Btu/kWh HHV 9,224 9665 10,627 12,143 1 4 , 6 8 7 20,027

Steam to desal., lb/h 427,900 427,900 427,900 427,900 427,900 427,900

Desal. production, MIGD 7.88 7.88 7.88 7.88 7.88 7.88

Desal. aux. load, kW 5,960 5,950 5,960 5,960 5,960 5,960

3.6. Gas turbine plus supplementary-fired heat recovery steam generator plus extraction~condensing steam turbine connected to desalination plant (CC-EC)

These units produce still more power by replacing the baekpressure turbine with an extraction/condensing steam turbine. A controlled extraction port on the steam turbine will

maintain proper steam flow and pressure for the desalination unit. Desalinated water production is reduced by about 15% from the backpressure steam turbine case, since some steam flow is required to flow through the low-pressure condensing section of the steam turbine. As in the case of a backpressure steam turbine, substantial power turndown can be achieved by

18 ,4.M. EI-Nashar / Desalination 134 (2001) 7-28

18 10 PR=8.0 ~ 16

8 ~ 14

o zb io go 160 °o Percent load

Fig. 12. Power to water ratio at part load for gas turbine with supplementary fired HRSG supplying constant steam flow to desalination. Performance ratio PR =8.0 and 10.0.

4o sb ao 160 Percent load

Fig. 15. Power to water ratio at different loads for

combined cycle cogeneration plant with backpressure steam turbine cogeneration plant supplying constant steam flow to desalination. Performance ratio PR = 8.0

3,

¢ 2.5, n~ -r d 2,

1.5

_~ o,s. 0 2 0 6b ~o i60

Percent load

Fig. 13. Heat rate ratio for gas turbine, supplementary fired HRSG, backpressure steam turbine cogeneration supplying constant steam flow to desalination. Performance ratio PR =8.0.

3

is4

z O,

2O 4"o 6o 80 16o Percent load

Fig. 14. Net heat rate for combined cycle with backpressure steam turbine cogenoration plant.

reducing gas turbine load and increasing HRSG duct burning f'Lring. Steam turbine load remains essentially constant. Performance information for this technology is shown in Table 9. The HRR, NHR and PWR at part load are shown in Figs. 16, 17 and 18, respectively.

4. Capital and operating costs of commercial cogeneration plants

The prime movers most commonly used in contemporary large cogeneration systems, and likely to be the dominant prime movers for the foreseeable future, are steam turbines, gas turbines and combined cycle plants. Other prime movers

2,5 -

:Z: 2-

1.5-

E-- o 1-

=. 0.5- 0 -r

0 2O do io lh0

Percent load Fig. 16. Heat rate ratio for gas turbine, supplomenlary-fired HRSG, extraction condensing steam turbine cogene~on plant supplying constant steam to desalination. Performance ratio PR = 8.0.

A.M. EI-Nashar ~Desalination 134 (2001) 7-28 19

3 . 5 ~ A

~ 3" ~ I 2.5,

2. 1.5,

z 0.5. 0 20

Percent load

211 P.--. .o . . . . . . . PR=IO.O . .

o !

20 4"0 (~0 8() 100 Percent load

Fig. 17. Net heat rate for combined cycle cogeneration plant with extraction/condensing steam turbine.

Table 9

Fig. 18. Power to water ratio for gas turbine, supplementary fired HRSG, extraction/condensing steam turbine cogeneration plant supplying constant steam flow to desalination. Performance ratio PR = 8.0.

Part-load performance of gas turbine, supplementary fired HRSG, extraction/condensing steam turbine (CC-EC) cogeneration plant supplying constant steam flow to a desalination unit. Performance ratio PR = 8.0


GT gross output, kW 95,730 8 3 , 5 4 0 6 5 , 7 0 0 4 7 , 1 8 0 27,480 6,740 ST gross output, kW 33,200 3 3 , 5 8 0 3 3 , 5 4 5 3 3 , 5 2 0 33,465 33 Plant gross output, kW 128,930 117,120 9 9 , 2 4 5 8 0 , 7 0 0 6 0 , 9 4 5 40,135 Power aux. load, kW 3,440 3,280 3,020 2,730 2,370 1,920 Net output, kW 125,490 113,840 9 6 , 2 2 5 7 7 , 9 7 0 5 8 , 5 7 5 38,215 Load, % 100 91 77 62 47 30 GT fuel input, MMBtu/h HHV 1154.7 1027.2 847.4 680.3 517.4 361.7 Duct burning fuel input, MMBtu/h HHV 0 86.7 192.7 290.9 379.1 455.1 Total fuel input, MMBtu/h HHV 1154.7 1113.9 1040.9 971.2 896.5 816.9 Heat rate, Btu/kWh HHV 9,202 9,785 10,807 1 2 , 4 5 7 1 5 , 3 0 5 21,375 Steam to desal., lb/h 360,000 360,000 360 ,000 360 ,000 360,000 360,000 Desal. production, MIGD 6.63 6.63 6.63 6.63 6.63 6.63 Desal.aux. load, kW 5,020 5,020 5,020 5,020 5,020 5,020


GT gross output, kW 117,280 102,410 8 2 , 9 0 0 62,270 40,580 17,290 ST gross output, kW 36,220 3 3 , 3 6 0 3 3 , 4 8 0 3 3 , 4 8 5 3 3 , 4 9 5 33,500 Plant gross output, kW 153,500 135,770 116,380 9 5 , 7 5 5 7 4 , 0 7 5 50,790 Power aux. load, kW 3,840 3,610 3,340 3,030 2,670 2,210 Net output, kW 149,660 132,160 113,040 9 2 , 7 2 5 7 1 , 4 0 5 48,580 Load, % 100 88 76 62 48 32 GT fuel input, MMBtu/h HHV 1342.8 1186.8 986.4 797.6 616.6 441.7 Duct burning fuel input, MMBtu/h HHV 0.0 72.3 193.8 303.5 401.1 487.2 Total fuel input, MMBaffh HHV 1342.8 1259.1 1180.2 1101.1 1017.7 928.9 Heat rate, Btu/kWh HHV 8,972 9,527 10,440 11,875 1 4 , 2 5 2 19,920 Steam to desal., lb/h 360,000 360,000 360,000 360 ,000 360,000 360,000 Desal. production, MIGD 6.63 6.63 6.63 6.63 6.63 6.63 Desal.aux. load, kW 5,020 5,020 5,020 5,020 5,020 5,020

20 A.M. E1-Nashar / Desalination 134 (2001) 7-28

such as fuel cells and Stifling engines are in various stages of development but are expected to see little general commercial application in the near future. In this paper, we will focus primary attention on the commercially available techno-

Table 10 Cogeneration technologies capital and operating costs

logics, which account for essentially all major cogeneration facilities for power and desalination. The range of capital costs for several eogeneration and desalination technologies is shown in Tables 10 and 11, respectively.

Cogeneration technology Capital cost, Fixed O&M cost, Variable O&M cost, Expected lifetime, $/kW $/kW S/kWh years

BP steam turbines Ext./cond. steam turbines Gas turbine/HRSG Combined cycle with BPST Combined cycle with ECST

750-1000 40 0.0035 25-35 650-900 32 0.0035 25-35 450-600 43 0.0023 20 550-850 43 0.0023 15-25 500-800 43 0.0023 15-25

Table 11 Desalination technology capital and operating costs

Desalination technology Capital cost, $/GPD O&M cost, $/m 3 Expected lifetime, years

MSF 4.0-12.0 0.1 25 MED 3.5-8.0 0.1 25 TVC 3.5-8.0 0.1 25

5. Optimal selection of cogeneration plant to match power and water demands

One of the reasons that it is difficult to stan- dardize cogeneration plants is the wide diversity of water and power requirements of different cogeneration plants as typified by the power to water ratio. Options in sizing a cogeneration system to match a given demand power-to-water ratio is demonstrated in the Power-Water graph of Fig. 19. Two plots are shown in this figure, one for a cogeneration plant having a high PWR such as a gas turbine/HRSG system and the other one with a low PWR such as a backpressure steam turbine system. Point D represents the power and

water demands and points P and W represent, respectively, a plant that matches the power demand only and a plant that matches the water demand only.

I f the demand power to water ratio is smaller than that of the selected technology, such as in case (a), the selected plant should match the power demand (point P) with the shortfall in water production supplemented by an auxiliary boiler. On the other hand, if the demand PWR is higher than that of the selected cogeneration technology as in case (b), the selected plant (point W) should match the water demand with the shortfall in power production supplied by a power-only plant.


Power (a) High P/W ratio Power (b) Low PAV ratio

P

.... " ~ Aux. boiler'~----~i

D = demand point P = match power demand W = match water demand

Water

plant ]~ W [

Water

Fig. 19. Matching eogeneration system side to power and water demand.

The selection of the optimal cogeneration facility from among a number of options is usually carried out using a computer model. It is assumed that the nominal capacity of the required eogeneration plant is known (both power and water production rates) based on the estimated demand for power and water at the site. The performance and cost parameters of a number of possible plant configurations are among the input parameters that are required by the program. On any one computer run, the program computes the life cycle cost, LCC, of all discounted cash flows for a series of user-supplied unit sizes and the plant with the lowest LCC value is selected.

A computer model for selecting the optimum cogeneration plant with a given nominal power and water rates is shown in Fig. 20. The model is designed to select the optimum cogeneration system size for a specific site where the electrical and water demands are specified throughout the year. The selected system is specified by the following three design parameters: • The cogeneration system size • The number of cogeneration units • The size of the auxiliary boiler if needed.

The selection is made from a user's desired spectrum of different sizes and different number

of units that are to be investigated. In addition to the sizes and number of units, equipment data such as cost and performance of each piece of equipment; economic data such as financing method, fuel cost, etc; plant load data such as electrical and water load variation throughout the year; and weather data such as ambient temperature and pressure are also required as input to the program.

5.1. Economic considerations

The determination of the preferred cogeneration system to satisfy a certain power and water demand involves examining numerous alternatives each for a particular configuration; the final system specification is the result of an extensive trade-off economic analysis.

The economic value of a proposed cogeneration system typically is determined by predicting a series of future cash flows and then evaluating these cash flows according to an agreed-upon set of criteria or indicators. The LCC method is the most frequently utilized and widely accepted investment analysis technique. It is based on a discounted cash flow analysis without regard to eventual financing slrategies. The LCC method recognizes that a capital investment by a utility is

22 AM. El-Nashar / Desalination 134 (2001) 7-28

i F~m~mg m~wd Tam, ~ : ~ !

6mw~ m ~ _ F ~ c~st

I ~ ~ e ~

, Difftgeut numl~ofmliis

I . E ~ ~ , ,

! / ~ . i I

W U load

/ . ~ ~ \ / ' ~ ~ )

• ~ s i z e • la i~ iavman~ • Fir~mcing

• ~ f l o w

Fig. 20. Optimization model for cogeneration plant.


a cash outlay for the purpose of producing a stream of future cash revenues (or expense savings) sufficient to recover, or repay, the investment plus a return.

The economic analysis of a cogeneration facility, as any industrial project, requires a set of assumptions concerning general economic con- ditions and ground rules, current and future. The primary ground rules that must be established for an economic cash flow analysis are: • The economic life of the facility • The first year of operation • The number of years of construction • The general inflation rate • The inflation rate for fuel and O&M expenses

The economic life of cogeneration systems is typically 15 to 25 years and is ultimately limited by the equipment life. This economic life is the period of time over which an investment is evaluated to determine its benefits and returns. The number of years of construction, the first year of operation, the general inflation rate, and other specific rates and escalations are parameters used to define the investment and operating costs of a cogeneration facility.

The life cycle cost analysis method is used to determine the most cost effective cogeneration option by comparing the total present worth of all costs incurred through out the lifetime of the plant. The life-cycle cost of a cogeneration plant producing electricity and steam is the sum of the initial cost plus the total present worth of annual costs. The initial cost includes the cost of the power generating equipment and the desalination equipment, engineering, installation and project management. Thus the initial cost can be expressed as

(IC):og =(1 + d + e + f)T~og (4)

where Tcog is the total hardware cost (power generation plus desalination equipment ), d , e,

and f are cost ratios for engineering, installation and project management, respectively.

The present worth of annual costs include annual fuel costs and O&M costs. The present worth of these costs can be expressed as [12]:

PWf-Cfo (.+gf /[1 (l+gf/'v] - t .k_g ' )[ -t, 1-77-k) J

( 1 + g°" )[1 - (! + g°" f ] PWo,. =Co,0 k _ g o , l + k

(5)

where PWf- present worth of fuel costs, $; PWom - present worth of O&M costs, $; C~ - fuel cost in the first year, $; Como- O&M cost in the first year, $; gr - fuel escalation rate; gore- O&M escalation rate; k - money interest rate; N - system life, years.

The life-cycle cost of the cogeneration plant, (LCC)~og, is obtained as the summation of the initial plant cost and the present worth of all annual recurring costs:

+(Pw,) (6)

where (P~f'f)cog and (PWom)~og are given by

l+go~ l+go~

(7)

where (Cf)0- fuel cost during the first year of operation, $; (Com)~ogo - O&M cost during the first year of operation, $; g f - fuel escalation rate; gore - escalation rate of O&M expenses; k - interest rate; N - equipment lifetime, years.

The life cycle cost of a desalination plant, consists only of capital amortization and O&M costs since the cost of steam and electricity used by the desalination plant is born by the system as

24 A.M. EI-Nashar / Desalination 134 (2001) 7-28

a whole and does not involve the consumption of additional external resources:

(Lcc).es=(lC)..s + (,' rvo. )..s

where (IC)a~, - initial capital of desalination plant, $; (PWom)a,s - present worth of O&M costs of desalination plant, $.

The total life cycle cost of the combined cogeneration and desalination plants is the summation of (LCCOcog and (LCC)ae,

gcC),o, =gcC)oo, + gcc) , (8)

where P - average power production, kW; H - plant availability, h/y; e, - exergy content per unit of steam, kWh/ton; C R F - capital recovery factor; m~ - average steam production, ton/h.

This equation is used to estimate the unit exergy cost of electricity and steam. The unit cost of electricity (S/kWh) is identical to the unit exergy cost of electricity (also S/kWh) since the exergy content of electricity is identical to its energy content; i.e. c, e = c,. The unit cost of steam on the other hand is different from its unit exergy cost since the exergy content of a mass of steam depends on its pressure and temperature. The unit cost of steam (S/ton) can be related to its unit exergy cost (S/kWh) by

5. 2. Cost allocation between electricity and water

The equality method of the exergy approach [13] is used for costing electricity and steam from a cogeneration plant. Based on these costs, the cost of water from the desalination plant can then be estimated using the normal economic procedure which take into consideration capital, O&M and energy costs. In the equality method the production by the cogeneration plant of the two products (electricity and steam) is considered to have the same priority, so the capital, O&M and energy costs are split between both products according to the exergy content of each. Based on this method the cost of electricity per unit exergy, ce, is equal to the cost of steam per unit exergy, Cse:

g E cs = ce (9)

The life cycle cost of a cogeneration plant which consists of capital amortization, O&M costs and energy costs can be split among the exergy content of the generated electricity and steam as follows:

(LCC)cog P.H.N.~ + = m, .H.N.esc, (10)

£ c, = c , g s (11)

Knowing the unit costs of electricity and steam, it is now possible to calculate the unit cost of water produced by the desalination plant from:

gcc), -c, .pf c. = (12)

mw .H.N

5. 3. Example

To illustrate the procedure for selecting the optimum eogeneration system from among several options, let us consider an example where it is required to install a cogeneration plant having a rated power output of 300 MW and a rated desalted water production of 50 MIGD. The plant specification and economic parameters assumed are given in Table 12.

To make things simple, the desalination system selected for this example is assumed to be MSF which seems to be appropriate for large capacities such as the one in this example. In general, other distillation technologies such as MED or TVC could be included in the selection process.


Table 12 Plant specification and economic parameters

Parameter Value

Rated power output, MW 300

Rated water production, MIGD 50

Performance ratio of MSF plant 7,8,9

Fuel cost, $/GJ 1

Plant factor 0.9

Escalation rate for fuel 0.03

Escalation rate for O&M expenses 0.03

Interest rate 0.08

Plant lifetime, year 25

Table 13 Slmeifie capital and O&M costs of the cogeneration plants

Cost parameter Specific F i x e d Variable capital cost, O&M cost, O&M cost, $/kW $&Wy $&Wh

BP-ST 1000 40 0.0035

EC-ST 950 32 0.0035

GT-HRSG 700 43 0.0023

CC-BP 800 43 0.0023

CC-EC 800 43 0.0023

MSF, PR =7-9 8--10 $/gpd 0 0.1 $/m 3

The options for plant configurations are as follows: • Backpressure steam turbine connected to MSF

(BP-ST) • Extraction-condensing steam turbine connect-

ed to MSF (EC-ST) • Gas turbine with heat recovery steam genera-

tor connected to MSF (GT-HRSG) • Combined cycle gas/baekpressure steam tur-

bine connected to MSF (CC-BP) • Combined cycle gas/extraction-condensing

steam turbine connected to MSF (CC-EC)

The assumed specific capital cost and O&M cost for each of the above cogeneration options as well as the MSF plant are shown in Table 13.

The electrical load on the cogeneration plant is assumed to vary throughout the year according to Fig. 21. This load variation is typical for other cogeneration plants operating in Abu Dhabi, UAE, and is also similar to the load patterns in other Gulf areas. The MSF desalination plant is assumed to operate at full load throughout the year. The shortfall in steam production by the cogeneration plant is assumed to be supplied by an auxiliary boiler whose capacity depends on the configuration of the plant as well as the load variation.

0

"0 g . I

0 . 8 ¸

0.6

0.4

0.2

0

Month

Fig. 21. Electrical monthly load ratios assumed for the example problem.

The annual fuel consumption for each option was estimated as the summation of the monthly fuel consumption by both the cogeneration plant and the auxiliary boiler. The monthly fuel consumption by the cogeneration plant was estimated by multiplying the monthly-average plant heat rate and monthly average load. The heat rate obviously depends on the plant load that varies throughout the year. The monthly-average fuel consumption by the auxiliary boiler is estimated from knowledge of the shortfall in the steam required by the MSF plant that cannot be supplied by the cogeneration plant.

The capital cost, present value of fuel and O&M expenditures as well as the life cycle cost for each option are shown in Table 14 which indicates that the most economic alternative is the gas turbine-heat recovery steam generator with a


life cycle cost of 1493 million $ to be followed with a small margin by the combined cycle-back pressure option. The costs shown in this table are estimated assuming that the performance ratio, PR = 9.0.

The LCC for different values of PR is shown in Fig. 22 which indicates that the LCC is quite sensitive to the PR value for each plant configuration. The BP-ST configuration shows an increasing trend for LCC with increasing the PR. However, the other configurations displays the opposite trend, i.e. the LCC decreases with increasing PR. As can be seen, the lowest LCC value is for the GT-HRSG option with PR = 9.0. The reason why the BP-ST exhibits this trend is that when the PR of the desalination plant is about 7, the annual amount of steam discharged from the BP steam turbine is just enough to supply the required amount of steam required by the desalination plant. Thus the steam turbine will match the MSF plant reasonably well. On the other hand, when the PR is larger than 7, the steam turbine will produce more steam than required by the MSF plant and hence some of this steam will have to be condensed in a dump condenser which constitutes a waste of energy. Thus increasing the PR beyond 7 for this option brings only increase in capital cost of the MSF plant and no extra benefit to the overall economy of the eogeneration plant.

The situation with the other cogeneration options is the opposite to that of the BP-ST one in that for these options, the amount of steam produced is smaller that that required by the MSF plant which make it necessary to install an auxiliary boiler to supplement the shortfall in steam requirement. The additional capital, fuel and O&M expenses associated with this boiler contributes to a high LCC value for the whole cogeneration plant. The increase in the performance ratio of the MSF plant can relieve this situation by reducing the capacity of the auxiliary boiler required as well its associated fuel and O&M expenses thus help to reduce the LCC.

Table 14 Life cycle costs of the different cogeneration options (PR = 9)

Cost Capital PV fuel, PV O&M, Life cycle parameter cost, $10 6 $106 $106 cost, $10 6

BP-ST 800 552 194 1547 EC-ST 803 465 266 1534 GT-HRSG 727 533 233 1493 CC-BP 772 439 292 1503 CC-EC 775 459 303 1537

PV = present value

18e0

1580

15S0

1GO

1620

--~ 1500

BP-ST EC-ST GT-HRSG CC-BP CC-EC c o o . ~ l o , ol:t~n

Fig. 22. Life cycle cost for different performance ratio.

The unit cost of electricity and water is shown in Figs. 23 and 24, respectively. The optimum cogeneration option (GT-HRST at PR=9) results in a unit cost of electricity of 2.16 e/kWh and a unit water cost of 1.13 $/m 3.

i| BP-ST EC-ST G T ~ CC-SP CC-EC

Cooener~on option

Fig. 23. Cost of electricity for each cogeneration option (PR = 9.0).

A.M. El -Nashar / Desal inat ion 134 (2001) 7 -28 27

BP-ST EC-ST GT-IfRSG CC-BP CC-EC Cooeneration option

Fig. 24. Cost of water for each cogeneration plant (PR = 9.0).

6. Conclusions

• The wide variety of options available for com- bining cogeneration plants with desalination plants and the influence of the technical and economic performance parameters of each combination makes the use of system modeling using computer programming inevitable.

• The optimum cogeneration option depends strongly on the load variation throughout the year. Both monthly electrical and water production loads should be input parameters to the computer model.

• The power to water ratio of the different combinations of cogeneration plants scans the range from 4 to 18 MW per MIGD with the lowest ratio for the BP-ST option and the highest ratio for the CC-EC option.

• The power to water ratio has a strong influence on the optimum selection of a cogeneration plant.

• The selection of the most economical cogeneration plant should be based on a life cycle cost analysis which should take into consideration the escalation rates of fuel and O&M expenses in order to arrive at an estimate of the total expenses for each option for the whole lifetime of its operation.

7. Symbols

Ce - - Annual cost of electricity, $ ce - - Unit cost of electricity, S/kWh

C ~ e

f I

Coin

C R F - -

Cs - - Cs e

E

F E S R

gr

gore

H

H R

H R R - -

I C - -

1C - -

k - -

L C C - -

Me

mw

N N H R

Cost of electricity per unit exergy, S/kWh Annual fuel cost, $ Fuel cost during first year of operation, $ O&M cost during first year o f operation, $ Capital recovery factor Annual steam cost, $ Unit cost of steam, S/ton Cost of steam per unit exergy, S/kWh Exergy, kW Fuel energy savings ratio Annual fuel escalation rate Annual O&M cost escalation rate Plant operation time, hours per year Heat rate, Btu/kWh Heat rate ratio Initial capital cost, $ Initial capital, $ Interest rate Life cycle cost, $ Rated capacity o f desalination plant, m3/d

--Rated capacity o f desalination plant, mVh Plant lifetime, years Net heat rate, MWdMWel,~

O & M - - Annual O&M expenses, $ p f - - P l a n t availability, number of running

hours per year divided by 8760 P - - Net power output, kW P - - Monthly average load, kW

P R ~ Performance ratio P W ~ Present worth, $ P W R ~ Power to water ratio, MW/MIGD T - - Total hardware cost, $

G r e e k

Ah - - Number of hours in a month /Log - - Process heat to power ratio, MW~VlWd r/b - - Boiler efficiency r/c - - T h e r m a l efficiency of a conventional

power plant

28 A.M. EI-Nashar / Desalination 134 (2001) 7-28

Subscripts

cog - - Cogeneration des - - Desalination e - - Electricity f - - Fuel f o - - Fuel for fas t year net - - Net power omO - - O&M for first year om - - Operation and maintenance s - - Steam w - - Water

Abbreviat ions

BP-ST - - Back pressure steam turbine cogeneration

CC-BP - - Combined cycle with back pressure steam turbine cogeneration

CC-EC - - C o m b i n e d cycle with controlled extraction-condensing steam turbine cogeneration

EC-ST - - Controlled extraction-condensing steam turbine cogeneration

G T - H R S G - Gas turbine and heat recovery steam generator cogeneration

IC - - Initial cost LCC - - Life cycle cost MED - - Multiple effect distillation MSF - - Multistage flash O&M - - Operation and maintenance TVC - - Thermal vapor compression

R e f e r e n c e s a n d b i b l i o g r a p h y

[1] L. Awerbuch, Power-desalination and the importance of hybrid ideas, Proc., IDA World Congress on Desalination and Water Reuse, Madrid, Spain, 1997.

[2] J. Kovaeik, R. Boerieke and S. Jupp, Cogenerafion principles, technologies and systems, in: Cogeneration - - Why, When, and How to Assess and Implement a Project, R.H. MeMahan, Jr., Ed., Marcel Dekker, Inc., New York, 1987.

[3] I. Kamal, Thermo-economie modeling of dual- purpose power/desalination plants: steam cycles, Proe., IDA World Congress on Desalination and Water Reuse, Madrid, Spain, 1997.

[4] J.W. Baughn and N. Bagheri, The Effect of Thermal Matching on the Thermodynamic Performance of Gas Turbine and IC Engine Cogene~atlon Systems", ASME 85-IGT-106, 1985.

[5] M. Haaland and K. Schilller, Brown Boverie Rev., (1977) 9-77.

[6] P.N. Estey, S.J. Jabbour and T.J. Connoly, A Model for Sizing Cogeneration Systems. Stanford University, Palo Alto, CA, 1980.

[7] A. Rohrer, Comparison of combined heat and power generation plants, ABB Rev, 3 (1996).

[8] A. Antonini, D. Mich¢li and P. Pinamonti, Perfor- mance parameters evaluation in industrial eogeneration plants, ASME COGEN-TURBO, IGTI, 6 (1991).

[9] B.J. Jody, E.J. Daniels and R.M. Bowman, Econo- mics of Industrial Cogeneration, Institute of Gas Technology, Chicago, IL.

[10] R.H. MeMahan, Jr., Ed., Cogeneration - - Why, When, and How to Assess and Implement a Project, Marcel Dekker, Inc., New York, 1987.

[11] F.W. Payne, Ed., Cogeneration Soureebook, The Fairmont Press, Inc.

[12] P.P. Groumpos and G. Papageorgiou, Solar Energy, 38(5) (1987) 341.

[13] T.J. Kotas, The Exergy Method of Thermal Plant Analysis, Krieger Publishing Company, Malabar, FL, USA, 1995.

Documents

Cogeneration for power and desalination — state of the art review