Cogeneration for power and desalination state of the art review

Transcription

1 Desalination 134 (2001) 7 28 Cogeneration for power and desalination state of the art review Ali M. El-Nashar Abu Dhabi Water and Electricity Authority, P.O. Box 41375, Abu Dhabi, UAE Tel (50) (mobile); Fax +971 (2) ; elnashar@emirates.net.ae 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 1. 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 of 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 Seawater Desalination Technologies on the Threshold of the New Millennium, Kuwait, 4 7 November /01$ See front matter 2001 Elsevier Science B.V. All rights reserved

2 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 P/W 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 represented by the total area above the ST-BP band. Table 1 Typical design power to water ratio for cogeneration plants Prime mover Backpressure steam turbine MSF (BP-ST) Extraction/condensing steam turbine MSF (EC-ST) Gas turbine unfired HRSG- MSF (GT-HRSG) Combined gas turbine, HRSG, backpressure steam turbine (CC- BP) 2.2. Fuel energy savings ratio Power to water 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, Q p, and consuming an amount of fuel

3 A.M. El-Nashar / Desalination 134 (2001) 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 (Q f ) cog, the fuel energy saved, Q f, is Q f Q p = η b P + η c ( Q f ) cog (1) The fuel energy savings ratio (FESR) is defined as the ratio of the saving ( Q f ) to the fuel energy required in the conventional plants. FESR Q f c cog = = 1 (2) Q p [ 1 + ( λcoηc / ηb )] ηb P + η c η / η where λ cog = (Q p /P) is the heat to power ratio in MW th /MW el, η c is the thermal efficiency of the conventional power plant, η cog = [P/(Q f ) cog ] is the efficiency of the cogeneration plant, η b is the efficiency of the conventional boiler. Typical values of these parameters for different cogeneration plants are shown in Table 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 cogeneration 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 cogeneration 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 definition, the net heat rate is defined as follows: Q NHR = f Q p ηb P (3) 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

4 10 A.M. El-Nashar / Desalination 134 (2001) 7 28 Table 2 Characteristics of different cogeneration plants Plant type Efficiency range Heat/power ratio range FESR range Backpressure steam turbine Extraction/condensing steam turbine Gas turbine/hrsg Combines cycle Table 3 Typical Net Heat Rate values for various cogeneration and power-only cycles System configuration NHR (MW th /MW el ) Fuel savings per MW year * 1000 s SCM of natural gas Cogeneration systems Backpressure steam turbine ,300 1,400 Extraction/condensing steam turbine ,200 Gas turbine/hrsg ,100 Combined cycle with BP steam turbine ,200 Combined cycle with extr./cond. steam turbine Utility power-only systems Heat rate (MW th /MW el ) Boilers with steam turbines NA Simple-cycle gas turbine NA Combined cycles 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 MW th /MW el 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).

5 A.M. El-Nashar / Desalination 134 (2001) 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 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 of 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 cogeneration 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 97,950 82,725 52,100 25,250 13,130 Power auxiliary loads, kw 5,500 5,050 4,010 2,790 2,010 Net power output, kw 92,450 77,675 48,090 22,460 11,120 Load, % Fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 16,208 18,511 27,278 53, ,524 Exhaust steam to desal, lb/h 973, , , , ,000 Bypass steam to desal, lb/h 0 139, , , ,000 Total steam to desal, lb/h 973, , , , ,000 Desal. production, MIGD Desal. auxiliary load, kw 13,560 13,560 13,560 13,560 13,560

6 12 A.M. El-Nashar / Desalination 134 (2001) 7 28 Fig. 2. Heat rate ratio of backpressure cogeneration plant supplying constant steam flow to a desalination unit having a performance ratio 8.0. Fig. 3. Net heat rate for BP-ST cogeneration plant 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. Fig. 4. Power to water ratio for BP-ST cogeneration plant supplying constant steam to desalination. Fig. 5. Performance of EC-ST cogeneration plant with constant steam to desalination. (Performance ratio PR = 8.0)

7 A.M. El-Nashar / Desalination 134 (2001) 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 125,000 93,200 72,700 54,350 Power auxiliary loads, kw 8,730 7,920 7,490 7,720 4,000 Net output, kw 116,270 85,280 65,210 46,630 4,000 Load, % Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 13,707 15,143 17,041 25, ,527 Extr. steam to desal, lb/h 683, , , ,836 0 Bypass steam to desal, lb/h , ,417 Total steam to desal, lb/h 683, , , , ,417 Desal production, MIGD Desal auxiliary load, kw 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 (PWR ) of about 9 MW/MIGD, but lower PWR s are possible. However, as PWR approaches 5 MW/MIGD, they are reaching the PWR of backpressure steam turbine plants. Lower values of PWR can be achieved by reducing the extraction steam flow and complementing it with bypass steam Gas turbine plus unfired heat recovery steam generator plus auxiliary boiler connected to desalination plant (GT-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 unfired HRSG, where steam is produced for export to a desalination plant. The amount of steam produced by the Fig. 6. Net heat rate for a typical EC-ST cogeneration plant. Fig. 7. Power to water ratio of extraction/condensing steam turbine cogeneration plant supplying constant steam to desalination.

8 14 A.M. El-Nashar / Desalination 134 (2001) 7 28 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 GT gross output, kw 95,730 83,540 65,700 47,180 27,480 6,740 Power auxiliary load, kw 1,910 1,780 1,580 1,340 1, Net output, kw 93,820 81,760 64,120 45,840 26,460 6,230 Load, % GT fuel input, MMBtu/h HHV Aux. boiler fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 12,308 13,809 16,758 22,390 36, ,828 HRSG steam to desal., lb.h 586, , , , ,000 93,000 Aux. boiler steam to desal., lb/h 0 86, , , , ,000 Total steam to desal., lb/h 586, , , , , ,300 Desal. production, MIGD Desal. aux. load, kw 8,170 8,170 8,170 8,170 8,170 8,170 Ambient temperature, C GT gross output, kw 113, ,410 82,900 62,270 40,580 17,290 Power auxiliary load, kw 2,260 2,200 1,980 1,710 1, Net output, kw 110, ,210 80,920 60,560 39,200 16,390 Load, % GT fuel input, MMBtu/h HHV Aux. boiler fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 11,730 12,696 15,040 19,192 28,005 62,821 HRSG steam to desal., lb.h 586, , , , ,400 56,200 Aux. boiler steam to desal., lb/h 0 75, , , , ,100 Total steam to desal., lb/h 586, , , , , ,300 Desal. production, MIGD Desal. aux. load, kw 8,170 8,170 8,170 8,170 8,170 8,170

9 A.M. El-Nashar / Desalination 134 (2001) Fig. 8. Heat rate ratio of gas turbine, unfired HRSG, auxiliary boiler cogeneration plant with constant steam supply to desalination. Performance ratio, PR = 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 fired 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 substantially as gas turbine load drops, and thus the HRSG duct burner can be fired to increase the Fig. 9. Net heat rate for GT/ unfired HRSG cogeneration 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. Modulating 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 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 Fig. 10. Heat rate ratio of gas turbine, supplementary fired HRSG cogeneration plant supplying constant steam to desalination. Performance ratio PR = 8.0. Fig. 11. Net heat rate of GT/supplementary-fired HRSG cogeneration plant.

10 16 A.M. El-Nashar / Desalination 134 (2001) 7 28 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 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. Table 7 Part-load performance of gas turbine, fired HRSG cogeneration plant with constant steam supply to desalination. Performance ratio PR = 8.0 Ambient temperature, C GT gross output, kw 95,730 83,540 65,700 47,180 27,480 6,740 Power aux. load, kw 1,910 1,780 1,580 1,340 1, Net output, kw 93,820 81,760 64,120 45,840 26,460 6,230 % Load GT fuel input, MMBtu/h HHV Duct burner fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 12,308 13,591 16,178 21,148 33, ,967 Steam to desal., lb/h 586, , , , , ,300 Desal. production, MIGD Desal. aux. load, kw 8,170 8,170 8,170 8,170 8,170 8,170 Ambient temperature, C GT gross output, kw 113, ,410 82,900 62,270 40,580 17,290 Power aux. load, kw 2,260 2,200 1,980 1,710 1, Net output, kw 110, ,210 80,920 60,560 39,200 16,390 Load, % GT fuel input, MMBtu/h HHV Duct burner fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 11,730 12,530 14,532 18,115 25, ,425 Steam to desal., lb/h 586, , , , , ,300 Desal. production, MIGD Desal. aux. load, kw 8,170 8,170 8,170 8,170 8,170 8,170

11 A.M. El-Nashar / Desalination 134 (2001) Table 8 Gas turbine, supplementary fired HRSG, backpressure steam turbine supplying constant steam flow to desalination. Performance ratio PR = 8.0 Ambient temperature, C GT gross output, kw 95,730 83,540 65,700 47,180 27,480 6,740 ST gross output, kw 31,050 31,310 31,290 31,270 31,240 31,190 Plant gross output, kw 126, ,850 96,990 78,450 58,720 37,930 Power aux. load, kw 2,540 2,420 2,220 2,000 1,730 1,390 Net output, kw 124, ,430 94,770 76,450 56,990 36,540 Load, % GT fuel input, MMBtu/h HHV Duct burning fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 9,294 9,908 10,975 12,704 15,731 22,355 Steam to desal., lb/h 428, , , , , ,298 Desal. production, MIGD Desal. aux. load, kw 5,970 6,000 6,000 5,990 5,990 5,980 Ambient temperature, C GT gross output, kw 113, ,410 82,900 62,270 40,580 17,290 ST gross output, kw 30,700 30,690 30,770 30,770 30,780 30,790 Plant gross output, kw 143, , ,670 93,040 71,360 48,080 Power aux. load, kw 2,870 2,830 2,610 2,360 2,070 1,700 Net output, kw 140, , ,060 90,680 69,290 46,380 Load, % GT fuel input, MMBtu/h HHV Duct brning fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 9, ,627 12,143 14,687 20,027 Steam to desal., lb/h 427, , , , , ,900 Desal. production, MIGD Desal. aux. load, kw 5,960 5,950 5,960 5,960 5,960 5, 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 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 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

12 18 A.M. El-Nashar / Desalination 134 (2001) 7 28 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 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 reducing gas turbine load and increasing HRSG duct burning firing. 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. Fig. 13. Heat rate ratio for gas turbine, supplementary fired HRSG, backpressure steam turbine cogeneration supplying constant steam flow to desalination. Performance ratio PR = 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 Fig. 14. Net heat rate for combined cycle with backpressure steam turbine cogeneration plant. Fig. 16. Heat rate ratio for gas turbine, supplementary-fired HRSG, extraction condensing steam turbine cogeneration plant supplying constant steam to desalination. Performance ratio PR = 8.0.

13 A.M. El-Nashar / Desalination 134 (2001) Fig. 17. Net heat rate for combined cycle cogeneration plant with extraction/condensing steam turbine. 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. Table 9 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 Ambient temperature, C GT gross output, kw 95,730 83,540 65,700 47,180 27,480 6,740 ST gross output, kw 33,200 33,580 33,545 33,520 33, Plant gross output, kw 128, ,120 99,245 80,700 60,945 40,135 Power aux. load, kw 3,440 3,280 3,020 2,730 2,370 1,920 Net output, kw 125, ,840 96,225 77,970 58,575 38,215 Load, % GT fuel input, MMBtu/h HHV Duct burning fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 9,202 9,785 10,807 12,457 15,305 21,375 Steam to desal., lb/h 360, , , , , ,000 Desal. production, MIGD Desal.aux. load, kw 5,020 5,020 5,020 5,020 5,020 5,020 Ambient temperature, C GT gross output, kw 117, ,410 82,900 62,270 40,580 17,290 ST gross output, kw 36,220 33,360 33,480 33,485 33,495 33,500 Plant gross output, kw 153, , ,380 95,755 74,075 50,790 Power aux. load, kw 3,840 3,610 3,340 3,030 2,670 2,210 Net output, kw 149, , ,040 92,725 71,405 48,580 Load, % GT fuel input, MMBtu/h HHV Duct burning fuel input, MMBtu/h HHV Total fuel input, MMBtu/h HHV Heat rate, Btu/kWh HHV 8,972 9,527 10,440 11,875 14,252 19,920 Steam to desal., lb/h 360, , , , , ,000 Desal. production, MIGD Desal.aux. load, kw 5,020 5,020 5,020 5,020 5,020 5,020

14 20 A.M. El-Nashar / Desalination 134 (2001) 7 28 such as fuel cells and Stirling 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 technologies, which account for essentially all major cogeneration facilities for power and desalination. The range of capital costs for several cogeneration and desalination technologies is shown in Tables 10 and 11, respectively. Table 10 Cogeneration technologies capital and operating costs Cogeneration technology Capital cost, $/kw Fixed O&M cost, $/kw Variable O&M cost, $/kwh Expected lifetime, years BP steam turbines Ext./cond. steam turbines Gas turbine/hrsg Combined cycle with BPST Combined cycle with ECST Table 11 Desalination technology capital and operating costs Desalination technology Capital cost, $/GPD O&M cost, $/m³ Expected lifetime, years MSF MED TVC Optimal selection of cogeneration plant to match power and water demands One of the reasons that it is difficult to standardize 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. If 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.

15 A.M. El-Nashar / Desalination 134 (2001) Power (a) High P/W ratio Power (b) Low P/W ratio W D = demand point P = match power demand W = match water demand P D D Aux. boiler heat Power-only plant W P Water Water Fig. 19. Matching cogeneration 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 cogeneration 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 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 strategies. The LCC method recognizes that a capital investment by a utility is

16 22 A.M. El-Nashar / Desalination 134 (2001) 7 28 Fig. 20. Optimization model for cogeneration plant.

17 A.M. El-Nashar / Desalination 134 (2001) 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 conditions 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 cog ( 1 + d + e f ) T cog ( IC ) = + (4) where T cog 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]: PW PW f om = C f 0 = C om 1 + g f 1 + g f 1 k g f 1 + k 1 + g om 1 + g 0 1 k g om 1 + k N om N (5) where PW f present worth of fuel costs, $; PW om present worth of O&M costs, $; C f0 fuel cost in the first year, $; C om0 O&M cost in the first year, $; g f fuel escalation rate; g om O&M escalation rate; k money interest rate; N system life, years. The life-cycle cost of the cogeneration plant, (LCC) cog, is obtained as the summation of the initial plant cost and the present worth of all annual recurring costs: ( LCC ) cog ( IC) cog + ( PW f ) + ( PW om ) cog = (6) where (PW f ) cog and (PW om ) cog are given by ( PW ) = ( C ) f cog ( PW ) = ( C ) om cog f 0 om cog N 1+ g f 1+ g f 1 k g f 1+ k 1+ g om 1+ gom 1 cog k gom 1+ k N (7) where (C f ) 0 fuel cost during the first year of operation, $; (C om ) cog0 O&M cost during the first year of operation, $; g f fuel escalation rate; g om 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

18 24 A.M. El-Nashar / Desalination 134 (2001) 7 28 a whole and does not involve the consumption of additional external resources: ( LCC ) des = ( IC) des + ( PW om ) des where (IC) des initial capital of desalination plant, $; (PW om ) des present worth of O&M costs of desalination plant, $. The total life cycle cost of the combined cogeneration and desalination plants is the summation of (LCC) cog and (LCC) des ( LCC ) tot ( LCC) cog + ( LCC) des = (8) 5.2. Cost allocation between electricity and water The equality method of the exergy approach [13] is used for costing electricity and steam from a cogeneration plant. Based on these costs, the cost of water from the desalination plant can then be estimated using the normal economic procedure which take into consideration capital, O&M and energy costs. In the equality method the production by the cogeneration plant of the two products (electricity and steam) is considered to have the same priority, so the capital, O&M and energy costs are split between both products according to the exergy content of each. Based on this method the cost of electricity per unit exergy, c ε e, is equal to the cost of steam per unit exergy, c ε s : c = (9) ε ε s c e The life cycle cost of a cogeneration plant which consists of capital amortization, O&M costs and energy costs can be split among the exergy content of the generated electricity and steam as follows: ε ε ( LCC ) P. H. N. + m. H. N. ε c cog = (10) e s s s where P average power production, kw; H plant availability, h/y; ε s exergy content per unit of steam, kwh/ton; CRF capital recovery factor; m s average steam production, ton/h. This equation is used to estimate the unit exergy cost of electricity and steam. The unit cost of electricity ($/kwh) is identical to the unit exergy cost of electricity (also $/kwh) since the exergy content of electricity is identical to its energy content; i.e. c e ε = c e. The unit cost of steam on the other hand is different from its unit exergy cost since the exergy content of a mass of steam depends on its pressure and temperature. The unit cost of steam ($/ton) can be related to its unit exergy cost ($/kwh) by c = ε (11) s c ε s s 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: c w = ( LCC) tot 5.3. Example 12 ce P h N. pf 0 m. H. N w (12) To illustrate the procedure for selecting the optimum cogeneration 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.

19 A.M. El-Nashar / Desalination 134 (2001) Table 12 Plant specification and economic parameters Table 13 Specific capital and O&M costs of the cogeneration plants 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 Cost parameter BP-ST EC-ST GT-HRSG CC-BP CC-EC MSF, PR =7 9 Specific Fixed capital cost, O&M cost, $/kw $/kwy $/gpd 0 Variable O&M cost, $/kwh $/m³ The options for plant configurations are as follows: Backpressure steam turbine connected to MSF (BP-ST) Extraction-condensing steam turbine connected to MSF (EC-ST) Gas turbine with heat recovery steam generator connected to MSF (GT-HRSG) Combined cycle gas/backpressure steam turbine 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. 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

20 26 A.M. El-Nashar / Desalination 134 (2001) 7 28 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 cogeneration 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 parameter BP-ST 800 EC-ST 803 GT-HRSG 727 CC-BP 772 CC-EC 775 Capital cost, $10 6 PV = present value PV fuel, PV O&M, Life cycle $10 6 $10 6 cost, $ 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 c/kwh and a unit water cost of 1.13 $/m³. Fig. 23. Cost of electricity for each cogeneration option (PR = 9.0).

21 A.M. El-Nashar / Desalination 134 (2001) Fig. 24. Cost of water for each cogeneration plant (PR = 9.0). 6. Conclusions The wide variety of options available for combining 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 C e Annual cost of electricity, $ c e Unit cost of electricity, $/kwh c e ε Cost of electricity per unit exergy, $/kwh C f Annual fuel cost, $ C fo Fuel cost during first year of operation, $ C om O&M cost during first year of operation, $ CRF Capital recovery factor C s Annual steam cost, $ c s Unit cost of steam, $/ton ε c s Cost of steam per unit exergy, $/kwh E Exergy, kw FESR Fuel energy savings ratio g f Annual fuel escalation rate g om Annual O&M cost escalation rate H Plant operation time, hours per year HR Heat rate, Btu/kWh HRR Heat rate ratio IC Initial capital cost, $ IC Initial capital, $ k Interest rate LCC Life cycle cost, $ M d Rated capacity of desalination plant, m³/d m w Rated capacity of desalination plant, m³/h N Plant lifetime, years NHR Net heat rate, MW th /MW elec O&M Annual O&M expenses, $ pf Plant availability, number of running hours per year divided by 8760 P Net power output, kw P Monthly average load, kw PR Performance ratio PW Present worth, $ PWR Power to water ratio, MW/MIGD T Total hardware cost, $ Greek h Number of hours in a month λ cog Process heat to power ratio, MW th /MW el η b Boiler efficiency η c Thermal efficiency of a conventional power plant

22 28 A.M. El-Nashar / Desalination 134 (2001) 7 28 Subscripts cog Cogeneration des Desalination e Electricity f Fuel fo Fuel for first year net Net power om0 O&M for first year om Operation and maintenance s Steam w Water Abbreviations BP-ST Back pressure steam turbine cogeneration CC-BP Combined cycle with back pressure steam turbine cogeneration CC-EC Combined cycle with controlled extraction-condensing steam turbine cogeneration EC-ST Controlled extraction-condensing steam turbine cogeneration GT-HRSG 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 References and bibliography [1] L. Awerbuch, Power-desalination and the importance of hybrid ideas, Proc., IDA World Congress on Desalination and Water Reuse, Madrid, Spain, [2] J. Kovacik, R. Boericke and S. Jupp, Cogeneration principles, technologies and systems, in: Cogeneration Why, When, and How to Assess and Implement a Project, R.H. McMahan, Jr., Ed., Marcel Dekker, Inc., New York, [3] I. Kamal, Thermo-economic modeling of dualpurpose power/desalination plants: steam cycles, Proc., IDA World Congress on Desalination and Water Reuse, Madrid, Spain, [4] J.W. Baughn and N. Bagheri, The Effect of Thermal Matching on the Thermodynamic Performance of Gas Turbine and IC Engine Cogeneration Systems, ASME 85-IGT-106, [5] M. Haaland and K. Schüller, Brown Boverie Rev., (1977) [6] P.N. Estey, S.J. Jabbour and T.J. Connoly, A Model for Sizing Cogeneration Systems. Stanford University, Palo Alto, CA, [7] A. Rohrer, Comparison of combined heat and power generation plants, ABB Rev, 3 (1996). [8] A. Antonini, D. Micheli and P. Pinamonti, Performance parameters evaluation in industrial cogeneration plants, ASME COGEN-TURBO, IGTI, 6 (1991). [9] B.J. Jody, E.J. Daniels and R.M. Bowman, Economics of Industrial Cogeneration, Institute of Gas Technology, Chicago, IL. [10] R.H. McMahan, Jr., Ed., Cogeneration Why, When, and How to Assess and Implement a Project, Marcel Dekker, Inc., New York, [11] F.W. Payne, Ed., Cogeneration Sourcebook, 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.