THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 91-GT-365345 E. 47 St., New York. N.Y. 14017

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M Discussion is printed only it the paper is published in an ASME Journal. Papers are available]iL ® from ASME for fifteen months after the meeting.

Printed in USA.

Further Technical Aspects and Economics of aUtility-Size Kalina Bottoming Cycle

A. I. KALINAH. M. LEIBOWITZD. W. MARKUSR. I. PELLETIER

Exergy, Inc.Hayward, CA

ABSTRACT

An 86 MW bottoming cycle has been designed based on theKalina cycle principles previously reported by theauthors. It is designated as Kalina Cycle System 6 (KCS6).It uses an ABB Type 13E gas turbine topping cycle to pro-duce a 227 MW combined cycle having a heat rate (LHV) of6460 Btu/kWh (52.8%). The working fluid is a 75% aquaammonia mixture.

Equipment and installation costs were developed for KCS6and a baseline two-pressure steam bottoming cycle. TheKCS6 turbine was designed with input from ABB.

Compared to the two-pressure steam bottoming cycle, KCS6provides an additional 12.1 MW (16.4%). The estimated costof the bottoming cycle is $1,058/kW vs. $1,033/kW for thesteam plant. The KCS6 heat acquisition equipment (boilerand recooler) and distillation/condensation subsystemrepresent the two major additions to cost over the steamplant. On the other hand, the turbine is less expensive,mostly due to the elimination of the large condensingstages.

An economic analysis of the KCS6 plant is presented usingthe value of the additional output as the decision-makingeconomic variable. The analysis is based on a model whichconsiders capital cost, heat rate and near-term world-widefuel prices. At $4.25/10 6 Btu fuel, the KCS6 costs approxi-mately $7 million less than the value of its output.

SYSTEM DESIGN AND PLANT COSTS

BackgroundAs the Kalina cycle technology continues to evolve,

the questions from the technical community and powerindustry have shifted away from thermodynamicprinciples to demonstrating economic feasibility.Recently, the authors have published two papers [1,2]describing the conceptual design and performancecharacteristics of a utility-size Kalina bottoming cycle forcombined cycle operation. While improvement in outputover conventional steam bottoming cycles was established,questions regarding equipment and installation costs were

left unanswered. Others have attempted to calculate costsbut were hindered by lack of design information.

Recently, Siemens AG reported on the results of aninternal study [3] on a 108 MW Kalina Cycle System 6(KCS6) bottoming cycle under a KWU V94.2 gas turbine.While their estimate of the KCS6 output was in agreementwith that reported by the authors in [1], Siemens estimatedthat KCS6 combined cycle investment costs were about 50percent higher than a reference steam plant: 1310 DM/kWvs 920 DM/kW. No supporting data were given. It isworthwhile to mention that 75 percent of the additionalcosts of KCS6 were attributed by Siemens to thedistillation/condensation subsystem of KCS6. Inasmuch asthe distillation/condensation subsystem has nocounterpart in a steam plant from which to extrapolatecosts, it is not surprising that its novelty results inexaggerated estimates of size and cost.

To deal with these issues, the authors havecollaborated with engineers from Asea Brown Boveri's(ABB) Baden, Switzerland group. An ABB Type 13E gasturbine was used as the reference topping cycle.

The study was conducted in the following way: Aprocess design, heat/mass balance and thermodynamicstatepoints were developed for a KCS6 bottoming cycleunder a Type 13E gas turbine. Based on this, a plant layoutwas made for the combined cycle showing the overallarrangement of equipment and elevations. A piping andinstrumentation diagram (P&ID) was generated todetermine pipe sizes, valve requirements and balance ofplant equipment.

Due to the substantial difference in volume flowbetween the KCS6 turbine and a fully condensing steamturbine, a layout and preliminary mechanical design forthe Kalina turbine string were developed. All of the otherplant equipment specifications were based on standardprocess and power industry designs. The pricing of all theequipment was determined from vendor quotations and in-house manufacturing estimates. Installation and erectioncosts were factored estimates based on existing costinformation for combined cycle plants recently built byABB.

Presented at the International Gas Turbine and Aeroengine Congress and ExpositionOrlando, FL June 3-6, 1991

Copyright © 1991 by ASME

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Overall DesignThe KCS6 was specifically designed to operate as a

bottoming cycle for utility combined cycle applications.The KCS6 designed for application with an ABB Type 13Egas turbine operates with a working fluid composition of75% ammonia/water. The heat-mass balance and processdesign are shown in Figures 1 and 2. Figure 1 describesthe high temperature portion of the plant. It is mainlycomprised of the waste heat boiler, three aqua ammoniaturbine stages and a unique regenerative heater(recooler) between the intermediate pressure (IP) and lowpressure (LP) turbines. The function of this regenerativeheater, wherein the IPT exhaust is cooled before enteringthe LPT, has been described by the authors in a previouspaper [1] and is summarized below for the reader'sconvenience.

Essentially, the IPT exhaust is a source of low tomoderate temperature heat that is used to evaporate aportion of the working fluid. As shown in Figure 1, about31% of the working fluid, after leaving the preheatersection of the heat recovery boiler at 183°C, is sent into theregenerative heater where it is vaporized and partiallysuperheated by cooling the IPT exhaust. This vaporizedstream is then sent back into the boiler for finalsuperheating. After this IPT exhaust is cooled, the vapor,still in a superheated state, is sent into the LPT for finalexpansion to 2.9 bar. Without this feature, hightemperature heat from the gas turbine combustion gaseswould have to be used for vaporization. From thestandpoint of the second law of thermodynamics, theregenerative heater is far better.

Distillation Condensation Subsystem (DCSS)The plant's distillation condensation subsystem is

shown schematically in Figure 2. A detailed explanation ofits operation is given in [1]. The function and operation ofthe DCSS is summarized below to acquaint the reader who isnot familiar with the process.

To fully condense the 75% aqua ammonia workingfluid leaving the LPT turbine would require a -18°C (0°F)sink. These do not normally exist in temperate climates.The alternative is to back-pressure the turbine toapproximately 6.4 bar (92 psia) where an 18°C (64°F) sinkcan condense all of the LPT exhaust. However, this wouldeliminate almost all of the thermodynamic gains made inthe heat acquisition portion of the plant.

me utaS proviaes the answer to use auuvc pruule,u.Condensing is achieved in two steps: first, by forming anintermediate mixture substantially leaner than theworking mixture and condensing it; second, by pumpingthe intermediate mixture to higher pressure, reformingthe working mixture and then condensing this.

More specifically, the 75% mixture, leaving the LPT,is cooled and then diluted to an intermediate composition of50%, using a source of lean liquid, approximately 42%ammonia, generated in the separator tank shown in Figure2. The 50% mixture is condensed in the LP cooler against18°C cooling water. This 50% intermediate fluid is pumpedto 6.4 bar (92 psia), preheated, partially vaporized and sentinto the separator. The enriched vapor, 97% ammonia,leaving the top of the separator is then cooled in the HPcondenser and diluted with some of the 50% intermediatefluid to reform the 75% working fluid. Now, at 6.4 bar, the75% fluid is completely condensed against 18°C coolingwater in the HP cooler.

All heat used to perform the separation (distillation)process is recuperated from the LPT exhaust.

PerformanceBased on type 13E operating conditions, the KCS6

produces 86.1 MW, net. This reflects all losses, parasiticloads and the cooling tower pumps. A state-of-the-art twopressure steam bottoming cycle generates 74 MW. Theimprovement is 16.4%. The KCS6 performance issummarized in Table 1.

TABLE 1

KCS6 Performance Summary

Gas turbine output = 142170 kWeBottoming cycle turbine power = 92554 kWeBottoming cycle turbine shaft power = 92378 kWeBottoming cycle turbine electrical power = 90807 kWeBottoming cycle output = 86136 kWeSystem total output = 227100 kWe

Gas turbine exhaust flow = 496 kg/secFuel consumption = 429,940 kW (1467 x 10 6 Btu/hr)Overall system efficiency = .528 (6460 Btu/kWh)Bottoming cycle thermal efficiency = .356Second Law efficiency of bottoming cycle = .780Cooling water = 18 ° C (64°F)

All KCS6 losses and auxiliary loads are shown in Table 2.

TABLE 2

Aaua Ammonia Turbine/Generator

Turbine isentropic expansion efficiency, %HPT, IPT, LPT 86, 92, 93

Turbine mechanical losses, kW 240LPT turbine exhaust loss, kJ/kg, (Btu/lb) 5 (2.1)Turbine balance piston loss, kW 670Generator efficiency, % 98.3Transformer efficiency, % 99.0

Heat Recovery Vapor Generator (HRVG)

Radiation loss, % 0.5Exit stack temperature, ° C, ( ° F) 78 (173)Preheater pinch, ° C ( ° F) 10 (18)Superheater approach, °C ( ° F) 23 (42)

Pressure drops (DP/P)

Feed pump outlet to superheater outlet, % 9Superheater outlet to turbine inlet, % 4Turbine throttle valve, % 4Reheater, % 10Recooler, % 5Turbine exhaust to LP condenser, % 2.5

Auxiliaries

DCSS condensate pumps, kW 634Main feed pump, kW 3288Cooling water pump, kW 749

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29 38

'36 !37to HRVG I I -- from

TURBINE• t EXHAUST

H

I

1

28 19 ._0_$____._fT'\.3 27. 16I I 121 t 7

I

3}__J 17

I # P bar X T U H kJ/kg G/G30 Flan kg/s

1 2.82 .50062 7.99 .50063 6.61 .50064 6.47 .50065 6.47 .50066 6.47 .97227 6.81 .50068 6.44 .50069 6.44 .9722

10 6.47 .416611 6.44 .750012 5.78 .416613 6.42 .750014 6.40 .750015 6.47 .500616 2.86 .750017 2.84 .750018 2.84 .500619 2.84 .416620 5.09 .416621 25.74 .750021 I 23 • Water

59- __ t8i f ---24 tf

24 • Water27 6.68 .5006

t I t2 28 25.39 .750029 25.12 .750032 19.32 .750033 7.99 .500634 7.99 .500635 6.47 .3806

58--- ---' ---23 1 36 6.47 .9722

L 1 37 6.47 .972214 I LJ 38 2.89 .7500

58 • Water59 • Water

waking solution (.75) - • - - - - lean solution (.41661

---------- basic solution (.5006) ........................ lean liquid (.3806)

- - • - - - seriched vapor (.9722) - -- - -- - cooling water

DCSS: Distillation Condensation SubsystemFigure 2

DISTIL[ATICN-CLSJDE(SATIGN SUGSYSTEM POINTS

21.67 -148.72 3.9709 371.1283

21.67 -148.07 3.9709 371.1283

48.18 -29.36 2.2060 206.1756

58.81 195.41 2.2060 206.1756

67.50 340.42 3.4998 327.0943

67.50 1428.89 .7097 66.3257

48.18 -29.33 2.6771 250.2096

47.48 1-29.33 .4711 44.0340

47.48 1298.29 .5289 49.4281

67.50 146.66 2.9709 277.6662

47.48 672.79 1.0000 93.4620

50.40 -20.24 2.9709 277.6662

40.47 564.31 1.0000 93.4620

21.67 -66.87 1.0000 93.4620

83.94 587.68 1.2938 120.9187

50.76 929.95 1.0000 93.4620

36.87 774.29 1.0000 93.4620

33.36 99.80 3.9709 371.1283

26.28 -127.23 2.9709 277.6662

26.28 -127.23 2.9709 277.6662

21.67 -64.07 1.0000 93.4620

17.78 • 25.8256 2413.7136

26.90 • 25.8256 2413.7136

48.53 -27.75 1.2938 120.9187

45.26 44.42 1.0000 93.4620

60.00 113.32 1.0000 93.4620

60.18 113.32 1.0000 93.4620

21.67 -148.07 1.2938 120.9187

21.67 -148.07 2.6771 250.2096

67.50 63.57 2.7901 260.7686

67.50 1428.89 .5289 49.4281

67.50 1428.89 .1808 16.8977

91.79 1726.14 1.0000 93.4620

17.78 • 18.1730 1698.4899

26.07 • 18.1730 1698.4899

HPTworking solution

31 - - - turbine gas

30 9C IPT-.- -5-1 2 4l f^

HRVG I 42 LPT

(Heat Re ovetryVapor G neraFor)

531 9

48 47 38

RE 00 R

55 44 45

1 DCSS

22

26 32 29

KALI86k CYCLE SYSTEM 6 POINTS

# P bar X T 5 H kJ/kg G/G30 F1 i kg/s

22 188.92 .7500 60.18 137.88 1.0000 93.46225 • Gas 522.00 570.35 5.3070 496.00026 • Gas 78.36 82.29 5.3070 496.00029 25.12 .7500 60.00 113.32 1.0000 93.46230 172.92 .7500 499.27 2734.52 1.0000 93.46231 160.10 .7500 497.56 2734.52 1.0000 93.46232 19.32 .7500 60.18 113.32 1.0000 93.46238 2.89 .7500 91.79 1726.14 1.0000 93.46240 56.54 .7500 381.26 2439.72 1.0000 93.46241 54.12 .7500 497.56 2769.24 1.0000 93.46242 12.74 .7500 329.93 2329.91 1.0000 93.46243 12.61 .7500 195.56 1980.94 1.0000 93.46244 183.75 .7500 182.72 797.44 1.0000 93.46245 183.75 .7500 182.72 797.44 .3109 29.06146 183.75 .7500 182.72 797.44 .6891 64.40147 179.82 .7500 288.48 1919.77 .3109 29.06148 179.82 .7500 288.48 1919.77 .6891 64.40149 179.82 .7500 288.48 1919.77 1.0000 93.46252 • Gas 400.65 432.34 5.3070 496.00053 • Gas 329.93 353.65 5.3070 496.00055 • Gas 195.56 207.19 5.3070 496.00061 126.00 .7500 470.77 2671.80 1.0000 93.462

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MECHANICAL EQUIPMENT

Heat Recovery Vapor Generator (HRVG)The plant's waste heat boiler is designed as a forced

circulation, single pass, parallel flow unit. A plot •of theboiler's heat acquisition characteristic (Q vs. T) is shown inFigure 3. The total heat duty is 242 MWth (826 x 106Btu/hr). The pinch, which occurs in the preheatersection, is 10 ° C (18 ° F), while the superheater approach is23 °C (42 °F).

From the standpoint of mechanical and hydraulicdesign, there is nothing unique about its specificationcompared to that which currently exists in utility boilerpractice. Surface was calculated based on existing heattransfer coefficients used for steam boiler duty, modifiedonly by the difference in heat transport propertiesbetween ammonia and water. The viscosity of ammonia isone-fourth that of water which increases the Reynoldsnumber and inside heat transfer coefficient. All surface isfinned. A comparison is made between a drum-type,double pressure waste heat boiler used in the steambottoming cycle and the HRVG specified for the KCS6. SeeTables 3 and 4. The major difference between the twoboilers is the 2.3 times size increase of the KCS6 boiler.With similar duty and heat transfer rates, the doubling ofthe surface is mostly the result of tighter temperaturedifferences.

In

420 -------:--..;-...^ .............:.............r-- - - -- --Superheater

310 ---:........:- --'---...... .. .:... ... .... ' .................... . .Superheater

TempC

200 --- ............. :. .- •----------------------`-..-:--..C...:... ..

Evaporator

90 Preheater '.

-20

0 30 60 90 120 150 180 210 240

Heat Duty KWth

KCS6 Heat Acquisition: T vs QFigure 3

TABLE 3

KCS6 HRVG and Recooler

Duty LMTD Conductance AreaMWth (106 Btu/hr) ° C ( ° F) W/m2K (Btu/hft2 F) 103 m 2 (10 3 ft2 )

Superheater 63.8 (212.6) 21.9 (39.5) 35.2 (6.19) 82.4 (890)Reheater 34.4 (117.4) 20.6 (27.0) 33.6 (5.92) 49.5 (535)Evaporator, 1 43.3 (147.6) 42.5 (76.5) 40.7 (7.16) 24.9 (269)Evaporator, 2 34.2 (116.7) 27.7 (49.9) 40.7 (7.16) 30.3 (327)Evaporator, 3 4.3 (14.7) 11.4 (20.6) 41.7 (7.35) 8.98 (97)Recooler 36.9 (125.8) 20.0 (36.0) 47.0 (38.21) 8.42 (91)

Preheater 61.8 (211.0) 15.3 (27.6) 41.7 (7.35) 26 (1040)

Total 278.7 (950.8) 300.8 (3,249)

Area of steam boiler = 129,522m 2 (1,399 x 103 ft2 )Area ratio = 2.322

TABLE 4

Boiler Heat Transfer Coefficients

Steam HRSG KCS6 HRVGOverall OverallConduc- Conduc-

Tube ID. Tube O.D. tance Tube I.D. Tube O.D. Lance

Section W/m2K W/m2K W/m2K W/m2K W/m2K W/m2K

HRVG vs. HRSGSuperheater 559.6 36.8 34 1718 36.8 35.1Reheater - - - 497 36.8 33.6Evaporator 3516 45.7 44 497 45.7 40.7Preheater 3910 43.5 42 3782 43.5 41.7

RecoolerSuperheater 1718 288.0 216.2

Evaporator N/A 1590 288.0 214.1

Preheater 3782 288.0 232.2

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Turbine ABB conducted a preliminary- mechanical design of

the KCS6 turbine train. It was designed for 160 bar, 500 ° Cinlet conditions, exhausting at 2.9 bar. It is shown inFigure 4. It contains a separate high pressure unit coupleddirectly to the intermediate and low pressure units whichare housed in the same casing. All three blocks aresupported on a single shaft driving a generator throughthe low pressure end. Note the ports required for theconnections to the recooler between the IPT and LPT units.

The major difference between the KCS6 aquaammonia turbine and a steam turbine is the LPT section.The volume flow in the KCS6 LPT is two orders ofmagnitude less than that of the steam LPT. Thus, thecasing and back end stages for aqua ammonia duty aremuch smaller and double flow is not required. The laststage bucket for KCS6 is 96mm long while the last stagesteam turbine bucket is 790mm. Overall, 57 blade rows arerequired for KCS6 vs. 48 for steam. As a consequence ofthis much smaller diameter, the leaving loss (kineticenergy leaving the last stage of the LPT that isunrecovered, lost to friction) for KCS6 is 5 KJ/kg (2.1Btu/lb). Typically, the steam turbine leaving loss in the100 MW size class is five times greater: 25 KJ/kg (10.5Btu/lb). See [4].

Distillation Condensation Subsystem (DOSS)The DCSS consists of a series of carbon steel, shell

and tube heat exchangers. To promote effective heattransfer, the units that are used for condensing duty arearranged in a vertical stack. At this time, it is not clearwhether it is more cost effective to use separate shells withhorizontal bundles on top of each other, to incorporateseveral horizontal bundles in one shell, or to use verticaltubes in a single shell.

For this installation study standard TEMA 'E', singlepass horizontal units are stacked on top of one another.

A summary of the plant's DCSS, giving heat transfercoefficients and surface of each exchanger is presented inTable 5.

HPT I PT LPT

FIGURE 4

KCS6 Vaoor Turbine

Table 5

DCSS Heat Exchanger Summary

Conductance LMTD AreaStream No. Process W/m2K (Btu/hrft2°F) °C (°F) m2 (ft2)

38-16 vs 27-15 HP prhtr/cond 3366 592 9.32 16.82 2371 2560616-17 vs 33-27 HP prhtr/cond 3480 612 6.61 11.89 644 695536-9 vs 28-29 LP prhtr/cond 4248 747 4.96 8.92 315 340111-13 vs 21-28 LP prhtr/cond 3935 692 7.59 13.67 339 366110-12 vs 3-4 Liquid/boiler 3418 601 6.94 12.50 2081 2248012-20 vs 34-7 Liquid/boiler 2849 501 3.39 6.10 3067 3312618-1 vs 23-24 HP Cooler 2309 406 4.76 8.57 8397 9068513-14 vs 58-59 LP Cooler 2474 435 5.82 10.48 4104 44326

Total Area 21 31 8 230240

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PLANT COSTS

A summary of the KCS6 plant costs is shown in Table6. Next to each item is a comment describing how the costwas developed.

TABLE 6

COST($103) 1

ll^l KCS6 sSteam

HRVG'HRSG 17,060 10,000

Turbine 6,270 7,390Generator 1,940 1,820DCSS Heat Exchangers 3,1 70Condenser 1,490 Balance of Plant 8,260 5,750Piping 1,470 590Valves 890 51 0Electrical and Controls 17,800 17,250Civil 13,000 12,910Erection/Installation 15,600 14,300Commissioning 2,370 1,730Project Management 3.330 2.670

$91,160 $76,410

$1,058/kW $1,033/kW

Basis for KCS6 Estimate

Vendor quotation based oncalculated surface and HRSGcost data

Manufacturing estimateVendor quotationVendor quotation based on

calculated surfacesFactored from steam cycleVendor quotationVendor quotationFactored from steam cycleFactored from steam cycleFactored from steam cycleFactored from steam cycleFactored from steam cycle

A few comments on the costs given in Table 6 areappropriate. Using calculated surfaces and vendorquotations for carbon steel exchangers (except for the

cooling water tubes), the installed cost of the DCSS wasestimated. At $6 million, it represents about 5 percent ofthe total combined cycle plant cost. This is about one-fifthof the cost estimated by Siemens AG in their study of KCS6[3]. Further, the KCS6 turbine, while generating 16percent more output, actually costs $1.0 million less thanthe steam turbine. On a per kilowatt basis, the differenceis 24 percent or $30/kW.

Considering that roughly half the KCS6 plant's costis based on factored estimates of steam cycle installationand construction costs having an uncertainty of at least±40%, it can be said that the KCS6 and steam cycle haveapproximately the same unit capacity cost, i.e., $/kW.

KCS6 ECONOMICS

To demonstrate the economics of this design, asimple analysis comparing the KCS6 to the steam cycle wasperformed, assuming the end-user to be a U.S. publicutility.

ModelValuation of Incremental Output. A utility which

purchases a combined cycle plant with a KCS6 bottomingcycle rather than with a steam bottoming cycle receives12.1 MW more generating capacity with the identical fuelconsumption. In order to make an economic evaluation ofthe KCS6 system, it is necessary to determine the value ofthe 12.1 MW of incremental output and compare this valueto its cost. Plant costs and outputs on which this evaluationis based are summarized in Table 7.

tThesc are the costs to the end-user, i.e., the price at whichthe plant could be purchased.

TABLE 7

Comparison of Costs and Output: Steam vs. KCS6

Steam

Combined Cycle Total Cost ($ Millions) 113.1 127.9Net Plant Output (MW) 215.0 227.1Cost, $/kW 526.0 563.2Fuel Consumption (kWth) 429,940 429,940Heat Rate (BTU/kWh) 6,823 6,460Utilization (hrs/year) 6,000 6,000Million BTU/kW year 41 39

The value of the 12.1 MW can be measured in termsof the conventional (steam) plant. To acquire this extraoutput using a conventional combined cycle, the utilitymust pay an additional $6.4 million (at a capital cost of$526.0/kW) plus provide additional fuel at a consumptionrate of 41 million BTU's per kW annually. The KCS6requires no additional fuel to produce its extra 12.1 MW; ithas only a capital cost component. For the comparison tobe meaningful, it is necessary to convert the conventionalplant's fuel component to a present value. The followingassumptions are used in calculating the present value(which is shown in the section "Results"):

Price of Natural Gas $4.25/million BTUEscalation Rate - Gas 3%/yearLife of Plant

30 yearsWeighted Average

Cost of Capital (See Table 8)

10.35%Tax Rate 40%

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TABLE 8

Assumed Utility Capital Structure

Percentage

Debt 50.00Equity 50.00Pre-tax Cost of Debt 10.00After-tax Cost of Equity 13.50Tax Rate 40.00After-tax Weighted Average

Cost of Capital 10.35

Utility Indifference Point. The value of the totalKCS6 combined cycle plant can be derived by adding thevalue of the incremental 12.1 MW (the capital cost plus thepresent value of fuel expenses as described above) to thecost of the conventional plant. This is the price at whichthe utility should be indifferent in making a selectionbetween the two systems.

ResultsThe present value of the fuel cost for an

incremental 12.1 MW using the conventional system is$15.0 million. Adding this to the $6.4 million capital costyields a total value of $21.4 million for the extra 12.1 MWprovided by the KCS6. Thus, the utility should beindifferent between paying $113.1 million for aconventional plant with 215.0 MW capacity or $134.5million for a KCS6 plant with 227.1 MW capacity. On a perkilowatt basis, the utility is willing to pay up to $1,767 forthe extra capacity.

It was estimated that KCS6 sells for $14.8 millionmore than the conventional system. (See Tables 6 and 7.)Yet, it was just shown that the utility should be willing topay $21.4 million for the incremental output it produces.This difference is a measure of the gross economic profitcreated by KCS6. Some of this difference must be allocatedto the retooling and development costs of themanufacturer and for fees to license the technology.However, to the extent that these costs account for lessthan the $6.6 million difference between the utilityindifference point and the cost of production, there will beunallocated economic gain. If this results in the utilitypaying less than $21.4 million or $1,767/kW for theincremental output, equity investors will benefit fromhigher returns and/or electricity rates will fall.

There are two other factors which, although beyondthe scope of this analysis, increase the attractiveness ofthe KCS6, and are worth mentioning. First, since less fuelis consumed per kW of output, there is a direct reduction ofemissions. Second, the tax benefit from depreciatingcapital costs has not been considered in this analysis.Since the capital component of KCS6 is larger than for thesteam plant, the true indifference point is somewhathigher than represented.

SensitivityThe results presented above depend on the

underlying assumptions. An indication of the system'ssensitivity to varying three of the most critical parametersis given below.

Price of Gas. The value of KCS6 varies directly withfuel price. At a higher fuel price, the utility would bewilling to pay more for KCS6 since its extra output comeswith no additional fuel requirement. Table 9 shows theutility indifference points at various fuel prices.

TABLE 9

Utility Indifference Point vs. Fuel Price

Fuel PriceIndifference Point

Total Cost$/Million BTU's ($/kW) ($ millions)

3.00 1,402 17.04.00 1,694 20.54.25 1,767 21.45.00 1,986 24.06.00 2,278 27.67.00 2,570 31.18.00 2,862 34.6

Escalation Rate. Fuel costs were assumed to increaseat a rate of 3% per year. Given its historical volatility, aprediction of future prices is very difficult. Table 10 showsthe change in the indifference point given different ratesof escalation.

TABLE 10

Fuel Price Escalation Rate vs.Utility Indifference Point

Indifference PointEscalation Total Cost

$gt@ kW ($ millions)

1% 1,564 18.92% 1,658 20.13% 1,767 21.44% 1,892 22.95% 2,038 24.7

Price Paid. The indifference point was derived bydetermining the present value of the capital and fuelexpenditures which would be required to purchase 12.1MW under the conventional system. For this analysis, adiscount rate of 10.35% was used, which is the utility'sassumed cost of capital. If the utility can purchase thisincremental output at a price below the indifference point,it will earn higher returns. The internal rate of returnwhich results from purchasing the KCS6 at various pricesis shown in Table 11.

Purchase Price vs.

TABLE 11

Utility Internal Rate of Return

After-TaxPurchase Price Internal Rate

(5/kW) of Return

1,767 10.4%1,700 10.9%1,600 11.9%1,500 13.1%1,400 14.4%

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CONCLUSIONS

Based on performance and cost data presentedherein, a KCS6 bottoming cycle enjoys a 12.1 MW outputadvantage and a $6.6 million present value advantage overa double pressure steam cycle for operation in a combinedcycle with a Type 13E gas turbine at $4.25/106 Btu fuelprices. Higher fuel prices will increase the present valueadvantage further.

ACKNOWLEDGEMENTS

The authors wish to acknowledge the cooperation of ABBand, in particular, wish to thank Messrs. Peter Muller andHans Luthi of ABB for their assistance in developing thesteam cycle and KCS6 P&ID, and cost estimates. We alsowish to thank Lawrence Rhodes of Exergy, Inc. for hisassistance in the software modeling and analysis of theKCS6 design.

REFERENCES

1. Kalina, A. and Leibowitz, H., Applying KalinaTechnology to a Bottoming Cycle For Utility CombinedCycles, ASME 87-GT-35, Anaheim, June 1987

2. Kalina, A and Leibowitz, H., Off -DesignPerformance, Equipment Considerations and Selection ForA Kalina System 6 Bottoming Cycle, ASME Cogen-Turbo,Nice, 1989

3. Gajewski, W. et al., The Kalina Cycle,Thermodynamic Principles and Feasibility, VGBKraftwerkstechnik 69 No. 5, May 1989

4. Spencer, R. C., Cotton, K. G. and Cannon, C. N., AMethod for Predicting The Performance of Steam TurbineGenerators......6,500 KW and Longer, ASME 62-WA-209, N.Y.,1962

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