Fuel cell technology: Status and future prospects

Energy Vol. 21, No. 7/S, pp. 521-653, 19% Copyright 0 19% Elwier Science Ltd Printedin Great Britain. All rights reserved 0360-X42/% $15.00 + 0.00

Pergamon

FUEL CELL TECHNOLOGY: STATUS AND FUTURE PROSPECTS+,S

A. J. Appleby Center for Electrochemical Systems and Hydrogen Research 238 WERC, Texas A&M University College Station, TX 77843-3402 (Received 22 October 1993)

Abstract- Fuel cell generators are reviewed from the viewpoint of systems, markets, emissions, and cost-reduction. Their most attractive features are likely to be their unobtrusiveness, which includes very low emissions, combined with their availability in small sizes, allowing cogeneration at the widest range of sites. Unattended operation and very high availability will result in low O&M costs. System designs require rethinking with a view to cost reduction, to make them more attractive compared with competing technologies. This is being pursued by developers. The fuel cell promises to be an important energy conversion technology, which will help to reduce carbon dioxide emissions in the next century. This review covers progress in the phosphoric acid fuel cell (PAFC), molten carbonate fuel cell (MCFC) and solid oxide fuel cell (SOFC) technologies for stationary applications. Although not exhaustive, it attempts to review the literature in a general manner from 1989, when the last overview (Ref. 6) was published. It more extensively reviews papers and presentations at symposia and conferences from 1991 to May 1995. A general review of engineering activity to August 1995 is included. Copyright 0 1996 Elsevier Science Ltd. 1. INTRODUCTION Michael Faraday described electromagnetic induction in 1831, and Hippolyte Pixii invented a permanent-magnet ac generator in 1832 which could be made to produce electricity using the motive power of steam. By 1866-67, Werner von Siemens had invented the self-excited dynamo. The Edison and Swan lamps followed in 1879 and 1881. By 1882, the electrical age had dawned with the opening of small steam generating plants for the public distribution of electricity for lighting in London and in New York. The Fist large 10,000 V ac plant opened in Deptford in 1889 to supply a large part of London. The first central ac plant in Germany started operation in Lauffen in 1891 to supply subscribers in Frankfurt am Main. Ostwald, cofounder of the new science of Physical Chemistry along with Van? Hoff and Arrhenius, delivered a lecture in 1894 to the Bunsengesellschaft, the German national society dedicated I:Othe new subject.1 In it, he looked forward to a future in the next century where machines would operate on the principles of the new science, rather than on the laws governing the volume changes of gases under the influences of heating and cooling, which were established in the early days of physics. The new machines would operate without steam boilers, flames, soot and smoke and other forms of pollution. They would convert the chemical energy of fuels directly into work, rather than first converting it into heat via an inefficient thermal cycle. Ostwald clearly hoped that the steam engine, with its then 10% efficiency, would be replaced by an efficient and non-polluting machine to directly generate electricity from chemical energy sources, which would open up a new civilization in the coming century.

’ Invited review paper. Manuscript received 22 October, 1993. Revised and extended manuscript received 18 March, 1996. Dedicated to the memory of Manville J. Mayfield, US Department of Energy, USAir 427.8 September, 1994. His discussion and input to this review were much appreciated. $Fuel cell technology was reviewed in a special edition of the journal in 1986,viz. Energy, The Inrernarional Journal, Vol. 11, No. l/2, January /February, 1986, pp. l-230 (Ref. 626). The emphasis there was on the materials technology of fuel cell stacks. This review concerns the application of this technology to stationary power generation, with an emphasis on systems, economics, and commercialization. It updates the 1986 report on SOFC materials, since extensive work has been conducted in this area. In contrast, materials progress on the PAFC and MCFC has been much less significant since 1986. It complements the 1995 report on fuel cell commercialization in Energy, The International Journal, Vol. 20, No. 5, May, 1985, pp. 331-470 (Ref. 83 b) and its summary in Progress in Energy and Con&&on Science, Vol. 21, 1995, pp. 145-151 (Ref. 83 a). 521

A. J. Appleby

522

It was recognized during the nineteenth century that the electrochemical cell, or voltaic battery, represented the direct conversion of chemical energy into work. The law of the conservation of this energy, i.e., the first law of thermodynamics, seems to have been first stated by Grove2 in 1846, anticipating Helmholtz by one year. Grove invented a “gaseous voltaic battery” in 1839, which directly converted the chemical energy of hydrogen and oxygen into dc electricity at a platinum black anode and cathode immersed in sulfuric acid. This battery became recognizable as the core of today’s fuel cell after developments by Mond and Langer in 1889.3 Their cell contained two electrodes made from invariant high-surface-area catalytic materials, separated by a small gap containing a porous retaining medium for a concentrated, highly-conducting electrolyte in a flat structure resembling a capacitor. When the electrcdes were separately bathed in hydrogen and oxygen, or other suitable fuels and oxidants, a dc current could be drawn with a minimum of loss from internal resistance. Unlike conventional batteries with one oxidizable (fuel) electrode and one reducible (oxidant) electrode, a fuel and oxidant continuously supplied from the outside were consumed at invariant electrodes. Unlike the battery, the fuel cell was not limited in capacity by the quantity of oxidizable fuel and reducible oxidant stored internally. The principle of the fuel cell was known to Ostwald, and he had it in mind in his Bunsengesellshaft lecture. His dream, unfortunately, did not come about. The steam engine was improved until its efficiency ultimately reached 40%. and the internal combustion engine became the power source of choice for smaller uses. However, the advantages of the fuel cell which he observed are still there to be exploited, and one century later, it now promises to become a clean, efficient source of energy, for use beyond the year 2000. 2. FUEL CELLS FOR ELECTRIC UTILITY POWER The electrochemical core of the fuel cell generator, i.e., the part corresponding to a primary battery with fuel and oxidant generating dc power, may be nominally classified as either low- or high-temperature, depending on its operating conditions. The low-temperature fuel cells (LTFCs) include those with acid electrolytes, e.g., phosphoric acid fuel cell (PAFC) and perfluorinated polymer sulfonic acid (proton exchange membrane, PEM) cells operating at 180-210°C and 80-90°C, respectively, as well as those using alkaline electrolytes (AFCs, normally operating at 80°C). The high-temperature systems (HTFCs) use molten carbonate electrolytes (MCFCs, 600”-700°C operation) or solid ionic oxide electrolytes (SOFCs, presently 800°-1OOO’C operation). The maximum work that such an electrochemical celI can obtain from a given fuel is determined by the second law of thermodynamics. It is equal to the negative value of the effective Gibbs energy of reaction under the real conditions of operation. Assuming the reaction to be that of a fuel with oxygen, then the corresponding Gibbs energy is that for combustion at the temperature and under the reactant and product activity conditions at the reactor exit. All of today’s fuel cells use the direct electrochemical oxidation of hydrogen as their operating reaction. The reasons for this are practical and result from reaction chemistry. In low-temperature fuel cells, hydrogen has a reaction rate about four orders of magnitude higher than that most active carbon compounds, such as methanol, and perhaps eight orders of magnitude greater than that for saturated hydrocarbons, of which the simplest is methane. The reasons for this result from catalysis and poisoning. The hydrogen contained in, e.g., methanol, will dissociate and react rather readily on adsorption of the parent molecule onto a suitable electrocatalytic surface, of which the best example is a noble metal such as platinum. However, the oxidized carbon residue remains behind, effectively blocking the surface sites. As the temperature is raised, the carbon residue (adsorbed CO) will react, provided that an oxygen carrier is present to yield the final product, CQ. This oxygen carrier must inevitably be water or steam at the fuel cell oxidation electrode (the anode). If steam is present in quantity at high temperatures, the rate of direct reaction of the fuel molecule with water vapor to give C@ and/or CO, together with hydrogen (the steam reforming reaction) may become more rapid than the rate of electrochemical oxidation of the carbon part of the molecule itself. The steam reforming equilibrium depends on the temperature. For methane, the reaction is: CI-kt + Hz0

+

CO + 3H2.

+

CO2+H2.

This may be followed by the water-gas shift reaction: CO+HzO

Reaction (1) is favored at high temperatures where equilibrium (2) lies well to the left. At temperatures approaching 800°C, it occurs rapidly on suitable catalysts. In contrast, equilibrium (2) lies to the right at lower temperatures, where Equation (1) becomes irreversible. With methanol, the reaction corresponding to (1) will occur at temperatures as low as 3OO’C on suitable reforming catalysts, when reaction (2) can occur simultaneously in the forward direction, so that the final product consists largely of m and Hz. The above shows that a mixture of methanol and oxygen would be chemically transformed to C@ and H2 in the anode area of a fuel cell operating at 300°C, and that the fuel cell would rapidly oxidize the hydrogen produced. Methane, however, will fail to react with steam under these conditions. However, if the temperanne is raised to 650°C (the mean operating temperature of the MCFC), it will react at a sufficient

Fuel cell technology

523

rate on an additional catalyst to supply the anode with hydrogen. As this is consumed, it produces more steam, and thus will continuously drive reactions (1) and (2) to equilibrium. At 1000°C, the operating temperature of the SOFC, the steam-reforming reaction, will be spontaneous. The steam-reforming reactions are always more rapid than direct oxidation. Attempts to supply pure methane to HTFCs have not been not satisfactory, at least with conventional nickel-based anodes. In the MCFC, any direct oxidation of methane is certainly slow. In the SOFC, the reaction has been studied in more detail.4s It occurs at perhaps one-tenth of the rate of hydrogen oxidation on a metallic nickel cermet surface.s Since pure methane is not thermodynamically stable under anodic conditions in either the MCFC or in the SOFC, cracking of the fuel to a refractory, non-reactive carbon may occur. This reaction is not very rapid for methane, even on a catalytic metallic surface such as nickel. On a conducting ceramic electrode, e.g., cerium-gadolinium oxide examined under SOFC conditions, it is very SIOW.~ Cracking may be prevented by changing the gas composition to one in which carbon is not thermodynamic:ally stable. This may be done by introducing an excess of either carbon dioxide or steam. The latter is the usual approach, since it is technically simple and has rapid kinetics. A steam-to-carbon ratio of about 2.5 is normally employed. The electrochemical reaction then proceeds via the steam-reforming process, with hydrogen as the electroactive fuel at the cell anode. 3. HYDROCARBON

STEAM REFORMING

For natural gas (NG) fuel, it is possible to design a HTFC system in such a way that gas and steam feedstock can be internally reformed in the fuel cell itself, using waste heat from the cell to supply the endothermic reaction. This is not possible in a low-temperature fuel cell (LTFC), where the fuel must be treated externally using a state-of-the-art steam reforming reactor of the type used to supply hydrogen in chemical plants and refineries. The waste heat in the LTFC is available only at its operating temperature, therefore the endothermic enthalpy of the reaction must be supplied by burning fuel. However, the high steam-to-carbon ratio required to complete the reforming process requires a large steam input, an.d therefore it is advantageous to use waste heat available from the LTFC to raise this steam wherever possible. This will avoid burning more fuel, which would reduce overall system efficiency. It is therefore advantageous to use an LTFC operating at a temperature appreciably above the boiling point of water for this application, unless the efficiency of fuel conversion inside a cell operating at a lower temperature is sufficiently high to compensate for the extra fuel required for steam-raising. The PEM and certain other acid systems operating below IOO’C have a higher in-cell performance than the PAFC under comparable conditions. However, this does not compensate for the ability of I:he latter to supply steam for reforming. For example, to achieve the same system efficiency as that in a PAFC generator operating on reformed NG at a cell voltage of 0.65 V, a PEMFC system may have to operate at 0.75 V. The AFC, which may have an even higher cell performance than that of the PEMFC!, is a more extreme case. The acid electrolyte LTFCs will operate satisfactorily on a mixture of Hz and COz, i.e., on water-gas shifted reformate, if the CO concentration is reduced below the poisoning limit. The AFC has a more severe problem, since it has an electrolyte which reacts with CO2 to form carbonate, which prevents effective electrochemical operation. Thus, it requires the additional energy-intensive step of separation of hydrogen and C@, as well as the separation of CO2 from the air supply. This has rendered its application unfavorable for use with common fuels. The acid-electrolyte LTFCs will tolerate C@, but they suffer from poisoning by CO to a de,gree which depends on their operating temperatures. The PAFC will tolerate about 1.5% by volume of CO at 200°C, whereas the PEMFC at 80°C may only operate without significant loss at 3 ppmv. Thus, the PAIX requires a minimum amount of CO removal, represented by two-stage water-gas shift conversion. The high operating temperatures of the HTFC systems make them immune to CO poisoning, and the:y have the advantage of performing automatic internal water-gas-shift, so that they effectively consume CO directly via hydrogen as an intermediate. Energetics have therefore favored the PAFC, MCFC and SOFC for utility use on NG or other light hydrocarbons, which can be readily steam-reformed (e.g., naphtha). The fuel cells operate at their maximum temperatures consistent with material considerations to give the best cell performance. The reformer is a catalytic device, which is poisoned by sulfur compounds, so these must be removed to less than 1 ppmv levels before fuel processing. The catalytic anodes of the PAFC and MCFC also show limited sulfur tolerance. Since fuel cells operate at higher efficiencies and/or higher power densities when the reactants are pressurized, any excess waste heat from the fuel cell may be advantageously used in a pressurization cycle for both the fuel and air supplies. This cycle will be more efficient as the fuel cell temperature increases. This is already standard practice in PAFC systems with outputs greater than 1 MW. It is proposed for the HTFCs whose high-temperature waste heat can also be used in a bottoming cycle. The PAFC, IMCFC, and SOFC technologies will also operate on low- or medium-BTU coal gas from an air- or oxygen-blown gasifier. The resulting gas must be desulfurized, and water-gas-shifted in the case of the PA.FC, before introduction to the fuel cell anode.

A. J. Appleby

524

4. FUEL CELL GENERATOR SYSTEMS It is apparent that a typical PAFC plant is complex, consisting of the core dc power unit, which has a cooling system capable of raising steam. Water for this supply is recovered from the exhaust gases, but a water purification system is required. The fuel requires a desulfurizer unit before it is introduced into the reformer and remainder of the fuel-processing train. Heat is recovered from the fuel cell, reformer and shift converters for various operations, including steam raising and pressurization. The latter requires a series of blowers, compressors and expanders. Heat recovery requires a considerable number of efficient heat exchangers. Spent anode fuel, consisting of dilute hydrogen in C@, is burnt before or after water recovery in the reformer burner to provide the reaction heat. Finally, the dc power must be converted to utility quality ac via an inverter. This is shown diagrammatically in Figure 1 for the United Technologies Corporation (South Windsor, CT, later International Fuel Cells, IFC’) 4.5 MW demonstrator. This plant operated successfully at the Tokyo Electric Power Company (TEPCO) site in Goi, Chiba Prefecture, Japan, in the mid-1980s. The dc power section, the “fuel cell” itself, is a relatively small part of the whole, both in weight and volume, and in relative cost in mature production. The most expensive component in a mature unit is chemical plant represented by the fuel processing system. The HTFCs may be simpler than the PAFC, since they require no shift converters, and can have fewer heat exchangers and no separate reformer unit if they can operate using integrated reforming within the stack. This was already in use in the Energy Research Corporation (ERC, Danbury, CT) 20 kW MCFC demonstrator in the Pacific Gas and Electricity (PG&E) facility in San Ramon, CA, where testing took place in 1992. This project was supported by PG&E (until early 1993) and the Electric Power Research Institute (EPRI, Palo Alto, CA).

GLYCOL-WATER

1

(WTS)

DRY COOLING TOWER SUBSYSTEM

rIL WATER STORAOE SUBSYSTEM

SUPERVISORY

(DCTS) CILYCOL-WA

(WSS)

TER

COOLANT r-

f

I

CONTROL SIQNALS TO/FROM DC MODULE, PCS, ANCILLARIEB

Y

SUBSYSTEM

SUBSYBTEM

El-PRESSURIZED AIR SUBSYSTEM (PAS)

DISTRIBUTION FREQUENCY CONVERTER

I-+ AC

FROM

POWER QRID

Figure 1. Block systems diagramof United Technologies’4.5 MW (ac) demonstrator,Goi. Chiba Prefecture,Japan (1985). * The Power Systems Division of United Technologies Corporation(formerly the Pratt& Whitney AircraftDivision of United Aircra@ and Toshiba Corporationformed InternationalFuel Cells (IFC), a ventureto develop commercial fuel cells, in 1985. Toshiba holds a minority interest in the venture. IFC is now part of UTC’s Hamilton StandardDivision.

Fuel cell technology

5. THERMODYNAMICS

525

AND EFFICIENCY OF FUEL CELL POWER PLANTS

The fuel cell generator may be regarded as a black box in which fuel (kJ) enters and electricity (kWh) exits. Inside the black box, fuel is &sulfurized, mixed with steam and transformed to hydrogen, which reacts in the fuel cell to produce dc electrical power. To describe the thermodynamics of the system, it is most convenient to consider the heating values (enthalpy of combustion) and Gibbs energy of combustion of the fuel using electrical units in V/equivalent (or electron-volts, eV), rather than the conventional energy values in kJ/mole. Following engineering practice, heating values are considered positive, whereas enthalpies of combustion are negative. The Id/mole and eV units are related by nF, where n is the number of equivalents or electrons per mole, and F is the Faraday, 96,487 coulombs/equivalent (Joules/eV). For reactants and products in their standard states (1 atm for gases, liquid in equilibrium with saturated vapor), the higher heating value (HHV, enthalpy of combustion with liquid product water) of methane :is 1.154 eV, the lower heating value (LHV, gaseous product water) being 1.040 eV. These may be taken as equivalent to those of NG. The corresponding values for hydrogen are 1.482 eV and 1.254 eV. The difference between the LHV value of hydrogen and that of NG must be supplied by providing the enthalpy of reforming. If the hydrogen is supplied to a perfect thermodynamically reversible fuel cell operating at 298 K (25’C). the voltage of the cell will be numerically equal to the Gibbs energy of combustion of hydrogen with the sign reversed. At 298 K, for hydrogen and oxygen in their standard states (1 atm), the value is 1.223 eV for liquid water product, and for gaseous water in its standard state (1 atm) at 298 K (lOO’C!) it is 1.164 eV. Reversible losses occur if the gases are not in their standard states, and when net current flows, irreversible losses occur due to the slowness of the reactions, concentration changes due to diffusion, and finally to the effects of internal resistance. In low temperature cells, the largest losses occur due to the slowness of the cathodic (oxygen reduction) reaction. As temperature increases, the Gibbs energy of combustion becomes more positive, but the irreversible losses decrease. Practical utility fuel cells operate with gaseous water as a product. Figure 2 shows the -eV values of Gibbs energy of combustion of hydrogen to gaseous water as a function of temperature for standard states. However, practical fuel cells cannot normally operate under standard state conditions. If they are operated at atmospheric pressure, they are supplied with a H2-CO2 mixture from the reformer at the anode, and with air containing 0.2 atm of 02 at the cathode. After reaction in the cell, the anode product is dilute hydrogen in C@, and the cathode product is depleted air. One exit stream (depending oci electrolyte chemistry) contains most of the product water, which is in the vapor state (except in the PEYMFC). The maximum theoretical voltage the cell can develop under reversible conditions corresponds to the Gibbs energy of combustion under cathode exit conditions. From the Nemst equation, this will differ from the standard value by an amount equal to (RT/2F) In [pH2][pO2]ln/[pH20], where R is the gas constant, T is the absolute temperature, and the p values are the partial pressures of the reactants and producis. With the partial pressures expressed in atmospheres, this expression is equal to (9.91 x lo-5)T ~og~o~p~~~po211Tz/~~~2~l volts. Figure 2 shows two plots of the theoretical reversible voltage at the cell exit assuming conversion of 85% and 90% of the hydrogen in reformed NG feedstock to product water. While oxygen utilization of 30% is assumed, this correction is small. It can be seen that the deviation of the result from the theoretical line for pure hydrogen increases with T. If the reformate can be supplied under pressure, the theoretical voltage will be correspondingly raised. The plot includes a series of typical operating points for the PAFC, MCFC and SOFC. Those for the PAFC include the effect of pressurized operation. Losses are much less for the HTFCs, but the cell voltage developed in practice by each technology is more or less independent of its operating temperature, due to the effect of reversible thermodynamics at the higher temperatures. From the Nemst expression, operation of the PAFC at 8.2 atm pressure should increase the cell voltage by only 21 mV. The effect is considerably more than this (about 60 mV, see Figure 3) due to the effects of irreversible kinetics. These become less significant as temperature increases. Finally, Figure 2 shows the enthalpy evolved in the reaction, which is the difference between the available Gibbs energy obtained as electricity (corresponding to the cell operating voltage) and the lower heating value of the hydrogen fuel mixture. corrected for the effect of partial pressures. As we have stated above, this enthalpy can be usefully employed in the process or, where appropriate, used for a bottoming cycle or cogeneration purposes. The “black box” efficiency of a fuel cell generator operating on NG can be best appreciated by considering a HTFC internal reforming system, i.e., a MCFC operating at an average temperature of 65O’C (CO + Co;! shift equilibrium constant = 1.96). We can simplify the thermodynamic argument by ignoring second-order effects, such as changes due to the sensible heat content of gases as a function of temperature and corrections for gas partial pressures. In any case, some of these tend to cancel in heat-exchanging gas streams. If the fuel cell operates at 0.76 V. then the total enthalpy available from Figure 2 will be about -0.494 eV for each equivalent of hydrogen consumed in the cell. However, we have already seen that the hydrogen utilization in the cell will not be 100%. The probable utilization range will be 75%-85%, although 90% may be possible in some systems. The reason for this is the low partial pressure of hydrogen in the anode gas as the stxeam approaches the cell exit. Since the cunent density at a given cell voltage depends on the partial pressure according to the laws of chemical kinetics and/or gaseous diffusion, the curnznt density inevitably drops as the mixture of hydrogen and carbon oxides passes through the cell. Uhimately, the

A. J. Appleby

526

current density will be so low that the cell area will be uneconomically used, so one runs into a situation of diminishing returns. The steam energy to provide an assumed steam-to-carbon ratio of 2.5 : 1 on methane (natural gas) fuel (equivalent ratio 5 : 8) is the difference between the enthalpy of formation of 0.625 uivalents of gaseous and liquid water in iheir standard states. This is about +O.143 eV. The net enthalpy “8 o reforming is +0.214 eV if the product is pure hydrogen. However, some C@ and H2 arc shifted to CO (heating value, 1.467 eV) in the cell, giving an anode exit gas with a higher heating value than that of pure hydrogen (see below). The effective heating value of the anode exit stream is 1.332 eV per equivalent, and it repsents 25% of the methane throughput into the cell, i.e., 0.332 eV per equivalent of methane. Upgrading to this mixture from pure hydrogen requires a total of (1.332 eV - 1.254 eV) x 0.25, i.e., tO.0195 eV. At 75% utilization, the total available enthalpy from reaction of hydrogen within the cell will be -0.494 eV x 0.75 - 0.0195 eV, i.e., a.351 eV. This is more than enough for the overall reforming reaction (i.e., conversion 100% of the methane feedstock to hydrogen in the cell, which requires +0.214 eV). About -0.137 eV of waste heat will be available from the stack to raise most of the steam. The internal reforming reaction will therefore proceed spontaneously, provided that the rates of reaction on suitable catalysts are sufficiently high at the cell operating temperature. Thus, each equivalent of methane entering the cell (LHV 1.040 eV) will yield one equivalent of hydrogen. Each equivalent of hydrogen reacting in the cell will yield 0.76 eV of electrical energy. The LHV efficiency of conversion of methane to dc electricity in the cell is therefore given by 0.76/1.040 or 73.1%. This is the “in-cell” efficiency. To obtain the overall gross dc LHV efficiency, this must be multiplied by the hydrogen utilization within the cell, i.e., 75%. The gross dc LHV efficiency will be 54.8%. In effect, the cell behaves as a thermodynamic black box consuming -1.040 eV of methane, and producing - 0.76 eV x 0.75 (-0.57 eV) of dc electricity, -1.332 eV x 0.25 (4.333 eV) of anode exit gas, and ( -1.040 + 0.57 + 0.332) = -0.137 eV of sensible heat. The enthalpy (i.e., waste heat) evolved in the stack is -0.240 kWb per kWe, and the enthalpy of combustion of the exit gas stream is -0.595 kWh per kWe. 1.4

Heating Value of Hydrogen

Lower & 1.2

Cell DC Efficiency (HHV) (hydrogen fuel)

>

1.0

85% ut

., rJ 2

- 70

B 2

90% ut

- 65

0.8 PAFC-1

.

- 60 - 55

PAFC-2

0.6

- 50

??

- 40

- 45 - 40

- 35

0.4 0

I

I

1

400

800

1200

Temperature,

- 35

- 30 1600

K

Figure 2. The Gibbs energy (-AG in eV) of the hydrogen-oxygen couple as a function of temperature(K) and hydrogen utilization. The enthalpy of reaction (-AH in eV) is superimposed. Values are for gaseous reactantsand products. Operational data points: PAFC-1: International Fuel Cells (IFC) PC23A pressurized PAFC, 0.22 A/cm?; PAFC-2: 200 kW atmospheric pressure IFC/ONSI PC2SC PAFC at ca. 0.3 A./cm? MCFC: reformate fuel (or internal reforming) at 0.16 A/cm 2; SOFC-1, 2: Westinghouse Electric Corporation SOFC (1994), reformate fuel (or internalreforming) at 0.15.0.30 A/cmz, respectively. Right axis - correspondinghigher heating value (HHV) efficiencies on hydrogen at 90% and 85% utilization. The multiplier to obtain lower heating value (L&IV)efficiencies is 1.18.

Fuel cell technology

521

The above assumes 100% reforming of the methane feedstock in the fuel cell stack. If the conversion is only 97% at 75% fuel utilization, the exit gas will contain the 3% of methane remaining (see below). This results in an exit gas with a slightly lower enthalpy of combustion (-0.322 eV), and a correspondingly larger amount of waste heat (-0.148 eV, 0.26 kW* per kW,). The composition of the exit mixture depends on the chemistry of the system. In the SOFC, which conducts via oxide (O=) ions produced by oxygen reduction at the fuel cell cathode, water is produced at the anode via the electrochemical reaction of O= with hydrogen. In the SOFC operating at 1,OOO“C(shift equilibrium constant = 0.58), an NG reformate mixture with a steam-to-carbon ratio of 2.5 : 1 in a cell operating at 85% utilization will exit at 2.9 mole % CO, 8.0% HZ, 15.3% CO2 and 73.8% Hz0 after equilibrium water-gas shifting. In the MCFC, conduction is via carbonate (CO3”) ions produced by reaction of O= ions (from oxygen reduction) with m, which must be supplied to the cathode gas stream to allow the cell to operate properly. As a result, one CR molecule is formed at the anode for each molecule of water formed, and this CQ must be transferred from the anode exit stream to the incoming cathode gas. Thus, at 85% fuel utilization for NG reformate at a steam-to-carbon ratio of 2.5 : 1 and an exit temperature of 685°C (shift equilibrium, = 1.65), the anode exit gas composition will be 2.6% CO, 4.2% Hz, 46.8% CO2 and 46.4% H20. This indicates that, all other things being equal, the SOFC should operate more effectively at higher utilization than the MCFC, since its exit gas composition is richer (10.9 mole % CO + HZ, compared with 6.8 mole %, both at 85% utilization). As a result, the MCFC is generally operated at 75% utilization (see Section 13), when the exit composition under the same conditions will be 4.3% CO, 7.5% HZ. 42.7% CO2, and 45.5% H20. If the methane reforming efficiency is only 97%, the exit gas at 75% total fuel utilization will contain 3.37% CO, 7.06% Hz, 0.36% CI+, 43.66% CO2, and 45.55% H20. The change in equilibrium Hz from the assumed 100% methane conversion case is small, and would have little effect on anode electrochemical kinetics, so little change in overall performance would be seen. The PAFC conducts via protons (H+) produced by reaction of hydrogen at the anode. These migrate to the cathode, where they react electrochemically with oxygen, producing water. Thus, no water is formed at the PAFC anode, and a model reformate (at a steam-to-carbon ratio of 3 : 1) would become 23% Hz, 38.5% CO2, 38.5% H20, and at 85% hydrogen utilization. Real, shifted reformate might have the exit composition 3.4% CO, 21.9% Hz, 34.0% C@ and 40.7% H20. No significant water-gas shift occurs in the cell, because of the its low operating temperature. Partial equilibration of water vapor partial pressure may occur across the electrolyte. For every 4 molecules of hydrogen passing through the anode at 85% utilization, 17 moles of nitrogen-oxygen (air) mixture are required at 50% oxygen utilization. This would exit containing 18.2 mole % water vapor if no equilibration takes place. The degree of equilibration depends on mass transport considerations, but if it is complete, the depleted model reformate would lose approximately 58% of its residual water vapor, so that the exiting anode and cathode gases will both contain 21 mole % of water vapor. However, in most cases little equilibration of water vapor parti.sl pressure appears to occur in the PAFC at normal operating temperatures. 6. THE HTFC: INTERNAL VERSUS EXTERNAL REFORMING In the above example of HTFC efficiency with internal reforming, it is assumed that the anode exhaust gas will not be further used to generate electricity. However, if some method existed to separate the exit gases efficiently and permit recycling, further use of recycled fuel may be possible, thus the overall utilization may be effectively increased. If all of the hydrogen could be separated and used in the cell, then the gross system dc efficiency, before accounting for parasitic losses for pumping and separation work, would be the same as the in-cell efficiency, i.e., 73.1% in the above example. In the absence of a hydrogen separation device, the heat available in the anode exhaust gas may be used for process heat, cogeneration, or in a combined cycle. At 85% utilization in the SOFC, the LHV of the anode exit stream is 0.15 x 1.311 eV, i.e., 0.197 eV per equivalent of methane entering the system. At the same utilization in the PAFC, the corresponding LHV is 0.192 eV. At 75% utilization in the MCFC, the value will be 0.332 eV. This energy can be used for external reforming, in cogeneration,, to supply auxiliaries, or in a bottoming cycle. Finally, the steam product may be condensed to supply some further cogeneration energy in the form of hot water. There are two options in internal or in-stack reforming: first, so-called indirect internal reforming (IIR) which takes place in separately-manifolded reaction chambers arranged like cooling plates throughout the stack; and second, in the option called “direct internal reforming” (DIR) on suitable catalysts within the anode chamber itself. The IIR option was first used in the ERC San Ramon MCFC and its precursors. Its advantage is that the catalyst beds are protected from deactivation by carbonate, but larger amounts of catalyst are required, since the reaction is not locally “driven” by the simultaneous oxidation of hydrogen and production of the steam reactant, which can only take place in direct reforming in the anode chamber. In practice, the IIR option is followed by DIR in the anode using a special catalyst section there. The reaction in the IIR chambers may certainly not reach equilibrium, which would correspond to about 98% conversion of CI-kl under typical 2.5 : 1 steam-to-carbon ratio conditions at 650°C. About 80% reforming in these plates is often assumed. The reaction should then go to completion under driven conditions on the

A. J. Appleby

528

DIR catalyst. However, this may degrade with time, and the reaction may only go to some percentage of completion. As we saw above, the assumption of 97% completion will not significantly decrease cell output. The exit gas composition under these conditions is far from reforming equilibrium (mass-action ratio 0.007, equilibrium constant, = lo), and represents a situation with a deactivated DIR catalyst. Even higher methane exit concentration are permissible before significant performance reduction would be expected. For example, an overall methane conversion of 90% represents 83% hydrogen utilization in the cell at 75% overall fuel utilization. This may result in a loss of ca. 40 mV compared with 75% hydrogen utilization at 100% methane conversion. In the SOFC, direct reforming at l,OOO°C can take place on the anode catalyst alone. However, it is so rapid that it tends to cool the leading edge of the electrochemical cell to the extent that this area becomes electrochemically inactive. Thus, reforming is then controlled by radiative or conductive heat transfer, and the system requires careful design for effective coupling. This design has so far been regarded as a secondorder development in the SOFC, and nearly aII SOFC systems to date operate using external reforming. However, the fact that it operates satisfactorily in the lower-temperature MCFC demonstrates its future potential for use in the SOFC. The higher hydrocarbons present in real NG can be satisfactorily handled in the MCFC, and presumably also in the SOFC. The thermodynamics of the HTFC internal reforming case are readily comprehensible. There are more difficulties in understanding the external reforming case, which does not use fuel cell waste heat except to raise steam. An internal (in-stack) reformer operating at a low space velocity (corresponding to the mean rate of the fuel cell anode reaction) will perform satisfactorily at a temperature as low as that of the MCFC stack (650°C average). In contrast, a compact, high space velocity external reformer must operate at about 8OO’C to achieve useful reaction rates. Reforming of CHq proceeds mainly to CO + 3H2 under these temperature conditions, with partial shift to C@. The effective LHV of the reformate is a compromise between the heating value of pure CO (1.467 eV) and the LHV of H2 (1.254 eV). The composition at a NG reformer exit temperature of 81O’C (shift equilibrium = 1.0) and steam-to-carbon ratio of 2.5 : 1 at 97% conversion will be 12.8% CO, 58.5% Hz, 0.6% CIQ. 5.0% C@, and 23.1% H20. The LHV of this gas will be 1.284 eV. Since the LHV of methane is 1.040 eV, 0.244 eV is required for upgrading, with a correction for differences in the sensible heat content of the input and exit gas streams between 25’C and the reforming temperature, plus reformer losses. Feedstock gas could be burned to provide the necessary energy, but in practice, it is more efficient to employ the anode exit stream, which might otherwise be wasted, plus any further gas required. If we take the real reformer efficiency as 95% based on the LHVs of the input and exit gas streams at 25’C, -1.352 eV total enthalpy input will provide product gas with a heating value of 1.284 eV at an external reforming,

reforming

temperature

of about 800°C.

Hence, -0.312

i.e., -1.361 eV minus -1.040 eV feedstock input.

eV of enthalpy

will be required for

The anode gas stream can provide -0.197

eV in the SOFC (85% utilization, 100% CI-kt conversion) and -0.322 eV in the MCFC (75% utilization, 97% CHq conversion). In the MCFC, this can be provide all of the enthalpy of reforming, whereas in the SOFC, the higher utilization means that supplemental fuel must be burned, unless the sensible heat from the stack can also be utilized. Because of heat losses, the efficiency in external reforming cases may be about 35 % less than the gross efficiency in the internal reforming case given above. From the systems viewpoint, one of the most important differences between external and internal reforming lies in the cooling requirements. If the above external-reforming MCFC cell operates at atmospheric pressure at 0.76 V on reformate with an LHV of 1.284 eV (97% CI-kt conversion), the cooling requirement is 0.688 kWth per kW of dc electrical output, after correction for water-gas-shifting requirements for the anode exit gas. If the cells operate on NG (1.040 eV) using internal reforming at the same cell voltage, the cooling requirement is considerably reduced. In the 75% utilization MCFC case considered above, the total waste heat was 0.240 kWu, per dc kW, (100% CIQ conversion), or 0.26 kWu, per dc kWe (97% conversion). Thus, cooling air flow (process air) can be reduced by 62-65% by internal reforming under these operating conditions, which means that the most economical combination of smaller flow channels and reduced parasitic work for circulation of air may be used. In addition, IIR-DIR reactive cooling requirements can be arranged to obtain more uniform temperature profiles within the stack and more desirable exit temperatures. This is discussed in Section 27 in more detail. In the SOFC operating at an exit temperature of 1,OOO’Cat 0.65 V and 85% fuel utilization (100% CH4 conversion), the corresponding figures are (external reforming) 0.967 kW,h and (internal reforming) 0.526 kWtJ, per dc kW,, respectively. Thus, the use of internal reforming in the SOFC could reduce cooling flow requirements by 45% with these assumptions. 7. EXTERNAL REFORMING:

THE PAFC

In the PAFC, the anode gas feedstock must be water-gas shifted to a mixture of CO;! and HZ to avoid anode poisoning. This produces medium-temperature heat equal to the difference in LHVs between the CGrich input and Co-poor output streams. In practice, this may be about 1.28-1.25 eV, i.e., 0.03 eV. Some of this can be collected, e.g., as steam, and used for auxiliary purposes. For example, at 80% hydrogen

Fuel cell technology

529

utilization, 0.25 eV of heat is available in this stream. Again assuming a reformer efficiency of 958, 0.057 eV of extra fuel must be burned to complete the requirement for reforming. As before., waste fuel cell heat is more than enough to provide the steam requirement. If the cell operates at 0.70 V, the gross system LHV efficiency will be (0.7 x 0.8)/(1.040 + 0.057) or 51.0%. The LHV efficiency of this model reformer based on a different criterion, the total fuel requirement, is compared with the net product hydrogen actually used in the fuel cell, which would be 91.4%. The performance of the IFC PAFC designs has been extensively described in the literature. The 11 MW PC23 was &signed to be operated at 0.73 V per cell, under 8.2 atm absolute pressure (atma), i.e., 7.4 kg/cm2 gauge (see p. 73 of Ref. 6). The design fuel utilization was 85%, and oxygen utilization was 70% to reduce pressurization work. Pressurization was provided by heat recovery via a turbocompressor, which operated partly on waste heat from the reformer exit gas and partly on an auxiliary burner. The net HHV efficiency of the system was 41.1% or about 43.7%, after auxiliaries and dc-ac conversion losses had been accounted for. This corresponds to a gross LHV efficiency of about 48.6%. At 0.73 V and 80% utilization, calculation shows that 0.162 eV of extra fuel is required per equivalent of methane. Thus, the heat required for fuel processing is this amount plus the heat content of the anode exit stream. (0.25 eV), i.e., 0.412 eV, which provides the theoretical heat of reforming (about 0.24 eV). The overall pressurized reforming LHV efficiency, expressed as total fuel energy divided by that of the net reformate used in the fuel cell, is 83.5% (88.9% HHV), which is considerably less than that assumed for the model
530

A. J. Appleby 1 .o

I

I

I

Reformate 0.9 MCFC 0.8 W F C 9

0.7

\

PAFC

0.6

0.5

0

200

100 Current

Density,

300

400

rnA/ctn2

Figure 3. Performance of state-of-technology fuel cells (dc modules). NG reformate fuel at standard utilization (PAFC, 80%; MCFC, 75 C; SOFC, 85%). PC23 - IFC 0.93m2 PAFC cells operating at 8.2 atma. 200 kW - JFC/ONSI PC25 atmospheric pressure PAFC on-site unit. Atmospheric pressure ERC MCFC (1994 earlylife data, curved line after 0.14 A/cm2 extrapolated). Westinghouse SOFC (early-life results after March 1991, compare Figure 5). 60

32 50

100

150

Current

200

Dendty,

250

300

350

400

tnA/cm’

Figure 4. Results in Figure 3 for complete systems (NG HHV - ac power system efficiency as a function of operating cell current density). Sensible heat reforming SOFC is at 85% utilization. Atmospheric pressure MCFC uses internal reforming at 75% utilization (simple system) and more complex system at 85% utilization. The sum of dc-ac conversion efficiency and parasitic loss assumed to be 5.25%.

Fuel cell technology

531

The PAFC system efficiency is less than that of the external reforming HTFCs at the same cell voltage, because of the problem of heat integration. The HTFCs can use cell waste heat for reforming (i.e., sensible heat in the gas streams). This is not possible in the PAFC. which in addition must be burdened with a large number of heat exchangers for efficient heat recovery, which add to system complexity and cost. State-oftechnology HTFCs may be able to attain the value of ca. 52% &I-IV, gross) or 50% (net) at 0.73 V per cell, whereas today’s PAFC is limited to 47% (LHV, gross) or 45% (net) at this cell voltage. Thus, the PAFC may show 5% lower LHV efficiency than the HTFCs under comparable electrochemical conditions. This difference may be reduced in the future by better design, provided that it does not increase capital cost to levels which significantly increase the cost of electricity. To date, this aim has been achieved by increasing the cell voltage to the highest value consistent with the materials which can be used in the cell and power density. Increasing operating voltage involves more corrosion, and causes increasing decay and &creasing lifetime.* This factor, together with the capital costs of stacks, allowed the point of best performance to be identified (at least using early 1980s fuel costs) at 0.73 V per cell (at 2.16 kA/m2,200 A/ft2) in the 8.2 atma IFC pressurized unit. This had no usable waste heat is available for cogeneration purposes, but waste heat recovery for pressurization effectively constituted a bottoming cycle. Optimization results in a voltage of about 0.65 V/cell (at about 3.0 kA/m2,280 A/ft2) in the 200 kW IFC PC25C unit, in which the quantities of electricity and cogeneration heat are about equal. The on-site unit must compete with delivered electricity costs, not central generating costs before transmission and distribution. These permit a lower heat rate and a higher capital cost. The latter is further subsidized by the sale of cogenerated heat. Whether the efficiency of the PAFC can be significantly improved by further increasing cell voltage in the future depends on material considerations. If no catalytic improvements occur, voltage at a higher current density per unit area could be increased by increasing the operating pressure. This results in another series of trade-offs, since more heat will be required for turbocompressor operation, and higher pressure steam will be required in the reformer, which in turn requires a higher temperature steam source, i.e., the fuel cell stack itself. At a higher stack operating temperature, the current density at a given stack voltage (which has already been itself increased by operation at higher pressure) will increase. This wi.11lower the per kW capital cost by increasing the stack power density. Unfortunately, material problems intervene again, since corrosion increases not only with operating voltage, but also with operating temperature and with water vapor pressure. The differential increase in cathode material corrosion rate resulting from each of these independent variables is additive, thus there is an operating limit with the present graphite cell constructional and catalyst support materials, as well as with the high-surface area platinum alloy cathode catalyst itself. In 1985,* it was felt that a possible trade-off would be to increase both the precious metal catalyst loading in the ceil stack and the current density. For example, a doubling of platinum alloy loa.ding by the use of electrodes with 20 wt % of supported catalyst on carbon, rather than 10 wt %, could allow a doubling of current density. At that time, the total loading was 7.5 g/m2 for 10% by weight of catalyst on carbon. This area could produce 1.6 kW with these electrodes, for a catalyst cost of about $100 at today’s prices (4.75 g/kW of platinum, i.e., $6O/kW). However, the total cost of early production stacks was perhaps $1,6OO/m~. Doubling the platinum loading, i.e., increasing the total cost to $1,7OO/m:2, but at the same time doubling the cunent density at constant voltage, would reduce the stack cost per kW from $1,000 to $53O/kW. Unfortunately, the increase in current density obtained by increasing the Pt catalyst loading is not linear. It is close to 35% for the first doubling and about 60% for the second doubling, since an increase in loading leads to a rapidly diminishing catalyst utilization. Hence, this tactic has not been usually pursued as a means of reducing cost. However, it is still viable. An increase in loading from 10 to 30 wt % will increase the cost of the stack in the above example from $1,600 to $1,8OO/m2, and it will allow a real increase in power density from (for example) 1.6 to 2.4 kW/mz. Thus, the stack cost for units high up the learning curve would fall from $1,000 to $75O/kW. This approach has been pursued in Japan by N. E. Chemical Corporation (formerly Nippon Engelhard). This is discussed in Ref. 9, which includes an update on Japanese work up to 1991. Whether the present operating conditions represent the limit beyond which performance decay will result in uneconomic operation is still unclear. In the review written in 1985, this was felt to be so.* In principle, a catalyst loading increase from 10 to 30 wt % for the same electrode carbon content could increase the cell potential by 40 mV at the same current density. 9 This, in turn, could increase the system efficiency from 45% &I-IV) to 47.5%. However, a more rapid decay rate is almost certain to bfe observed, so that the mean lifetime efficiency will be less than that anticipated. As a result, performance (i.e., efficiency) improvements in the PAFC may be best addressed by changes in chemical engineering system design, as well as by improvements in mechanical house-keeping, e.g., turbocompressor efficiency. An efficiency improvement can be traded off, as necessary, against the overall capital cost by operating the stack, and therefore, the entire system, at a higher power density. Whether significant improvements can be made by reconfiguring the system via a different series of engineering tradeoffs is moot. There are some possibilities, however. The Westinghouse Electric Corporation (Large, PA) air-cooled PAFC system design operated at a rather modest cell voltage under pressurized conditions, but its efficiency wa;s increased to levels which are not very different from those of pressurized IFC designs by incorporating a steam condenser to operate the turbocompressor. The steam was obtained using fuel cell waste heat in excess of that required for the process (reforming) steam in a simple bottoming cycle, which improved the electrochemical power output, rather than giving extra mechanical work via shaft output.6gr0 Other

532

A. J. Appleby

methods of using waste heat from the system in a more effective manner might include the use of the cathode exit air in the reformer, which carries sensible heat from the cell and is already pressurized. This could improve overall performance by about l-28. However, the cathode exit gas is both humid and somewhat depleted in oxygen, therefore a catalytic reformer burner is necessary if this device is used This approach was taken by Toshiba Corporation (Chiyoda-ku, Tokyo) in work leading up to the late 1980s pressurized Japanese 1.0 MW demonstrator unit.11 Turbocompressor performance can also be increased. Very small turbocompressors were developed for PAFC systems in the 50 kW class, for example for the Fuji Electric Company (Chiyoda Ku, Tokyo) by Ishikawajima-Harima Heavy Industries Co. Ltd. (IHI, Koto-ku, Tokyo) in the mid-1980s. Their efficiencies and compression ratios were rather low (60% and 2.0), so their value for increasing system efficiency is questionable, although they could increase power density and reduce system capital cost. However, in the larger sizes, great strides are being made in improving compressor efficiency, which will be reflected in improvements in overall system efficiency. Some examples will be quoted later. Combinations of the PAFC system and the advanced cycle Heron turbine, acting as a turbocompressor, have been described.12 These systems would use the fuel cell as a topping cycle for the turbine. The prototype Heron turbine (Model-O) was a three shaft machine with a low compression ratio system (7.47 in the prototype) with a recuperator operating in an advanced cycle. It attained an efficiency of 38% (LHV) in an experimental unit of only 9.50 kW and 44% (LHV) was expected in a 1.5 MW unit.13 Above PAFC sizes of about 3 MW, this turbine-fuel cell combination could reportedly increase the system efficiency over that of the PAFC generator itself by as much as 5-lo%, allowing 55% (LHV) to be attained. As is discussed in the Conclusions (Section 29) of this review, the higher quality waste heat available with HTFCs should allows LHV efficiencies of about 70%. Such innovations merit future examination. 9. THE UTILITY FUEL CELL GENERATOR:

EFFICIENCIES

AND COSTS

The average generating efficiency of installed capacity today is about 38% in Europe and Japan, and about 34% in the United States. A pressurized PAFC operating on NG fuel or other clean light hydrocarbons has an LHV efficiency of about 45% today. While this is higher than the average, this does not mean that it will automatically find a role, since an efficiency of 45% is by no means exceptional. The latest generation of gas turbine (GT) machines in the 20-100 MW class can achieve LHV efficiencies of 34% or more on NG, and 52% or more is attainable with a Rankine combined cycle (GTCC). They are available at about $800-$85O/kW, but require scale-up to about 100 MW or greater to achieve satisfactory steam cycle efficiency. Their efficiencies can also be expected to be a moving target, as turbine inlet temperatures improve beyond 1,260”C (2,30O’F), by the use of improved materials and improved turbine blade cooling techniques, and by the use of advanced cycles. The latter included humidified air cycles. In 1994, Asea-Brown-Boveri (ABB, Heidelberg, Germany) was proposing the GT24 and GT26 range of machines with reheat, producing 150-250 MW with 58.5% LHV efficiency in a GTCC. The efficiency of the PAFC may be improved in the future by using system improvements. rather than electrochemical improvements, i.e., in electrode performance in the stack itself. As has been indicated in the last section, conventional approaches may increase its efficiency by, at most, 4% to yield a machine with a heat rate of 7,730 BTU/kWh, 8,150 kJ/kWh (HHV), corresponding to a LHV efficiency of 49.0%. It is clear that the efficiency of the PAFC alone will not allow it to compete head-on with the advanced GTCC. The use of integrated turbine technology of Heron typerz~rs may substantially decrease these heat rate values, and this may change the competitive strategy for dispersed units in the 5 MW class and above. The PAFC fuel cell generator is a complex technology in the early stage of production development, and is therefore a high capital cost system at this time. A number of analyses of PAFC economics were produced during the 1980s. They are summarized in Refs. 6, 14, and 15. Most of the analyses involved the theoretical fitting of costs to a postulated production learning curve. It is now conceded that for a niche market penetration, the PAFC must have costs less than about $1,67O/kWt for electric utility units, and preferably $1,340/kW.16 If the fuel cell generator is regarded as a dispersible technology, it can be sold at a premium over conventional generating capacity. The average investment in transmission is about $550$6OO/kW in most countries.16 If the dispersed PAFC can avoid new transmission capacity, a capital cost of $1,34O/kW will compete with a $8OO/kW central generator, provided that O&M costs am acceptable. The niche-market fuel cell generator may have a cost as high as $2,8OO/kW for on-site cogeneration units in locations where delivered electricity costs are high, and heat can also be sold as a commodity.17 The production costs of early PAFC units were high. The 4.5 MW IFC demonstrator at Goi in Japan, which operated in the mid- 198Os, cost $25 million (1980 dollars) or $5,5OO/kW (1980, about $lO,OOO/kW in 1995 dollars). Even so, its cost was 40% less than that of the 4.5 MW demonstrator in New York City, which was under construction in the late 1970s and finally only operated as a gas generator. In 1986, IFC was offering the first three units of the 11 MW PC23 at $4,8OO/kW (1995), with the next twenty units at $2,4OO/kW.6 In the 11 MW Goi demonstrator, which used IFC PC23 PAFC stacks and design, with Tokyo Electric Power Company-Toshiba engineering, the cost of the stacks themselves was about 50% of

t Unless otherwise stated, costs are given in mid-1995 dollars, corrected using the Implicit price Deflater, Bureau of Economic Analysis, US Department of Commerce.

Fuel cell technology

533

the total cost of the system. The sponsors hoped that stack costs would eventually be reduced by a factor of ten, to about $300-35O/kW (1995). in mass production. It is reasonable to suppose that PAFC unit costs will go down as developers proceed along the learning curve. A case in point is the experience of Kinetics Technology International (KTI, a subsidiary of Mannesmann Plant Construction, Zoetemeer, the Netherlands, a manufacturer of steam-reforming hydrogen plants)12 who designed and built a number of small demonstration PAFC plants. The first was designed by KTI and built by Engelhard Industries and KTI. It was successfully operated with a 25 kW Engelhard stack for almost one year. A second unit was constructed using a 25 kW Fuji Electric stack, which operated at the Delft University of Technology in the Netherlands, starting in October 1989. Due to an operational error, the stack was flooded with water and had to be replaced. A similar unit was designed for operation at Casaccia, Italy. An 80 kW unit, also using Fuji Electric stacks with commercial guarantees was built for the Bavarian Solar Energy Project (Solar Wasserstoff Bayem), Germany. The cost of the Delft plant was $77,OOO/kW (1995), the Casaccia plant was about $55,OOO/kW (1995). while that of the 80 kW plant was about $23,OOO/kW (1995). In 1991, KTI offered to build turnkey power plants at much lower Costs. For example, the fust demonstration 250 kW plant was expected to cost $15,5OO/kW (1995), the first series of five units $9,OOO/kW and the following series of twenty units $2,8OOfkW. After 50 units, costs were expected to be $1,7OOikW.12 The above costs have been converted from Netherlands guilders (NFl) to dollars at the commercial trading exchange rate after correction for inflation. The various European countries (and Japan) have costs for equipment, assembly labor, and services which differ widely from those in the United States when these are calculated at the usual commercial trading exchange rate. Raw materials costs are generally quoted in reserve currency (U.S. dollars). The basic materials costs of a given system will not generally vary greatly from country to country, unless they are significantly affected by import taxes. However, fabrication and assembly costs may differ greatly, since trading exchange rates are market-controlled, and bear little relationship to real costs (including, e.g., value-added taxes) and purchasing power. Equipment costs should therefore not be compared too closely in different countries without consideration of the fiscal and foreign exchange background. This will be discussed again throughout this review. To give an approximate comparison with KTI’s projections, the series of approximately 40 IFC 40 kW PC18 units cost on average $12,5OOikW (1985, i.e., $17,OOO/kW 1995), cf., Ref. 6, p. 117. The 200 kW PC25 had unit costs which were substantially less. In 1988, its price was expected to eventually fall from the introductory commercial level of $2,5OO/kW (1988, $3.2OO/kW 1995) to $1,3OO/kW (1995)‘s or less in mature production. The 1995-96 production run of 200 kW PC25C units will be sold by IFC at $3,OOO/kW. The present target is $1,5OO/kW by 1998-2000 for a commercial PC25 (see Section 25). KTI expected some economies of scale, with lower capital costs for larger units. The first demonstration 2 MW unit which was planned (but not executed) by KTI in 1991 was expected to cost $8,2OO/kW (1995), the next series of five units $4,05O/kW and the following series of twenty $1,65O/kW. For larger 5 MW units, the first five were expected to cost $2,85O/kW and the following series of twenty $l,425/kW. For 10 MW units, the corresponding figures were c$1,65O/kW for five units and c$l,lOO/kw for twenty units.12 KTI was therefore anticipating a similar learning curve to IFC, though the business perspective of each company was different. IFC approached the marketplace as a stack developer contracting out the chemical engineering system, whereas KTI was a chemical engineering company contracting out the stack work. KTI’s manufacturing plans were on hold during 1994-95. The economics of a given cogeneration system operating in a quasi-baseload mode depend on its capital cost, on the local fuel cost, and on the efficiency of fuel conversion. Fuel (NG and/or LNG) costs in Europe and Japan are higher than those in the United States, putting a higher premium on efficiency. For a given fuel cost, higher efficiency allows higher capital cost for the same cost of electricity. The PAFC has no efficiency advantages over competitive equipment. To tackle the advanced GTCC system he.ad-on, the PAFC must have a competitive capital cost. To succeed in niches in the marketplace at a premium cost, it must have other advantages over its competitors. It does have the advantage of a certain degree of flexibility. For example, if an early 10 MW unit has an LHV efficiency of 45% and the stack cost: is 50% of the total, the absolute cost of the stacks can be divided by a factor of two by operating them at double the current density, assuming that the cooling system in the stacks is adequate and that the IR drop in the stack can be improved to avoid efficiency degradation. With no performance improvement, the syst’em can be operated at 0.43 AJcm2 and 0.65 V, instead of 0.22 A/cm2 and 0.73 V. As a result, the LHV efficiency will be reduced to 40%. but the capital cost in $/kW will fall to 84% of the previous value. This may result in a lower cost of electricity with an early capital-intensive plant. In contrast, a GTCC will not allow such operating trade-offs.

10. MODULARITY OF FUEL CELL GENERATORS We have stated that the advanced GTCC can only achieve high efficiency in large units in the 100 MW class. A common perception of the generic fuel cell is that it is modular and can achieve the same efficiencies in very small units as those in very large units. This may be true for the electrochemical fuel cell (cell stack assembly, CSA, or dc Power Section) itself, operating independently on hydrogen fuel and using for example, simple air cooling. However, it is not true for large fuel cell units operating on fuels such as NG, which require fuel processing in a heat-integrated system. For example, it is unlikely that a 10 MW

534

A. J. Appleby

fuel cell plant can be economically made up of 50 independent atmospheric-pressure 200 kW units, even though this is possible in principle. The power unit consists of a chemical plant (the fuel processor), which resembles a small refinery, and certainly has economies of scale. Apart from the dc fuel cell generator or electrochemical cell stack, another important plant component is the dc-ac inverter. It is an essentially modular purpose-built unit for a given size of plant, which was expected to cost about $7OlkW in 1995, down by a factor of ten or so since the early 1980s. We should note that quotations differ on cost, depending on the developer and his perceptions of the risk involved. Because the inverter contains many solid-state parts, e.g., GTO thyristors, it has no particular economies of scale. However, in the future it can be made by printed circuit techniques if voltages and parallel currents are appropriately matched, so that thin, flat conductors can be used. This should result in substantial cost reduction. A mature 10 MW unit is likely to cost less, and will probably be somewhat more efficient, than ten mature 1 MW units. For example, it will be more efficient if it is pressurized, and like all rotating machinery. a turbocompressor to serve a 10 MW plant will certainly be cheaper and more efficient than one scaled for a 1 MW unit. Similar, a 10 MW reformer will show economies of scale in terms of cost compared with ten 1 MW units. This should be added to the effect of surface-to-volume ratio. Reformers are heat-transfer limited, so there is an upper limit to efficient reformer size. Multiple tubular reformers are favored by some developers of the chemical engineering system, e.g., Haldor Topsae (Copenhagen and Lyngby, Denmark, and Houston, TX).18 An alternative high-efficiency reformer design, which maximizes heat transfer and is available in modular elements, is the II-II flat plate system.19 Even if the reformer itself shows some leveling in optimum characteristics as size increases, those of the remaining chemical engineering system will certainly show economies of scale. Increasing size implies the handling of increasing gas volumes, with increasing surface area of piping and reactors, including the reformer, shift converters and heat exchangers. For containment which is optimized in respect to stress, the cost of material will be independent of pressure. However, low pressure equipment is never optimized, since wall thickness is always greater than that which is mechanically necessary. Hence, pressure operation in large plants decreases piping diameter, making it closer to the mechanical optimum, and hence, decreases cost in $/kW. Hence large pressurized systems show an economy of scale for passive components, which will more than compensate for the cost increase for compressors. Finally, the energy requirement of the compressors will be more than compensated by the increased efficiency of the fuel cell operating under pressurized conditions. Thus, an optimum design for an optimum mature 10 MW unit might include, e.g., two reformers and one large turbocompressor. Whether this is more cost-effective than, e.g., ten 1 MW units strung together will depend on the relative maturity of both, so the design choice is likely to be made on the basis of lowest cost at the given stage of development. The stack itself consists of a large number of identical cells, mounted in series in a bipolar array to give a high dc voltage suitable to couple to the inverter. Mass production of the largest possible number of small cells would be expected to result in the lowest cost per unit area. However, the cells in the stack must be manifolded for efficient gas supply, as well as for the cooling system. The more connections per unit area, the higher the cost. Hence, the latter increases as cell area decreases. To some extent, this is compensated by complications due to supply channel size and pressure drop when cells become very large. As result, the cell size will optimize with system size. For multi-megawatt systems, 1 m2 seems to have become the size of choice and for sub-megawatt systems, it is presently closer to 0.5 m2 (0.465 m2, 5 ft2, in the PC23). No generalized optimization model, which trades off the economies of mass production of small cell parts versus the increasing difficulty of tying them together, appears to exist at present. It suffices to state that different technologies will require different optimum sizes due to, for example, mechanical constraints. For example, ceramic parts have thermomechanical problems and special reliability aspects which influence rejection rate in manufacture. Hence, ceramic SOFC cells must be much smaller than PAFC or MCFC cells. A special case of scale-up optimization may be seen in internal reforming versus external reforming HTFC technologies as a function of system size. All things being equal, we have seen in Section 6 that an internal reforming system will be normally about 3-5s more efficient than a simple external reforming system without a bottoming cycle. The internal reforming system uses a simplified balance-of-plant (BOP), which should be economically favorable. If the system uses DIR, alone or in conjunction with IIR, the anode volume will be larger and more costly than a standard anode. As system size increases, the internal reforming cell will show only small economies of scale, if indeed there are any at all. Cell size may increase somewhat as the plant size increases, but the latter will still essentially be a series of interconnected batteries. An external reforming system may show a large economy of scale in the reformer. Thus, an external reforming system may become less expensive in $/kW as system size increases. In addition, as systems become larger and include mechanical components, such as turbocompressors, Heron-type turbine cycles and/or steam bottoming cycles, the efficiency, as well as the cost, of the external reforming system may be advantageous. Thus, all systems require a careful optimization in regard to the way in which fuel processing, cell components and associated equipment arc to be handled. There will be no simple rule-ofthumb which will suffice to give the minimum cost of power for all applications and sizes. Pressurization, if used, should of course be compatible with available materials. The fuel-cell generator has a much wider range of useful size than its competitors, such as the GTCC. It can scale up to the 10 MW class, but it is probable that this is close to the upper limit for many (if not all) component parts of a NG or clean hydrocarbon distillate unit of relatively conventional design. A 100 MW

Fuel cell technology

535

unit may simply be a combination of 10 MW components, although some parts (e.g., the turbocompressor) might still benefit from an increase in scale. The lower limit for a pressurized system may lie at around 1 MW. although this is not well defined at this time. Atmospheric pressure units operating at lower ‘efficiency today (to allow higher current density operation, hence, lower capital cost) can certainly scale tiwn to 200 kW and perhaps be economic in even smaller sizes, depending on the application. However, economies of scale do apply at least to certain parts of the system, so that the per kW cost in a 200 kW size may be 50% higher than that of multi-megawatt units at the same level of maturity. This may not always be so if a sufficiently large production volume of smaller units can be manufactuted. If the price can be brought down to sufficiently low levels, higher electrical efficiency (with less available cogeneration heat) may be made optional at a higher capital cost by operating units with mom cells at lower current density. The lower limit for commercial on-site units is debatable. Delivered electricity costs in Japan are more than twice those in the United States @25+27/kWh, i.e., 2527ekWh at the now-typical trading exchange rate of YlOOto the dollar). This is partly due to higher energy costs (NG from liquid, about $75O/GJ, see below) and to the higher costs of generating equipment occupying scarce land resources. We should note that these costs are closer to the U.S. norm if the OECD purchasing power parity (PPP) exchange rate is used, which is estimated by the World Bank at about Y150 to the dollar. Based on the ratio of average hourly assembly labor costs in Japan and in the United States (including fringe benefits and national taxes), the effective exchange rate was Y129 to the dollar, based on a trading rate of YlOOper dollar.* Thus, what appears to be a relatively expensive small fuel cell (calculated at the commercial exchange rate:1might be economical in Japan, but not in the United States. For example, the Fuji Electric Company -intends to commercialize a 50 kW on-site unit, but the UTC PC1 8 40 kW unit was not considered to be commercially viable, nor was the smaller PC1 1 12.5 kW system, the predecessor of the PC18 This was intended for the all-gas home, and was developed under the American Gas Association Target Program between 1967 and 1976 by the then Pratt & Whitney Division of United Aircraft Corporation. The PC18 had a very rapid transient response time, which required a complex and costly computerized feed-forward system between the cell stack and the reformer to supply waste anode gas for fuel processing. By comparison, the PC25 is simplified, has less rapid response characteristics and uses a feedback coupling mechanism to supply the necessary energy for fuel processing. Its intrinsic mature cost will therefore be lower than that of the proposed PC1 8. 11.

DISPERSIBILITY AND EMISSIONS

The major advantage of the fuel cell generator, exemplified by the PAFC, over the advanced GTCC is its dispersibility. It can be made in sub-megawatt sizes and therefore can be placed near the required loads. Whether this is desirable will depend on the philosophy of the utility. This goes against the tendency to centralize generating capacity into larger complexes of higher efficiency and easier maintainability, but perhaps higher vulnerability. Central complexes using fossil fuel also have higher local pollution effects. The advantages of dispersed power include a better utilization of the transmission grid and easier application of cogeneration. A disadvantage is the decreased availability of the plant for maintenance and the higher manning rate required if conventional oversight is used. To avoid this difficulty, dispersed power must be designed to be remote-dispatch, unmanned, computer-controlled and essentially maintenance--free, apart from periodic inspection. Economical dispersed power, or at least power which can be added in small increments with a short lead-time, will make better use of utility capital and lower investment and planning risk. They will trade capital cost for O&M cost. The lOO+MW combined cycle systems represent a reliable, low-maintenance technology which is to some extent dispersible. Their size and acoustic emissions do restrict their siting possibilities compared with a fuel cell power plant. However, for a utility planner, they have similar financial advantages to those of a fuel cell generator in being small enough to be a low investment risk compared with a large central station. Combined cycle plants available by 1990 had low chemical emissions, for example, about 20-25 ppmv NOx (as NO2). These emissions were low compared with the New Source Performance Specification (NSPS) requirements in the 1978 Fuel Use Act. The NSPS standards were 150 ppmv for utility machines rated at between 10 and 100 MMBTU/h, 75 ppmv for larger units, with no specification for smaller units, or (curiously) for non-utility units over 30 MW (conventionally, 400 MMBTU/h). The above ppmv figures are normalized to 15% oxygen in the exhaust (dry basis). For a steam-injected turbine, the exhaust might typically contain 12.7% oxygen and 13% of water vapor.” These NO2 figures compare with approximately 290 ppmv for a modern pulverized coal plant, which in addition will have SO2 emissions of about 570 ppmv.21 Sulfur emissions arc negligible for gas-fired combined cycle or fuel cell plants. NSPS Na standards for new utility coal plants were 0.6 lb./MMBTU (260 g/GJ, 2,450 g/MWh at 38% efficiency), 0.716 lb./MMBTU (310 g/GJ) for industrial coal boilers, and 0.3 and 0.2 lb/MMBTU (130 and 86 g/GJ) for oil- and gas-fired utility and industrial boilers, respectively. The General Electric Frame 6 PB6531B simple-cycle gas turbinese had NC&,CO, total hydrocarbons and particulate emissions of 43 g, 40 g, 4 g and 2.4 g per GJ (LHV), respectively (i.e., 0.1,0.094, 0.0094 and 0.0055 lb./MMBTU). A single-cycle machine with 1,104°C (2,020“F) turbine inlet temperature, it had * The New York Times,October 15,1995. The rates quoted (Deutsche mark, 1995, $1.425 DM = $1.00 = WOO)were United States, DM 27.97, Japan, DM 36.01 per hour. ESY211ll0-0

536

A. J. Appleby

a LHV efficiency of 32.3% at 21X ambient. Its Na emissions were 480 g/MWh, equivalent to 21 ppmv in the exhaust (15% oxygen, dry basis). More advanced machines with similar emissions specifications were available (e.g., the General Electric PGLM-2500, of 20.4 MW, with an LHV efficiency of 34.6% and a turbine inlet temperature of 1,260°C, 2,300’F). For a 52% LHV efficiency GTCC machine, the above emissions levels correspond to 300 g, 280 g, 28 g and 17 g per MWh, respectively for N@, CO, total hydrocarbons and particulates. A number of machines with improved low-NO2 burners were becoming available (e.g., the simple-cycle 38.3 MW General Electric Co. Frame 6 PG6541B, turbine inlet temperature 1,160°C, LHV efficiency 30%) which produces 8-9 ppmv of N@, i.e., the equivalent of 120 g per MWh in a 52% LHV efficiency combined-cycle plant. The average NQ emissions for all United States power generation was 2,200 g per MWh (as N02) in 1989. Since 33% of all electricity was provided by nuclear and hydroelectric plants with zero emissions, the average for all thermal plants was about 3,300 g of NO, per MWh. ‘Ihe average for coal plants (80% of thermal output) was 3,500 g per MWh (ca 0.8 lb./MhIBTU). Average oil plant emissions (6% of thermal output) were 2,000 g/MWh (0.46 lb./MMBTU), and average NG plant emissions (14% of thermal output) were 2,300 g/MWh (0.53 lb./MMBTU). The industry expected that the requirements of the 1990 Clean Air Act and other actions would reduce the emissions of all thermal plants to 1,000 g per MWh (about 0.23 lb./MMBTU) by 1995-6.z1 By December, 1992, the rules required the installation of low NO2 burners (0.45 lb.iMMBTU, about 2,000 g per MWh) on many coal-fixed boilers. Rules for other plants were being decided after discussion with industry. We should also note that the emissions produced on-site from the total power used in the Los Angeles Basin were 450 g per MWh in 1991. Since only 37% of the power used is generated locally, 36% in NG plants (mostly steam), and 1% in oil plants, the NO2 emissions for locally generated power were about 1,200 g per MWh, 52% of the national average. Texas utilities’ NG plant emissions were even lower at 1,ooO g per MWh. Southern California Edison had set a goal of achieving 40 g per MWh later in the decade, i.e., about 100 g per MWh or 0.023 lb.JMMBTU for the locally-generated power. The U.S. national average for SO2 emissions was about 1.2 lb./MMBTU, or 2,200 g per MWh. This was almost entirely &rived from coal plants (54% of electricity generated) since oil plants represented only 7% of generation. Emissions from coal plants averaged 2.1 lb./MMBTU (9,250 g per MWh), and those from oil plants operating on high-sulfur residual fuel oil averaged 1.2 lb./MMBTU (5,200 g per MWh). Emissions of SO2 from NG plants were negligible. EPRI expected that coal plants would be required to emit less than an average value of 0.45 lb./MMBTU (2,000 g per MWh) of SO;! after 1995 as the provisions of the 1990 Clean Air Act were phased in. The general requirements included a reduction of all SO2 emissions by 25% compared with the 1985 figure by 1995, and by 50% by 2000, after which emissions would be capped. Regulations were yet to be set, but older plants would be required to achieve the 1978 NSPS standard of 1.2 lb./MMBTU (5300 g per MWh), and new plants should not exceed 0.3 lb./MMBTU (1,330 g per MWh). As plants become more efficient, emissions in g per MWh will be correspondingly reduced. The significance of coal gasification plants incorporating fuel cell cycles is discussed in Section 17. The PAFC of the early 1980s was designed to be a great improvement on NSPS NO2 emissions levels. Unlike the turbine, which requires a large volume of compressed air for internal cooling, the air-flow to the pressurized fuel cell cathode is normally minimized to reduce parasitic losses to the minimum consistent with good electrochemical performance. This corresponds to an approximate maximum of about 70% oxygen utilization, with more typical values of 50%. As Section 5 indicates, the PAFC fuel gas stream initially contains excess water vapor left from fuel processing. The product water is formed on the cathode side, and equilibration takes place inside the cell. Because the molar flow at the cathode is high compared with that at the anode, about 90% of all water vapor is rejected in the cathode exit stream. In contrast, the HTFCs reject all excess reforming and product water in the anode exit stream. The PAFC anode exit stream is combusted in the steam reformer burner with little excess air. As a result, the reformer burner off-gas is much richer in Co, and Hz0 than gas turbine exhaust. The PAFC burner exhaust may only contain 7% oxygen (dry basis), compared with 15% oxygen (dry basis) in a gas turbine. At 80% anode utilization and 7% oxygen (dry basis), there is a total of only 4.0 moles of dry exhaust from the reformer burner per mole of methane used in the fuel cell (i.e., 1 mole CO2,0.28 moles 02, and 2.72 moles N2). At 85% utilization, there ate only 3.38 moles per mole of methane. In contrast, a gas turbine operating with 15 mole % 02 (dry basis) has an exhaust composition equal to 36 moles per mole of methane used (1 mole CO2,5.4 moles 02 and 29.6 moles N2). Thus the same concentration of NO2 in the PAFC (at 85% utilization) and turbine exhaust represents a greater production per MMBTU by a factor of 10.7 in the turbine, compared with that in the PAFC operating under the specified conditions. Typical requirements for the PAFC were originally given as N@ emissions below 20 ppmv in an exhaust stream containing 6.1% oxygen (about 7.8% dry basis, operating on methane). For simplicity, it is assumed that NG may be equated to pure methane to determine ppmv emissions in g/GJ or g/MWh. This a good assumption in regard to its heat content, but it is not necessarily so for the combustion volumes for typical NG containing higher hydrocarbons and inactive diluents. The only part of the system where NO2 could be produced was in the reformer burner, which operated on very lean gas at a relatively low fltme temperature. From the chemical viewpoint, obtaining this level of NO2 was therefore feasible. The specified exhaust concentration corresponded to 5.7 g/GJ (HHV), 6.2 g/GJ (LHV), or 0.013 and 0.0145 lb./MMBTU, respectively, expressed as N& Alternatively (and more logically) the figure was equal to 56

Fuel cell technology

537

g/MWh at a heat rate (i.e., HI-IV) of 9,300 BTU/kWh (40.4% LHV efficiency, 36.7% HHV). No CO emissions level was specified for early PAFCs. The requirements in the New York 4.5 MW demonstrator were given in terms of the fuel HHV as 8.6 g/GJ (0.02 lb./MMBTU) of NO2, 13 mg/GJ of SO2 and 1.3 mg/GJ of particulates. These corresponded to 84 g, 130 mg and 13 mg of these pollutants per MWh, respectively.22 The measured NO:! level in the TEPCO Goi plant, which had the same requirements, was less than 10 ppmv,zs and typically about 8 ppmv, i.e., about 24 g/MWh. This is less than 10% of that of a then state-of-the-art combined cycle in the 100 MW class and 0.7% of the allowed NSPS emissions of a simple utility combustion turbine with the same output, operating at 25% efficiency. Emissions of S@ and particulates at Goi were below the limits of detectability. Hydrocarbon and CG emissions were not determined. Since the mid-1980s, other PAFC plants have had their NO2 and other emissions characteristics determined under normal operating conditions. The prototype unpressurized IFC 200 kW units7 were also required to have NO2 emissions less than 8.6 g/GJ I-II-IV (0.02 Ib./MMBTU). The total hydrocarbon emissions requirement was to be the same, with a CO level less than ten times higher. The specified NO2 emissions level corresponded to 35 ppmv as NO;! in the raw exhaust gas, equal to approximately 48 ppmv (7% @, dry basis), or 19 ppmv (15% 02 equivalent, dry basis). The actual levels measured for NO2 and CO were about 5% of these requirements., i.e., 1.2 ppmv of NO2 and 20 ppmv of CO in the exhaust, corresponding to 3.5 g and 35 g per MWh, respectively. The level of total hydrocarbons detected was about 10% less than the specification value,’ i.e., 7.9 g/GJ or 80 g/MWh. The CO was entirely from the reformer burner, and the total hydrocarbons consisted largely of methane and were therefore innocuous in respect to tropospheric ozone formation. Determination of non-methane hydrocarbon (NMHC) or weighted reactive organic gas (RGG) levels required measurement under California air pollution specifications, but the figures were limitingly low. As would be generally expected, all other things being equal, a pressurized system should have a somewhat higher N& emissions level, since the flame is hotter and the equilibrium towards NO2 will be more favorable. This is shown by a comparison of the 200 kW results with those obtained at Goi, even though the latter are still very lo\ anil certainly meet all required standards. All Japanese specifications for gaseous fuel ce. i e; missions have been standardized to 7% oxygen content of the exhaust gas. In the 200 kW air-cooled Sanyo PAFC prototype at TEPCO (35% HI-IV), also operating at atmospheric pressure, a value of 2.4 ppmv NO2 was measured,24 corresponding to 4.1 g/MWh. In the prototype Japanese 1 MW systems, NO2 levels less than 20 ppmv were specified. The measured level in the pressurized Kansai Electric Power Company unit (40% HHV) operating at 4 atm using Fuji Electric Company stacks and a Mitsubishi Electric Company (Tiyoda-ku, Tokyo) chemical engineering system was 18 ppmvzs reduced to 7% exhaust oxygen content, i.e., 31 g/MWh. However, for the 11 MW TEPCO 8.2 atm demonstrator at Goi, 10 ppmv NO;! was specified,z6 and the measured reading was only 1 ppmv.” This result is equal to 1.6 g/MWh, stressing the good neighborliness of the future PAFC power plant. The original NO2 specification of the IFC PC23 unit was 1.3 g/GJ (HHV) or 0.003 lb./MMBTU, i.e., 11 g/MWh at 41.1% HI-IV efficiency, or more than six times higher than the value measured at Goi. A recent reading for the IFC PC25A is 0.45 ppmv (at 15% 02, dry basis, see Section 25). This corresponds to 2.0 g/MWh. Other PAFC emissions (Se, particulates) have been undetectable, and the plant noise level of only 55 dBA at the perimeter fence (60 dBA at 10 meters for 200 kW units) was considered to be inaudible. The above PAFC units operate in a water-conserving mode and are, therefore, only dependent on fuel supply from the outside. In general, NO;! emission levels for the latest generation of the PAFC (e.g., the PC25A, 0.5 ppmv) are 40-50 times lower than those for state-of-technology GTCC machines (9 ppmv) in g/MWh (electric) or g/GJ terms. Even so, the large combustion turbine operating in an efficient combined cycle will continue to be a moving target from the both the emissions and efficiency viewpoint. The fuel cell will, however, remain the fossil technology with the highest combined emissions/efficiency figure-o;Smerit in small sizes. It may be added that combinations of fuel cells with the Heron cycle turbine,12 which will allow unprecedented efficiencies, look equally attractil from the emissions viewpoint. Exhaust emissions of the Heron combustor operating at atmospheric pt ure have been determined to be only 1 ppmv of NOz. Under its normal lean low pressure operating cc Itions, its turbine emissions values are expected to be only 2-3 ppmv, equivalent to 20-30 g per MWh w combined with a PAFC as a bottoming $cycle in a 55% efficient system.13 :rgy use technologies, Table 1 compares the N&, To attempt to put the PAFC in the context of othe , on-site unit with the values for future passenger CO and volatile organic emissions of the 200 kW PC cars built to California emissions standards. Thesr it3 lude “conventional” vehicles (1995 model year standard), low-emission vehicles (LEVs) and ultt k-l< w-emission-vehicles (ULEVs). The emissions standards per mile are included in the table in each category, and the assumption is made that the vehicles operate at 30 mpg of gasoline to allow all emissions to be quoted in g/GJ. For the 200 kW PC25, total hydrocarbons are not distinguished from weighted values for reactive non-methane organic gases, RGGs or NMHCs. However, the value is so low as to be negligible. In the final column, the passenger cars are assumed to be electric zero emission vehicles (ZEVs) operating at 0.3 kWh (line power to battery) per mile, assuming that the electric power is provided by the 200 kW PC25A PAFC. The equivalent emissions from the power required by the electric vehicles ate then seen to be exceptionally low. Table 2 summarizes some rounded values for available emissions data and illustrates the very low values for the PAFC, except perhaps for VGCs. However, these require further evaluation for nor -methane

A. J. Appleby

538

reactive hydrocarbons. be dispersed.

Uniquely, the fuel cell generator will combine dispersibility

with the real ability to

Table 1. Comparison of California passenger vehicle emissions for gasoline vehicles and for electric vehicles charged by 208 kW ONSI PC25s. The numbers are g/mile, with g/GJ at 30 mpg given in parentheses in the fiit three columns for IC-engined vehicles. For electric vehicles consuming 0.3 kWh/mile, pollutants are given in g/mile in the final column. The fit number corresponds to the specified design maximum values for the PAFC, and the second is the actual measured value.

Emission

California Conventional (1995)

Low-Emissions Vehicles

EV (0.3 kWh/mile) Supplied By PC23

Ultra-Low Emissions Vehicles

No;!

0.4

(91)

0.2

(46)

0.2

(46)

0.026

0.0007

0

3.4

(770)

3.4

(770)

1.7

(390)

0.300

0.0014

(9)

0.026

0.00006

0.25

ROG

(57)

0.075

(17)

0.040

-

Table 2. Relative utility emissions (g/MWh, rounded out). NO, data (as NOi, for PAFCs reflect the technology from different developers. The Clean Air Reauthorization Act of 1990 requires low-NO, burners on coal stations (0.45 lb./MMBTU, 1875 g/MWh). with new standards to be set for other sources.

State-of Technology Performance

New Source Performance Standards (1978 Fuel Use Act)

coal (38% Eff.)

Boiler Gas, Oil (38% Eff.)

NGx

1220 oil 820 NG

5 MWClass Gas Turbine (25% Eff.)

Large Turbine (33% Eff.)

(15zmv)

(75liKv)

Gas Turbine Combined Cycle (55% Eff.)

pressurized PAFC (44% LHV)

Atmospheric PAFC (40% LHV)

120 (9 ppmv)

2-20

2-5

90 (?)

(0.6 lb=&T’U) co Its

na

na

na

280

na

820 (floor value)

(low)

(low)

(low)

0.013

120

40

30

15

0.0013

SGX (1.2 lb5&TU) Particulates (PMIO) 120 VGCS (state-of-the-art)

30

80 (?)

Fuel cell technology

539

12. POTENTIAL PAFC MARKETS AND CAPITAL COSTS - ESTIMATES TO 199:! There have been many projections for the potential electric utility PAFC market for the United States. In general, the more recent the estimate, the lower it is. The 1987 estimates given in Ref. 15a, which took into account the high efficiency gas turbine combined cycle (GTCC) as the most effective competition for the fuel cell generator, estimated a market between 7 and 22 GW in 2010, provided that a machine at a competitive price would be available with a LHV efficiency of 48.5%. This could rise by a factcr of five if the LHV efficiency was 52.6%. The PAFC is a long way from these efficiency values, so it is possible that later technology, in the form of the HTFCs, will step into the gap. In contrast, the on-site cogeneration market could be as high as 18 GW (Ref. 6, p. 117). The U.S. Department of Energy Fuel Cell Systems Program Plan for Fiscal Year 199028 gave ultimate capital cost goals of $95O/kW (1995) for NG electric utility PAFCs and $1,55O/kW for on-site units to allow head-on competition with alternative technologies. They gave ambitious efficiency values in the range 45-555 for NG electric utility systems and 40-508 for those operating on coal gas, for which no capital cost was specified. Whether the efficiencies are LHV or HHV, and whether those for coal gas systems were based on coal gas or coal feedstock was also not specified. Slightly different parameters were given in the program summary prepared by all of the U.S. sponsors, the Department of Energy, the Gas Research Institute and the Electric Power Research Institute .29 They were again $95O/kW (1995) for electric utility NG systems (45% HI-IV), ca. $1,2OO/kW for on-site systems (40% HHV), and $1,8OO/kW for coal systems (45% HHV). These efficiency values seem reasonably realistic in the medium term. This document also reviewed the potential commercial market up to 2000 as only 260 MW for the PAFC, of which 100 MW might be for commercial cogeneration, with 60 MW for industrial cogeneration and 100 MW for electric utility use. In addition, demonstration units might respectively total 10, 30 and 60 MW. These were considerably scaled back from previous estimates. If its economic and capital cost goals were achieved, the PAFC market might be 40% of the projected total or 4 GW.29 An interesting opportunity for the PAFC in the United States (and perhaps for other fuel cell systems in the future) may be its use in removing the nuisance of landfill gas, which must be flared or otherwise used for safety reasons. The gas is typically 50% methane and 45% CGz with l-700 ppmv of S (as 1~2s). The presence of CO;! in the gas aids the steam-reforming operation by acting as a supplementary :reactant at 8OO”C.ss The loss in fuel cell performance which results from a decrease in hydrogen content from about 62-73% (wet basis, depending on steam-to-carbon ratio in the range 3.5 to 2.5) in pure NG reformate to about 53-62% for landfill gas, is negligible. In the future, the Environmental Protection Agency may prohibit flaring and the use of thermal engines, such as diesel generators. Here, the fuel cell will essentially perform a community service, producing electricity together with cogenerated heat as an economic bonus. In the 200 kW range, 7,475 landfill sites had been identified, representing a total of 4.4 GW. In addition, there were 1,700 larger sites in the 400 kW to 1 MW range, representing 1 GW total. This is a large potential niche market, to which the on-site PC25 system seems perfectly fitted.30 In Europe, potential PAFC applications received little emphasis during the late 198Os, beyond the requirement for demonstration plants as a means of learning how to use fuel cell technology 1.0the best advantage. However, a market of about 2 GW, probably an upper limit, was predicted for the year 2005 in Italy.31 One may assume that if an improved HTFC technology became available at that time, it would replace some of the PAFC potential. A list of European fuel cell projects to 1991, including the SOFC, is given in Ref. 32, which includes a discussion of potential markets, especially in the aftermath of Chernobyl and of the Swedish and Italian referendums to abandon nuclear power.* In the United Kingd.om alone, combined heat and power installations could total as much as 320 MW at 4,000 sites, up from only 7 MW at 170 sites identified in 1987.32 Much of this market may be taken by the PAFC. For Europe as a whole, the on-site fuel cell market was estimated to possibly equal 100 MW per year by the end of the decade. It was then not unreasonable to suppose that 5% of the new and replacement electric utility market might be taken by fuel cells, representing 0.4-0.8 GW per year by the year 2000. Some of this market may be shared by the PAFC. However, MCFCs, and to a less extent SOFCs, were expected to be dominant technologies in Europe. Extensive development programs either existed or were planned in 1990.33 Spending was then about $50 million per year, mostly on the HTFCs. This total was not very different from the sum then being spent in the United States. The future of the HTFCs is discussed in following sections. In 1990, Abe et al34 estimated that the Japanese market for the PAFC would be 10 to 100 MW before the year 2000. Within the same time-frame, he suggested that the MCFC might have a deployment up to 10 MW. In the subsequent decade, a capacity of about l-2 GW was predicted in Japan for the PAFC. Later, more market segments were identified in Japan, and the total was revised upward. In 1991, Fukutome35 quoted a study conducted by Japanese government agencies (the Agency of Industrial Science and Technology, AIST, and the New Energy and Industrial Technology Development Association, NEDO). They were based on an imported LNG cost of 4 Y/Meal (then about $7.47/GJ, $7.90/106 BTU; about $9.50/106 BTU at the trading exchange rate in September 1995, $6.40/l@ BTU at the PPP rate). This is 35 times higher than U.S. assumptions, &pending on the exchange rate used. As a result, the break-even cost of Japanese plants is considerably higher than in the United States, since a higher efficiency for * These may (or may not) be reconsidered in the future in view of the requirement to reduce global climate change emissions.

540

A. J. Appleby

expensive fuel compensates for increased capital cost. The economic comparison for an electric utility fuel cell was a LNG steam boiler plant with 37% efficiency, costing Y210,000/kW.35 In 1991, this corresponded to $l,555/kW (1991$) at the trading exchange rate, about twice the U.S. cost. In September 1995, it corresponded to $2,3OO/kW (1995) at the trading exchange rate after allowing for Japanese inflation, or about $1,55O/kW at the PPP rate. The benchmark for a cogeneration plant was an industrial diesel unit (30 year life) operating at 30% efficiency, costing Y22O,OOO/kW. For a 2-year stack life, breakeven costs for both cogeneration and electric utility dispersed fuel cell plants operating at 43% electrical efficiency were estimated to be Y19O,OOO/kW($2,08O/kW, trade exchange rate, September 1995), whereas for a 5-year stack life, they were Y260,OOOfkW and Y28O,OOOlkW, respectively ($2,85O/kW and $3,07O/kW, same basis). Transmission and distribution credits of UlS,OOO/kW ($165/kW, same basis) were assumed. Thus, allowable costs calculated at the trading exchange rate were about twice those assumed in the United States. The economic cost of a central station fuel cell plant with 5-year stacks operating at 43% efficiency would be a lower value, about Y18O,OOO/kW ($1,97O/kW, same basis). Fukutome concluded that the PAFC was likely to succeed as a dispersed technology, whereas the MCFC will become a central station technology, trading off increased capital cost for higher efficiency. For use as a detached generator on remote islands, break-even might occur at Y220,000-26O,OOO/kW ($2,400$2,85O/kW, same basis). The PAFC would be ideal for this application. District heating systems in Japan were only about 0.5% of total heat demand in 1991. Assuming cogeneration PAFCs were available, it was estimated that 1,040 MW per year could be installed in urban redevelopment areas by the year 2000, with 840 MW per year in new town areas. Customer-owned units supplying combined heat and power to individual new buildings were projected for units in the 1 MW, 3 MW and 5 MW sizes. No units in the sub-MW range , e.g., Fuji Electric 50 kW or IFC PC25 200 kW systems, were considered. The markets for these PAFC units were evaluated at 510,220 and 160 MW per year by the year 2000. Thus, this reports identified total potential Japanese markets of 2,400 MW per year for commercial cogeneration by the year 2000. In June 1990, the Ministry for International Trade and Industry (MITI) published a report taking a long-range view of Japan’s future energy supply and demand. It concluded that GNP and energy demand should be decoupled by enforcement of a conservation policy, which would change the elasticity factor for these variables from the 1990 value of 0.98 to 0.42, so that a doubling of GNP should result in an increase in energy demand by only 33%, down from the recent value of 96%. To achieve this, cogeneration systems mainly supplied by fuel cells should be increased from a proposed capacity of 150 MW (electric) by the year 2000 to 10.5 GW. The Supply and Demand Committee of the Electric Power Industry published a report at the same time which proposed an acceleration of nuclear capacity and the introduction of an optimized mix of power plants. This would include dispersed power generation using renewable energy sources, but including a large fuel cell generating capacity. In consequence, the aim should be for a total installed fuel cell (presumably PAFC) capacity of 2,250 MW in 2000, which would include 900 MW in commercial use and 300 MW in industrial use, with 1,050 MW of dispersed electric utility units. By the year 2010,2,800 MW should be in commercial use or only about 10% of the potential market identified in the AIST-NEDG report.j5 Industrial use should include 2,400 MW and utility use 5,000 MW. Of the latter, the PAFC should be 3,100 MW, newer HCFC technologies providing the remainder, giving the proposed total of 10.5 GW of installed fuel cell capacity. In 1991, unpressurized 200 kW PAFC systems were being developed by the Fuji Electric Company36 under NED0 funding for remote island and cogeneration use. The former were designed to use methanol fuel for simplicity, since its reforming temperature is only 300°C, which results in a simple, efficient system with easy start-up. The efficiency of the methanol unit was 39.7% (HI-IV), 45.2% (LHV), whereas that for the NG cogeneration unit was 40% (LHV), identical with that of the IFC PC25. Expected emissions of Fuji Electric and PC25 units were comparable, with NO2 at less than 2 and 4 ppmv, i.e., less than 3.7 g and 7.5 g/MWh, respectively.36 Fuji Electric emerged as the leading Japanese company for PAFC development. By mid-1991, it had supplied either the stacks or complete packages for 27 PAFC units totaling 2.1 MW, including the 1 MW Kansai Power demonstrator, a 200 kW methanol remote-island plant for Okinawa Electric Company and fifteen 50 kW plants operating on NG or LPG. Four of the latter were in Europe. Stacks were also delivered to KTI for the experimental European demonstrators of up to 80 kW described earlier. A further 63 plants, totaling 9.7 MW, were then on order. These included a 5 MW unit with similar operational specifications to the PC23 for delivery in 1995 to Kansai Electric Power Company. This is to be largely inside a three-story building to reduce its footprint, rather than laid out on a flat field. One innovation in the system is a motor-driven compressor supplying a power turbine operating on reformer offgas. The turbine powered a generator to improve controllability and load response. The cell stacks for the pressurized 5 MW Fuji Electric demonstrator were to operate at a slightly lower pressure (7.2 atma, 106 psia) than that proposed for the PC23 and would use a 0.8 m2 cell area, instead of 0.93 m2. The stack’s design power density was 1.6 times higher than that of the 1 MW unit of 1986 and it was expected to operate at 0.746 V and 0.30 A/cm 2. This is impressive, considering that the originally specified performance of the PC23 was 0.73 V at 0.22 A/cm 2, although an improved short stack demonstrated 0.74 V at 0.43 A/cm2 at 1,000 h in 1985.8 Because of the usual slow performance decay, both the decay rate and the specified time of operation for a given performance should be indicated by developers to allow more effective comparisons of technology. A 15-cell short stack of reduced size (0.36 m2) had operated for 12,600 h by March 1991, with an addition of electrolyte at 10,000 h. Unlike the

Fuel cell technology

541

PC23 stack, it was not designed with an acid reservoir to store sufficient electrolyte for 40,000 hot hours. The degradation rate over 5,000 h was 33% of the expected amount, and was 20% of the expected amount over the next 5,000 h. Testing was continued to 20,000 h to allow a total life prediction. The 50 kW cogeneration unit was designed to be a compact box delivering 4.9 kW/m3, with a specific power of 100 kg&W. Its LHV efficiency was the same as that of the IFC PC25 200 kW unit, and it gave 0.66 V (time of operation unspecified) at 0.24 A/cm 2. However, it was hoped that this current density could be increased by 50% at the same cell voltage by further improvements in electrodes and cell structures, particularly by lower internal resistance. PAFC development at Fuji Electric to 1991 has been summarized by Anahara.J6 The large Japanese market of about 8.3 GW of PAFC units by 2010 was then expected to be shared by Fuji Electric, IFC (Toshiba-UTC) and other Japanese developers. IFC! fuel cell stacks of improved PC23 type using the Configuration B low-resistance bipolar plate and improved electrode structures were proposed for use in certain large pressurized electric utility plants in Japan. The unpressurized 200 kW PC25A and its successors would be used for cogeneration applications. By 1991, several PC25 units were on order in Japan. These followed Japanese testing of four preprototype units, designated PCX, which made the developmeni of the PC25 possible. An update on this series of g,enerators is given in Section 25. 13. THE MCFC GENERATOR The development of HTFCs is less advanced than that of the PAFC. The MCFC has been in various stages of stack development since 1980, with emphasis on reproducibility, materials and component lifetimes, and scale-up. The tests of the Energy Research Corporation 20 kW stack at the small San Ramon plant have been mentioned above. In Japan, preliminary 10 kW stacks from various developers were tested in 1987, and scale-up to a breadboard 1 m2 cell at II-II first took place in 1988. A lo-cell 1 m2 stack (10 kW) was in operation there in 1991, along with other 50-cell smaller stacks. Developments at IHI and elsewhere up to that point are given in Ref. 9. As may be expected, emphasis was on component lifetime. There has been continuous improvement in MCFC cell pcrfonnance since 1980 among the major U.S. developers. In the mid-1980s, the MCFC was usually shown operating at a cell potential of 0.73 V at about 0.16 A/cm2 on reformed NG or on a NG steam mixture. The IIR and/or DIR internal-reforming section or sections (if incorporated) contained a suitable catalyst (generally nickel, either on high-surface area alumina in separate reformer plates or a carbonate-resistant support such as lithium aluminate in the direct-lzforming fuel cell anode chamber). This performance could be obtained at a fuel utilization of 85% with the “rich” oxidant commonly used for testing, i.e., 30% m, 70% air (30% CO2, 14% 02) at about 30% oxygen and CO2 utilization. The potential of a hydrogen/oxygen fuel cell operating at 923 K is 1.014 V with the reactants and gaseous product water in their standard states. This is also the open-circuit potential of an MCFC with 1 atm of CO2 at both the anode and the cathode. The Nemst potential of the exiting anode gas under the temperature and utilization conditions is +0.046 V compared with the standard state value. The corresponding value for the cathode exit gas is -0.107 V. Hence, the exit Nernst potential to which the constant utilization current density-voltage curve will extrapolate at zero current density in a co-flow cell is 0.861 V. Developers who were comparative late-comers to the technology (e.g., in Japan since 1980 and in the Netherlands since 1986) had demonstrated this performance by 1990. During 1987-92, developers realized that this “rich” cathode mixture would be scarcely practical in a fully integrated power plant. The exiting anode gas stream must supply the CO2 for the cathode stream. The only devices to separate hydrogen and CO2 in the anode exit stream operate close to room temperature (see Section 14). It is generally not cost-effective to cool the anode exit stream, and reheat the various gases, because of the high cost of heat-exchangers. Thus, the most effective way of adding CO;! to the cathode reactant was to burn the anode exit stream and directly add the entire product to the required amount of air. If in-stack reforming plates are used, as in ERCs San Ramon and Santa Clara plants, a steam-tocarbon ratio of 2.5 : 1 is required. The indirect internal reforming (IIR) plates contain distributed steamreforming catalyst. They resemble the cooling plates in the water-cooled PAFC, and are placed one for every six cells. The cell anodes also contain direct internal reforming (DIR) catalyst, which eliminates the need for an anode recycle loop. About 80% of steam reforming takes place within the indirec:t internal reforming plates, the remainder being in the anode chambers. Cooling is via internal reforming, combined with sensible heat removal via the process gases (Section 6). For simplicity, ERC’s stacks operate without a cathode recycle loop, since this is not necessary for cooling an IIR-DIR system. The fuel utilization cannot exceed 75% in this simple system, otherwise there is not enough heat

available in the combusted anode exit stream to heat the incoming air. This would require the use of an additional heat-exchanger. At 75% utilization, the anode exit stream becomes 4 moles of CO2, 1 mole Hz, and 3.5 moles H20. This is combusted with 3.5 moles of oxygen in air, to give a cathode inlet gas composition of 4 moles of COz, 3 moles of 02, 14 of N2 and 4.5 of H20. Thus, the cathode feedstock consists of 15.7% COZ, 11.8% 02, which is directly used in a single pass through the cell at utilizations of 75% for Co2 and 50% for Oz. For each mole of methane oxidized at the anode, 3 moles of hydrogen are oxidized at 75% fuel utilization, therefore 3 moles of co;? and 1.5 moles of @ are combined at the cathode t0 produce C03= ion, which migrates to the anode. The overall oxygen utilization is 50%. Thus, the

542

A. J. Appleby

cathode gas mean composition corresponds to 10.8% Ca, 9.7% 02, and the exit gas composition is 4.8% C@, 7.1% 02 (1 mole C@, 1.5 moles 02, 14 moles NZ and 4.5 moles Hfl). This total flow of 14 moles of cathode exit gas per mole of oxygen consumed at 50% utilization is sufficient to remove the heat generated at 0.76 V and 75% fuel utilization in the internal-reforming cell. As Section 6 indicates, the flow requirement for an external reforming stack operating under the same cell voltage and utilization conditions would be 2.6 times greater, which would require a feedback loop and heat-exchanger, or a total volume throughput 2.7 times greater, with an air flow corresponding to 6.8 times stoichiometric (15% oxygen utilization). In a co-flow cell, the above exit gas composition would reduce the exit Nemst potential by a further 0.067 V at 65O’C compared with the “rich” cathode composition above. However, reduction of the anode utilization from 85% to 75% increases the exit Nemst potential by 0.026 V, so that the effective open circuit potential corresponding to 75% anode utilization and to the above cathode exit composition is 0.822 V. This would be the highest achievable voltage in a co-flow cell. In cells with cross-flow or counter-flow geometry, the effective constant-utilization open-circuit voltage is somewhat higher. In the first case, the anode exit “sees” a cathode gas composition which is closer to the mean value, and in the second, the anode exit “sees” the cathode entry composition. The performance curve at constant 65% fuel utilization in ERC cross-flow cells extrapolates to a zero-current figure of about 0.86 V, for which the co-flow figure would be 0.842 V. The corresponding figures at 75% fuel utilization are about 20 mV lower. Improvements in the electrodes and in the cell have now reduced the polarization slope in the operating current density range, so that ERC could obtain 0.83 V at 0.05 Alcm2,0.76 V at 0.16 Aicm2, and 0.715 V at 0.20 A/cm2 at 65% fuel utilization in a short stack with 0.325 m2 active area cells in 1992. In a large 1994 stack, 0.764 V as obtained at about 0.14 A/cm2 (see Section 26). Performance with practical lean gas mixtures is shown by the MCFC polarization data in Fi:,ures 3 and 5. While today curvature occurs at current densities greater than 0.14 A/cm2, it is expected that the straight line can be extrapolated to higher current densities as more experience in controlling IR drop and present polarization losses is acquired. The ERC goal is 0.76 V at 0.21 A/cm2 by 1998 with the above gas compositions and utilizations. Under real system conditions, increasing cooling requirements as voltage falls means that additional air must be added to the burned anode exit stream, so that in practice, the current density cannot be raised above a given design point without system changes. The design points today are set by effciency specifications, i.e., cell voltage at a required fuel utilization. MCFC performance is characterized by a relatively linear cell voltage-current density relationship in the working current density range, as Figures 3 and 5 show. This is partly a result of relatively high internal resistance compared with the PAFC, notably in the electrolyte layer and in the cathode components, including their contact resistances. The cathode itself is lithium-doped nickel oxide and the current collector or collector layers carry oxide films. In the PAFC, the overall internal resistance is about 0.1 Q-cm-z. Thus, at 0.30 A/cm2, a loss of only 30 mV is seen. This small value results from the use of a thin (0.1-0.2 mm) silicon carbide matrix holding the electrolyte. In the MCFC, a much thicker (typically about 1 mm) lithium aluminate matrix is required to prevent gas crossover and to provide a diffusion barrier to prevent the slow deposition of nickel nodules which result from corrosion of the cathode. This phenomenon can be life-limiting (see Section 15). As a result of the matrix thickness and the oxidized cathode components, the resistance losses in the MCFC are several times higher than in the PAFC. However, the majority of the overall linear loss is not simple internal ohmic resistance. It is a combination of linearized kinetic and diffusion losses, which are still not completely elucidated or described by a mathematical model. What was considered to be a state-ofthe-art cell in 1990 had a true ohmic resistance component of about 0.4 Q-cm-z. At 7 atm pressure, the “pseudo-resistance” of the anode and cathode reactions was about 0.06 and 0.5 R-cm-z, respectively on standard gases. The total pseudo-resistance increased by a factor of about two at 1 atm. The latest results (Section 26) show that the total of true resistance and polarization pseudo-resistances have fallen by about a factor of two, even in large stacks. It is evident from Figure 3 that a reduction of both these and the ohmic resistance, to give a lower overall slope of the quasi-linear voltage current, would yield better performance. However, Figure 5 shows that a considerable improvement has taken place, in spite of the demands of scaling up of the technology to large cells and the negative effect of the necessity of using more dilute gas mixtures. The linear part of the state-of-the-art MCFC polarization slope in Figure 5 has a value of less than 0.5 Q-cm-2 in an ERC stack operating on process cathode gas mixture (15.7% CO2 input, 4.8% exit) at 75% CO2 and 50% 02 utilizations, and at 75% fuel utilization. The polarization slope for commercial 1998 stacks (the thin line in Figure 5) is projected to be 0.4 Q-crns2 to 0.21 A/cmm2 (Section 26). These values are about one-third of those which were considered “normal” in the mid-1980s for cells operating on rich cathode reference gas mixture (30% CR, 70% air). Since 1985, the power density at 0.76 V has increased by about 15%. in spite of the practical necessity of operating with dilute reactant gas mixtures in simple atmospheric pressure systems. These dilute gas mixtures have the further advantage of slowing down cell degradation due to nickel oxide cathode dissolution, which is approximately proportional to CO, partial pressure in the cathode gas stream (see Section 15). Some diagnostic parameters for this process have been obtained.37

543

Fuel cell technology

Fuel Utilizatii 0.9

85x - soK:

-

75X, with lean cathode gas - MCFC State-of-Technology

MCFC

Westinghoum SOFC

C

0.5

-

0.4

911991

0.3

’ 0

I

I

1

I

200

400

600

600

Current

Density.

mA/cm2

Figure 5. Westinghouse SOFC performance (hydrogen at atmospheric pressure, 85% utilization) as a function of development schedule,s6 compared with ERC MCFC performance from Figure 3. September 1991 performance used the low-resistance air-electrode-support (AES) tube., which would all equip future units. SOFC results on NG reformate at 85% utilization are 30 mV lower than those shown (c.f., Figure 3). The State-of-Technology MCFC represents 1994 atmospheric pressure ERC data with in-stack reformer plates at 75% fuel utilization and practical cathode gas in the simplified integrated atmospheric pressure power plant (mean cathode composition 10.8% CO,, 9.7% 09. The thin line is projected 1998 performance for early commercial stacks operating under the same system conditions (0.76 V at 0.21 A/cm*, Section 26).

14. MCFC NG SYSTEMS OPTIONS

As has been discussed earlier, a natural-gas fueled MCFC can use either external or internal reforming. Whether reforming takes place in the anode compartment or elsewhere in the stack, internal reforming will have a higher efficiency, which was evaluated as about 4-5% in the illustrative analysis given earlier. This has been examined in detail by several authors. Kishida 3s has shown that a pressurized system design which included a bottoming cycle, would indeed show a 4.3-4.6% increase in efficiency for a.n internal reforming plant over one using external reforming. The design of an MCFC system includes a inumber of options to increase the cell potential in a particular reforming approach. To understand this, we should be reminded of the chemistry of the MCFC. To function, it must recycle Co2 from the anode exit stream to the cathode inlet. This is normally carried out in a real system by combusting the remaining anode gas stream. If the proposed system uses external reforming, the heat from this stream must be suppl.ied to the reformer to give optimal system efficiency. If reforming uses stack waste heat, the exit stream itself is essentially “waste” heat, which can be used for a bottoming cycle or in cogeneration after combustion. Whichever is the case, an anode gas (NG reformate, steam-to-carbon ratio 2.5 : 1) stream starting out as a mixture of C@, HZ, and Hz0 in the ratio 1 : 4 : 0.5 (ignoring shift) after anode reaction at 85% Hz utilization. combustion and mixing with sufficient air to sustain the cathode process at an oxygen utilization of 50% will typically consist of a mixture of CO2, H20, @ and N2 in the ratio 4.4 : 5.0 : 3.4 : 14.8, i.e., 16% C@, 12.3% 02. This relatively dilute mixture can be upgraded by water removal (steam separation) provided that the necessary heat exchangers and condensers can be economically included in the system. The resulting richer mixture increases the reversible potential sufficiently to give an increase :in cathode potential, and the steam can be recycled for reforming. KishidaB showed that an internal reforming system with steam separation would operate at 2.2% higher efficiency than a unit not using steam separation. The corresponding value for an external reforming system would be 1.9%. His assumed steam-to-carbon ratio was 3.5 : 1. In all cases, the option will be to accept an increase in system complexity and capital cost reflected in the requirement for two more heat exchangers, in return a less than 2% increase in system efficiency. Alternatively, as Figure 4 shows, the system could be operated at the same overall efficiency

544

A. J. Appleby

and at a higher power density, which will reduce the capital cost of the stack. An increase in current density from 0.16 to 0.18 A/cm2 will approximately correspond to this increase at constant system efficiency, reflecting a change of stack capital cost of only about 12%. Many developers feel that the cost of the stacks in an introductory unit might be 33% of the total cost. Hence, this proposed change would make an overall reduction in the total cost of 4%. in return for some increase in system capital cost and complexity. This tradeoff may (or may not) be acceptable. Another option may be pressurized operation, in which the turbocompressor is essentially a bottoming cycle which uses some or all of the waste heat from the stack, with or without available shaft work to produce more electricity. The tradeoff will again be increased capital cost versus increased efficiency. Kishidas* has also examined the effect of pressure on performance in a typical system and the effect of turbocompressor efficiency. A system operating unpressurized at an HHV efficiency of 49% would operate at the same current density and about 51% at 3 atm, 53.5% at 5 atm and slightly over 54% at 7 atm, if the turbocompressor efficiency was 67%. The corresponding values for a 72% efficient turbocompressor would be close to 1% higher. The overall system efficiency includes 97.5% for the inverter. The state-of-technology turbocompressor considered by Kishidas* in 1985 was 71.5% efficient. A 5 MW class turbocompressor has been recently developed in Japan with an efficiency of 74.2%, which is obtained by using air-bearings and three-dimensional impellers operating a very high shaft speeds.35 Airbearings were used as an experimental technology in the New York and Goi 4.5 MW designs, but they were considered to be unreliable in the early 1980s. This new development could promise a further 0.5 % in system performance, if this is desired. Kishida38 showed that most of the improvement in efficiency occurs by increasing the operating pressure from 1 to 3 atma. After that, the improvement is rather small, roughly corresponding to the expected reversible thermodynamic effect. Finally, higher than 8 atma, efficiency starts to fall as gas compression work becomes more important than electrochemical gains. The reversible potential change corresponding to increasing the pressure from 1 to 3 atma is a little more than 20 mV, about 30% of the increase actually seen. This is because the cell potential-current density slope in Figure 3, which partly depends on kinetics, decreases initially as pressure increases, then tends to level off. A system operating at 5 atma might operate at 100 mV higher than an unpressurized one under comparable conditions. The energy requirement for pressurization is not “free” in a system with a bottoming cycle. In this example, it may be equal to about 50 mV of electrical work, which is essentially removed from the gross output of the bottoming cycle itself. Thus, the fuel cell component of a pressurized system with a bottoming cycle may have the same overall efficiency as an unpressurized system operating at a potential which is 50 mV lower, for example at 0.75 V instead of 0.8 V. Since pressurized and unpressurized systems may operate at the same current density at 0.8 and 0.7 V, respectively, the pressurized system can be operated at higher current density at equal efficiency (i.e., at 0.75 V). This may change the current density at constant efficiency by about 20% for the pressurized example operating at a potential 50 mV higher than the unpressurized system. The result would be a 23% lower stack capital cost per kW. Operating an MCFC of this type in a pressurized mode is therefore an option, but whether the small gain in efficiency (or in stack capital cost) will be worth it remains to be seen, given the fact that high capital cost items, for example pressure vessels and a turbocompressor, must be added to the system. If the system has no bottoming cycle, all of the energy of pressurization can be provided by waste heat, so constant efficiency is represented by constant potential operation, i.e., at 0.7 V in the example given. Thus, pressurized operation would result in a current density increase of almost 45%. leading to a per kW capital cost reduction for the stack of 30%. This is a little more attractive. We should note that pressurized operation also leads to materials problems, which are discussed in the following section. Another possible way of improving the efficiency in either pressurized or unpressurized systems, as usual at the expense of capital cost, would be to discover a more innovative method of transferring co2 from the anode exit stream to the cathode input other than simply putting the gas mixture through a burner. In an external reforming system, this does not matter unduly. The heating value of this gas will be used to provide the heat of reforming, so it is not wasted. Similarly, in an internal reforming system with an associated combined cycle, the heat would again not be entirely wasted, since it would be used in a thermal cycle. However, this will be less efficient than the equivalent use of the gas stream in a fuel cell, if this should prove possible. Similarly, in a cogeneration unit, the waste gas stream would at least be recovered to provide salable heat, although this is far less valuable than electricity. If internal reforming is used in a non-cogeneration electric utility system, the anode off-gas is altogether wasted. If its heat content could be used via hydrogen separation and recycling, the effective efficiency of the cell could be increased. If all of the hydrogen could be used in the fuel cell via separation and recycled back to the anode, the coulombic efficiency would be raised from the single-pass utilization value (say 85%) to close to 100%. This would increase the gross efficiency of the electrochemical cycle. Naturally, separation would require work and also a higher capital cost. The question would therefore involve the parasitic power requirement for separation, as well as the total increase in capital cost. Steam separation requires only heat exchangers and a condenser, whereas H2 or CC2 separation is more complex. Carbon dioxide separation from the spent anode stream via a temperature-swing absorption process using magnesium oxide was examined in the late 1960s. with little success. This method would require one heat exchanger to cool the depleted anode stream to the absorber temperature, a heat exchanger to restore the hydrogen-rich stream to the anode inlet temperature, an absorber cycle, a heat exchanger to release CO2 and a further heat exchanger to take the latter to the cathode inlet temperature. Another

Fuel cell technology

545

which requires cooling the depleted anode stream to close to room temperature, would use a This was under examination at Mitsubishi pressure swing absorption system for CO2 separation. Electtics A further possibility is an electrically-driven fuel cell electrolyzer device to anodically oxidize low partial pressure hydrogen in the anode exit stream and cathodically evolve an equal amount of pure hydrogen to feed the anode inlet. Again, it would require cooling of the exit stream and reheating of the separated gases. It would use a carbon-rejecting aqueous fuel cell technology, for example, the PAFC or another acid system, e.g., the perfluorinated sulfonic acid polymer membrane or proton exchange membrane (PEM) cell. A concept similar to this has been described in Ref. 40. It is a PAFC-electrolyzer system operating at 200-250°C, which shows some tolerance to moderate levels of CO. In it, the electrochemical reactions occur reversibly at a sufficiently low level of Co in the reactant gas. Since its electrodes operate close to the hydrogen potential, corrosion and lifetime are not a problem. However, any such device operating with an MCFC would still require at least adequate reduction of CO in the MCFC anode exit stream to avoid poisoning of the PAFC anode in the separation device. The parasitic power is small, perhaps the equivalent of 50 mV for the transfer of 15% of the remaining hydrogen. This means an increase in fuel utilization from 85 to 100% (conceptually) for a parasitic electrical loss of only 1%. The practical hydrogen utilization would be approximately 96%. Thus, a system operating at 52% efficiency at 85% utilization without hydrogen separation (c.f., Figure 4) would have a conceptual efficiency of 58% with separation and recycle, taking into account parasitic power losses. The concept has been discussed elsewhere (See Ref. 6, p. 543). Both of the above systems would require three heat exchangers, which increase the capital cost of the system. Again, the tradeoff is in capital cost (and reliability) versuss efficiency, hence in cost of electricity. Attempts to operate the system at higher current density with a reduction in efficiency to offset the inevitable capital cost increase will run into the same diminishing returns as before.

possibility,

15. MCFC TECHNOLOGY

STATUS, 1991-92

During this period, technology was in the scale-up process to stack sizes which were suitable for electric utility use. The cells were typically about 5-6 mm thick. Based on 1.15 kW/m* of active cell area, a power density of about 0.2 MW/m3 was possible for the active part of the stack. Because of the requirements for manifolding, this fell by a factor of ca. 1.5 in practice, the actual value depending on cell active area. The power density value for the atmospheric pressure PAFC was greater by about a factor of two because of its higher current density. Short-stack testing was typically conducted to establish proof-ofprinciple for improved concepts to about 2,000 hours. Approximately 10,000 operating hours had been conducted on atmospheric pressure components, and many materials problems in the stack had apparently been overcome. One problem still remaining was the slow dissolution of the lithiated nickel oxide cathode material, for which a satisfactory more stable substitute had been found. Nickel micronodules deposit in a band close to the anode and can, under some conditions, cause substantial lifetime problems, for example shorting via dendrite formation between the anode and cathode. Nickel oxide dissolution is proportional to carbon dioxide partial pressure at the cathode, hence to total operating pressure.41 At a mean ca.thode CO;! partial pressure of 0.25 atm., a lifetime of 20,000+ hours before cell failure by shorting was antic:ipated (see Ref. 6, p. 571). However, with the engineering changes in ERC’s simplified atmospheric pressure system, the mean cathode CO2 partial pressure was only 0.108 atm, which should permit a predicted lifetime of 50,000 hours. While various engineering fixes might further improve lifetimes beyond those projected on p. 571 of Ref. 6, life under pressurized conditions (at several atmospheres) was problematical. Further discussion of this question is given in Section 26. Earlier problems, particularly corrosion and management of the electrolyte, became less important with the new techniques involved in scale-up. Thermal cycling, at least under carefully controlled conditions, became routine. The major problems as commercialization approached involved the fabrication of repeat parts, particularly those made from nickel-clad stainless steel sheet-metal. In future, consideration should be given to increasing power density and reduction in the amount of metal in the stack to lower costs. Finally, the special requirements of the design of pressurized systems, particularly those integrated with coal gasifiers for the central station, needed be addressed. A useful collection of papers on MCFC developments to 1990 is given in the volume cited as Ref. 34. 16. MCFC MARKETS, COMMERCIALIZATION,

AND CHARACTERISTICS:

1992 STATUS

Because of its high operating temperature and particularly because of its ability to use the ccl:, waste heat for reforming NG, the atmospheric-pressure version of the MCFC should prove attractive to utilities. It should be easily capable of 50% LHV efficiency in baseline operation at 0.73 V at 0.16 AJcmz. It could be operated at 48-50% LHV efficiency at a lower stack capital cost, if this is desirable. Whether units in the MW+ class will be attractive for pressurized operation at a higher capital cost remains to be seen. After the general failure of larger electric utilities to commercialize the large PC23 PAFC, wh.ich became apparent by mid-1988 (Ref. 6, p. 614-15), the American Public Power Association (APPA) decided to go

546

A. J. Appleby

ahead with a requirement for fuel cell power units. The organization represented about 2,200 of the smaller (for the most part) municipal utilities, with approximately 90 GW of capacity, some of it idle. Purchased power was 78% of sales. As much as 30 GW of capacity might use future fuel cells, if these have the right cost-effectiveness characteristics. In general, APPA members wanted equipment with capacities which were less than that of the 11 MW proposed for the IFC PC23 PAFC. Large utilities, e.g., Consolidated Edison in New York, wanted much larger units than 11 MW for urban sites, for example 100 MW. However, for both large and small utilities, the urban sites which were most suitable for dispersed fuel cells could not generally use units which had a power density of 29 MW/I-Ia (12 MW/acre), the value proposed for the PC23. For a greenfield site outside an urban area, land cost considerations dictated a density of about 110 MW/I-Ia (44 MW/acre), whereas for a repowering site in the inner city, the density should be in the 140-247 MW/Ha (57-100 MW/acre) range (see Ref. 6, p. 614). Thus, designs would have to be compact, and probably multistory systems or units making use of, e.g., building sub-basements, would be required to avoid excessive land costs. Similar considerations certainly applied in Japan, and sketches of 1991 fuel cell &signs showed multistory units.% In October 1988, the APPA published a “Notice of Market Opportunity for Fuel Cells” (the “NOMO”), summarized by Gillis (See Ref. 6, p. 614). The APPA estimated a total generation market for energy conservation technologies equal to 3,500 MW per year among its members, of which 900 MW per year could be fuel cells. The total capacity required might vary from 50 MW (e.g., for Manassas, VA) to 5,000 MW (for Los Angeles). The NOM0 considered that any fuel cell must compete with GTCCs in all sizes. The LHV efficiency must therefore exceed 50% on NG. The ideal NO;? emissions concentration was 10 ppmv, which could not be obtained in conventional combustion turbines in 1988, but could be attained in ammonia-injected turbine machinery. At 50% efficiency, this would correspond to NO2 emissions of 150 g/MWh. This value exceeded all proposed requirements, so that the very low emissions discussed earlier for fuel cells were not a significant environmental incentive,42 at least in the absence of equal characteristics in the areas of efficiency, cost and footprint. The guidelines given were that the power section (stack) of the fuel cell should cost no more than the combustion turbine element of a GTCC unit (about $25O/kW in 1995 dollars) and the total mature cost of a 50% efficient fuel cell power plant should not exceed about $75O/kW (1995), the value for a central station NG plant. 43 The plan provided for the construction of four or five 50% efficient demonstration units, i.e., using MCFC technology, and for orders for about 50 early production units to give an incentive to developers. The APPA considered that a 2 MW MCFC with a capital cost of $1,87O/kW (1995) would be economically the equivalent of a much larger combined cycle plant costing $l,OOO/kW (same basis), where both are assumed to be at a 65% capacity factor. The credits for the fuel cell, which made this equivalence possible, were (in mils/kWh): spinning reserve 3-4; peaking 4-5; transmission and distribution credits 2-14; loss savings 7-14; added reliability O-13; and environmental credits, 4-6. Together, these might average 3eJkWh (3.5cikWh in 1995). In addition, a credit could be taken for lack of S@ emissions, which may be sold to the operator of a coal plant under the new environmental regulations. In 1991, this was considered to be worth an additional 3-5 mils/kWh (3.5-5.5 mils/kWh in 1995) to the owner of a small MCFC plant.44 The plan was to build one 1.8 MW demonstrator (after the small San Ramon plant) in Santa Clara, with orders expected for at least 40 MW of 2 MW units, which was later expanded to a proposed 63 MW. Both ERC, the NOM0 selectee, and MC-Power Corporation (Burr Ridge, IL) were moving towards commercialization of small (up to 2 MW) units. Special conditions had been worked out regarding royalties to ensure sufficient incentive to pursue the program and still make a profit on a commercial target cost of $l,lOOikW (1995).45 Both developers were working within consortia whose objective was to ensure commercialization. M-C Power was a privately held corporation owned by the Institute of Gas Technology (IGT, then of Chicago, now of Des Plaines, IL, 51%). II-II in Japan (24.5%), and (originally) Combustion Engineering (Windsor, CT, 24.5%), which had become part of ABB. The initial technology input was supplied by IGT, and there was to be no technology transfer to minority stockholders. ABB declared in 1991 that the development of dispersed fuel cell generators would not be among its corporate goals, and it transferred its share in the company two years later to Bechtel, Inc. Demonstration and commercialization of MC-Power’s internally manifolded fuel cell technology was being conducted by the Alliance to Commercialize Carbonate Technology (ACCT, Ref. 46). This consisted of another group of electric utilities, and was being funded by the U.S. Department of Energy, the State of Illinois, the California South Coast Air Quality Management District (SCAQMD), San Diego Gas and Electric, Southern California Gas, Union Oil of California, the Institute of Gas Technology, EPRI and the Gas Research Institute (GRI, Chicago, IL). The Fuel Cell Commercialization Group (FCCG, Ref. 45) had 23 utility members and represented ERCs technology. It proposed several 2 MW demonstrators and about 50 early production units with a projected cost of $1,65O/kW (1995). The fist 2 MW unit was to be supported by a partnership between the City of Santa Clara Electric Department, EPRI, the Los Angeles District of Water and Power, Southern California Edison, and United Power Association-National Rural Electric Cooperative Association and other partners. Southern California Gas and PG&E were original supporters of the project. ERC had two MCFC system desi ns, The first (1.77 MW, &rated by 25% from maximum power) would have a full-load LHV efficiency o f 60%. a marginal footprint of 35 MW/Ha for a “flat” plant and rated emissions of 0.14 g/MWh N@ and 0.9 g/MWh SO2. The figure for NO2 was almost two orders of magnitude less than the measured value of the Goi 11 MW PAFC, and essentially counted as

Fuel cell technology

547

zero. The value is equivalent to 16 ppbv in the raw exhaust (20 ppbv dry basis, 9.0% oxygen). The corresponding S@ level in the raw exhaust would be 70 ppbv, i.e., the residual S content from 1.5 ppmv present in the feedstock. The gas feedstock must be desulfurized to 1.5 ppmv of less, oth.erwise the operation of the stack is affected. In 1991, little information had otherwise been given on MCFC emissions, although they were expected to be very low. Since the anode exit stream is burned to provide CO2 for the cathode gas, the whole exhaust from any burner (in the reformer or elsewhere) is passed through the catalytic cathode, which is an excellent reducing scrubber for NO2, which was expected to be “undetectable.” The learned-out cost of ERC’s FCCG 2 MW unit was estimated at $1,45O/kW (1995). A simplified system operating at 54% LHV efficiency with a slightly higher density footprint (43 MW/Ha) woald contain fewer heat exchangers (Ref. 6, p. 231-33) and was estimated to have an ultimate cost of :$1,12O/kW (1995).45 These values were costs of the equipment alone, and they did not include the cost of the site and its preparation. According to the 1990 Department of Energy assessment,28 the mature MCFC capital cost requirement was $71O/kW (electric utility, 1995 dollars) and $1,3OO/kW (on site, same basis) with efficiencies (presumed to be HHV) of 5560%. The capital cost of an MCFC coal plant (see below) operating at 5055% efficiency should be $1,42O/kW (same basis). As with the PAFC, the Fuel Cell Implementation Committee29 gave slightly different values. They were $95O/kW, $1,19O/kW and $1,42O/kW (same basis), operating at efficiencies of 55%. 50% and 50%, respectively. The major problems to ensure the commercialization of these systems were first, the requirement for adequate fuel cell stack lifetime with acceptable degradation in system heat rate, and second, capital cost. The initial cell voltage, hence the initial system efficiency or heat rate, was no longer an issue. The economic requirement for cell stacks was a five-year lifetime, over which they may be regarded as a consumable item in calculating the return on investment. This same assumption was used for the PAFC system. Any improvement in lifetime over the requirement of five years, which meant any reduction in the present performance degradation rate, was regarded as a bonus. Any possible sudden failure mechanisms, such as internal shorting due to cathode dissolution problems, must be eliminated during the statistical lifetime of stacks. This second issue was perhaps the mote important. The cost requirements are well illustrated by an evaluation of the MCFC in a Japanese context.34 Again, competitive Japanese capital costs seem very high compared with those estimated for the United States. To become a dispersed power source in the multi-10 MW to multi-100 MW range, the MCFC must have a maximum cost in the Y200,000-3OO,OOO/kW range (1989 Y, i.e., about $2,400-3,6OO/kW in September 1995 at the trading rate, or $1,800-2,4OO/kW at the PPP rate). The stack cost for such units should be Y70,000-lOO,OOO/kW ($1,680-2,4OO/kW, or $1,120-1,800&W, same bases). A good estimate of the cost of 1989 stacks, operating at about 1 kW/mZ, was Y198,OOO/kW ($2,4OO/kW or $1,8OO/kW, same bases). Of this, the cells represented 88.2%, structures 10.2% and the containment vessel only 1.6%. The aim would be to change these to a ratio of 3 1.2 : 6.0 : 1.6 at the same power density, giving a stack cost of about Y76,OOO/kW ($9OO/kW or $6OO/kW, same bases). Finally, the stack power density should be almost doubled to 1.8 kW/m2, giving a cost of about Y4O,oOO/kW ($475/kW or $32O/kW, same bases). This increase in power density was exactly the same as the U.S. objective.42 The weight of bare stack active components and the bipolar plate was about4’ 22.5 kg/m2, but this could rise by a factor of ten in assembled stacks with their associated equipment. Clearly, weights should be reduced and power densities increased, so that cost could be reduced. 48 A reasonable cost of the stack within a dispersed system should be one-third of the total, according to Japanese estimates, whereas for a large coal-fired central station it should be 15%. 34 Thus, the latter should cost a maximum of $2,13OkW for a PPP exchange rate stack cost of $32OlkW (1995). So far. Japanese efforts had been concentrated on increasing cell size to commercial levels ? For example, cell areas had been increased by a factor of 10 in area in 3 years, yet they still maintained laboratory performance. Cost reduction was to represent the next stage of activity.48 Abe et alM estimated that the Japanese market for the MCFC might be up to 10 MW by 2000, with up to 1 GW by 2010. The Japanese Government Agency reports quoted by Fukutome35 estimated HTFC markets as high as 2.4 GW by 2010. This estimate was not considered excessive, as it would only represent about 1% of total installed capacity. Following this, a l-1.3 GW per year of fuel cells could be introduced, of which 40% might be HTFCs. 34 We may anticipate that the two HTFC variants will share this potential market, should it develop as anticipated. We have already stated that a conservative estimate of the European fuel cell market might be 0.4 to 0.8 GW per year around 2000.32 Much, if not most, of this may be available to the MCFC, provided that it meets cost and performance goals. However, the market may be considerably more than this figure. The year 2010 is probably a better target than 2000 to assess the real market penetration capability of the fuel cell. The Italian market may be 0.3 GW per year for both the PAFC and MCFC.31 However, by then penetration of the PAFC may peak, and that of the MCFC may continue to rise to 0.6 GW per year by 2025. Thus in Europe as a whole, the MCFC market may be 1 GW per year in 2010 and 2.5 (GW per year in 2020. This was also borne out by an estimate for the Netherlands cogeneration market.33 In 1990, this was predicted to start in 1995 and displace 20 PJ of NG per year in 2005 via increased efficiency using dual end-use. This implies 23 MW per year growth for the MCFC, assuming a 65% capacity factor. The corresponding estimates for 2010 and 2020 were 100 PJ and 150 PJ, respectively, if limitations in CO2

548

A. J. Appleby

emissions are enforced. These would be equivalent to 1.6 and 2.4 GW per year, respectively. The MCFC market in Europe therefore appeared to be promising in 1990. In Germany, MBB had taken a minority interest in ERC and intended to set up a 2 MW MCFC production line with the initial ability to supply 40 MW per year.j2 The situation from a 1995 perspective is reviewed in Section 26. The MCFC system still required improvement to be fully cost-effective, notably from the viewpoint of simplification at both the system and component level, and it needed an examination of possibilities which offered increased power density, so that the capital cost of the stack components might be further reduced. Provided that these do occur, the system seemed assured of an exciting future for both NG fuel and for other carbonaceous gaseous fuels, e.g., those derived from biomass and waste. 17. MCFC-COAL CENTRAL STATIONS For the United States, a 1991 EPRI assessment49 of the penetration of the coal gasifiers operating with an integrated combined Brayton-cycle gas turbine using a steam Rankine bottoming cycle (Integrated Gasifier Combined Cycle, IGCC) indicated that these may be deployed over a 30-year period starting in 1995. HTFC systems, using the MCFC as an example, were then expected to demonstrate coal gas operation starting in or about 1994, with integrated gasifier demonstrators operating starting about 2000, and prototype units about 2008. Deployment of commercial units equivalent to 5% of the U.S. market, or 75-125 GW depending on load growth, was expected by the year 2040. The MCFC with an integrated coal gasifier would be used as a topping cycle. Waste gas from the fuel cell (and any gas bypassing the fuel cell) would be burned in a turbine, probably using the cathode exit stream, which would provide shaft work. Waste heat from the gasifier itself, the fuel cell stack and the exhaust of the turbine would be used in a steam cycle. Because of the requirement for a steam cycle (and for a gasifier), the system would be large, with a minimum size of perhaps 200 MW. It would therefore be a central station technology. Adding the MCFC had an advantage over a simple IGCC in two areas, reduced NO;! emissions and overall efficiency. The reduction in NO2 emissions would depend on how much gas is recycled in the system through the fuel cell cathode after combustion, compared with how much is directly rejected through the turbine exhaust. This depends on system &sign, i.e., on cost-effectiveness, particularly on the tradeoff between system efficiency and lowest cost of electricity. A high overall efficiency will result from the use of an energy recovery cycle. A coal gasifier produces hot gas at a pressure between 1 atma and 68 atma, depending on the technology. Conventional gasifiers operate by partial oxidation, associated with injection of greater or lesser amounts of steam to encourage water-gas shifting. This is considered in more detail below. If the reactor is air-blown, the gas has a low volumetric BTU content (equivalent to about 17% total CO plus H2 for a Texaco entrained-bed gasifier), whereas it has a medium BTU content (for example, 58% CO, 39% Hz) for an oxygen-blown gasifier. The trend has been to recommend the use an oxygen-blown system associated with a liquid-air plant to produce a calorically richer gas. This results in a good energy trade-off between that required for oxygen separation and the net improvement in energy efficiency which results from elimination of excess nitrogen from the coal gas. Some further qualifications will remain, for example a gasitier must not produce a high concentration of higher hydrocarbons if the feedstock is to be used in a (non-internal-reforming) fuel cell. In particular, the gas must be tar-free. This sets a lower limit on the oxygen-to-carbon ratio and the bed temperature. Coal gasifiers are discussed in Refs. 50 and 5 1. The gas composition will depend on the type of gasifier, which may operate oxygen-rich or oxygenlean, and may use variable quantities of steam. The Lurgi moving-bed gasifier operates at about 900°C with a relatively low Cl2 : C ratio (about 0.25) and a high steam-to-carbon ratio (2.4) to keep the temperature low enough to prevent ash melting. At the other extreme is the Shell entrained bed gasifier, which operates at a high temperature (1,650’C) at a high 02 : C ratio (0.45) with little steam injection. The first approach produces large amounts of hydrogen by water-gas shifting. A hydrogen-rich gas at lower temperatures (and high pressures) favors some methane formation. Hence, the Lurgi gasifier, and more particularly the IGT HyGas entrained-bed process, result in a gas containing methane. The Lurgi gasifier was favored for producing gas for hydrocarbon synthesis (e.g., in the South African Sasol Process), since it gives a composition with a high H2 : CO ratio (about 40 and 15 vol. %, respectively, with 30 and 10 vol. % of CO2 and methane). The Shell fluidized-bed gasifier produces a gas which typically contains approximately 33 vol. % H2 and 65 vol. % CO, the remainder being CO2. Thus, the effective LHV for the Shell product gas is 1.395 eV. That of the above Lurgi gas is 1.197 eV, whereas that of the methane-rich HyGas product is about 1.170 eV. The differences in gas composition can be best appreciated if they are considered after water-gas shifting to completion. The H2 : CO2 ratio in the Shell gasifier would then be about 1.45, whereas that in the Lurgi gasifier would be 1.7. Gasifiers operating under oxygen-lean conditions include the British GasLurgi Slagger moving-bed system and the Kellogg-Rust-Westinghouse (KRW), which have a Hz : CO ratio of about 0.6 with a Cti : H2 ratio of 0.25 to 0.4. Fully steam-reformed and shifted, the H2 : COZ ratio of the Lurgi Slagger gas would be 1.8. The HyGas system has a Hz : CO ratio of about 1.25 and a CH4 : HZ ratio of about 0.6. After complete reaction, its HZ : C@ ratio would be 1.94. This overall range (1.4 : 1 to 1.93 : 1) represents the extreme Hz : co2 ratios available in different gasiflers. Coal gasification is similar to hydrocarbon steam reforming, but the energy input to the reactor is provided by combusting part of the fuel internally, rather than in a separate reactor with a heat transfer

549

Fuel cell technology

system operating between the two. The same procedure has also been examined in the adiabatic steam reforming of hydrocarbons. Carbon oxidation proceeds in two stages: first to CO, then to C@. The fast partial oxidation stage consumes only 28% of the heating value of pure carbon fuel. Coal contains carbon with some hydrogen, which together account for the greater part of its heating value. The energy content of most coals can be reasonably accurately expressed (to within about 0.05%) by a standard formula which multiplies the percentage composition of each component by a numerical value, the sum of which gives the HHV. In BTU/lb., the multipliers are: C, 146.58; H, 568.78; G plus N, -51.53; S, 29.4; ash -6.85. The corresponding values in kJ/kg are obtained by multiplying by 2.325. The LHV is then obtained by multiplying the weight of water formed on burning unit weight of coal by 1,030 (in BTU/lb.) or 2,395 &I/kg), and subtracting this value from the HHV. Thus, a typical high-quality coal (Allegheny-Pittsburgh) has the composition (in wt %) C, 77.7; H, 5; 0,6.2; N, 1.5; S, 1.6; ash, 8, and has calculated and experimental HHVs equal to 13,828 and 13,890 BTU/lb. respectively. Using the experimental HHV and the above formula, the LHV is 13,428 BTU/lb. After elimination of H#, N2 and S@, it has a nominal formula for the elements active in gasification given by CI-Ioa. This molecular group supplies 4.68 electrons, so the coal has an effective HHV of 1.105 eV and an LHV of 1,069 eV. Energy must be supplied to convert this coal into gas with a higher effective heating value. For example, the Shell gasifier must upgrade from 1.069 to 1.395 eV. The overall reaction in the gasifier is essentially a thermal and materials juggling act, in which balanced amounts of oxygen and steam are added to maintain the reactor temperature under controlled mixing conditions. Inside, the water-gas shift and producer-gas reactions are at equilibrium. High oxygen, low steam conditions will favor a high temperature with high CO in the product, whereas low oxygen and high steam will give a low temperature and will favor hydrogen, some methane, with CO2 and little CO. High pressure will favor methane. The Shell gasifier will be used as an example of the high oxygen, low steam reactor. For illustrative purposes, we will consider the above coal with the “model” formula Chop. To achieve the Shell gasifier product exit conditions, the overall reaction may be approximately written as follows (gas LHV values are in parentheses): lOOCI-Io.68 + l6HzO + 43.002

+

2CO2 + 98CG + 5OH2 (Shell, 1.395 eV).

This reaction scheme takes into account the thermal balancing requirements by using a real output product gas composition from a real reactor. By summing the energies of the coal fuel in and the product gas out, but for the present ignoring the steam energy requirement, the LHV efficiency of the gasifier itself is 82.5%, based on reactants in and products out, both at 25°C. Taking into account the steam-to-carbon requirement (0.28 : 1) calculated from the difference in the heats of formation of gaseous and liquid water at 25’C, the LHV efficiency is 80.5% (82.2% coal HHV to gas I-II-IV). If the process is used only as a gas generator, the steam will be provided by burning coal, as is assumed here to calculate the theoretical efficiency. If the system is used for Rower generation, steam will be recovered from waste heat elsewhere, for example from turbine or fuel cell exhaust. The archetypical low-oxygen, high-steam Lurgi gasifier has an overall reaction which approximates to: lOOCI-Io.6a + 8OH2O + 28.502

+

55CG2 + 27C0 + 78H2 + l8CH4 (Lurgi, 1.199 eV).

Without the steam-to-carbon requirement (2.4 : 1), the in-gasifier LHV efficiency in this reaction is 84.9%. Taking the high steam requirement into account, the LHV efficiency is 69.6% (75.6% coal-to-gas HHV). The KRW fluidized bed gasifier lies between the Shell and Lurgi processes in operating characteristics. Its temperature is about l,OlO’C, and its steam requirement is less than that of the Lurgi system, but its oxygen requirement is slightly higher. Its overall equation, based on the design estimate given on p. 891 of Ref. 50, is approximately: lOOCI$6a+38.5H~O+3002

+ 13.1C@+72.3C0+43.3H2+14.6CI-I~

(KRW, 1.271 eV).

Based on this material balance, the in-gasitier efficiency would be 88.4% and the process efficiency, taking into account the steam-to-carbon requirement (1.82 : 1). would be 75.8% (78.8% coal-to-gas HI-IV). The Texaco entrained-bed gasifier is another high-temperature system (1,48O”C, steam-to-carbon requirement 0.60 : 1), which was used in the Cool Water prototype IGCC plant.52 Its material balance is approximately: 10OCI-&)68+ 24.4H20 + 46.302

+

17CG2 + 83C0 + 58.4H2 (Texaco, 1.379 eV).

The product gas is less rich in CO than that from the Shell gasifier, so that the in-gasifier efficiency is lower (78.0%) with an overall LHV efficiency, including steam, of 73.9% (76.4% coal-to-gas HHV). The British Gas-Lurgi Slagger, an oxygen-lean Lurgi system, operates with a low steam-to-carbon ratio (0.6 : 1) at a higher temperature (1,480“C) and may be represented by:

550

A. J. Appleby

loOC~.68+39.8H20+25.802

+ 2.9C@+85.6C0+50.8H2+1

lSCH4 (BGL, 1.300 eV).

Based on this material balance, its in-gasifier efficiency is 94.8% with an LHV process efficiency of 89.9% (93.1% coal-to-gas I-IHV). The above gasifiers generally convert the fixed carbon in coal at greater than 99% efficiency. Any remaining carbon is left in the ash or slag. An exception is the KRW system, which had operated at only 76% carbon conversion by 1986 (Ref. 50, p. 891), but was projected to obtain about 90% conversion. A final gasifler which should be considered is the proposed Exxon catalytic system, which would operate at 7OO’C at 36 atma using potassium ion catalyst (as KOH or K2CO3) to isothermally gasify coal (LHV 1.069 eV) to methane (U-IV 1.040 eV). This driving force is small, so the reaction does not go to completion. The complete reaction would be approximately 1OOCHo.~ + 83H2G -_) 41.502

+ 58.5CH4 (Exxon, 1.040 eV).

A steam-to-carbon ratio of 1.9 was used. The reaction is kinetically limited and about 27 volume % of methane was present in the off-gas. The gross LHV efficiency of the process (including the energy for the required steam) is 82.9% (89.4% coal-to-gas HI-IV). For all gasifier technologies, the real efficiencies of gasification will be lower than those given above, due to less than theoretical conversion, heat losses in the remaining system, clean-up requirements, etc. The additional loss is typically about 3-5%. If the coal-derived gas is used in a gas turbine, its effective equivalent heating value is irmlevant, and the most efficient gasifier will, give the highest system efficiency. This is because the heat engine operates only on the heat content of the gas. However, if the gas is used in a HTFC, the situation is like that discussed earlier for internal reforming of NG. The gas is converted to hydrogen in the fuel cell, which operates not on the heat content of the gas, but on the Gibbs energy of the hydrogen produced from the gas. Thus, gas from the Shell gasifier is transformed into dc electricity at 52.4% in-cell LHV efficiency (0.73/1.393) in an atmospheric pressure HTFC operating at 0.73 V, the remaining energy being given out as heat. In the Lurgi gasifier, the corresponding dc LHV efficiency will be 61.0% (0.73D.197) and, correspondingly, less heat will be rejected. Overall, the coal-to-dc efficiency will be 39.2% for the Shell system operating at a practical coal HHV-gas LHV efficiency of 74.9% and 39.2% for the Lurgi system operating at a coal HI-IV-gas LHV efficiency of 64.3%. The dc in-cell efficiency for the British Gas-Lurgi Slagger would be (0.73D.299) or 56.2%. If the gasifier coalHHV-gas LHV efficiency is 82%. the overall efficiency (coal HI-IV-dc power) would be 46.1%. This illustrates the fact that the most effective gasifier for use with a HTFC may not be the same one which is most effective for use with a gas turbine. In general, the figure-of-merit for a fuel cell is equal to gasifier efficiency divided by heating value per equivalent of gas produced. A gasifier producing a large amount of methane (1.040 eV LI-IV) will give a more efficient system than one producing a large amount of CO (1.467 eV) at equal gasifier efficiency. If the Exxon gasifier could operate at a practical coal HHV-gas LHV efficiency of 77.9%, its coal HHV-dc power efficiency would be 54.7%. Another approach might be to gasify using fuel cell waste heat, in the manner of internal reforming, using CO2 separated from the MCFC anode tail gas, rather than steam. The approximate reaction is lOOCHo.68 + lOOCo2 +

200C0 + 34H2 (1.436 eV).

The coal HI-IV-gas LHV for this process would be 130.0%, the heat for upgrading being supplied by a fuel cell operating at reactor temperature. The coal HHV-dc power efficiency at 0.73 V would be 66.1%. However, if the CO product could be methanated to completion, the resulting gas would have a lower heating value per equivalent, with a coal I-II-IV-gas LHV process efficiency of 121.5%: lOOCHo.68 + 83CO2 +

166C0 + 17CH4 (1.343 eV).

The resulting coal HHV-dc efficiency will however be the same, i.e., 0.73D.105, or 66.1% at 0.73 V. Any such proposals will of course require some innovative approaches for heat transfer. To illustrate the advantages of HTFCs used with conventional gasifiers, we will first consider an illustrative IGCC system. Heat is recovered from the system to raise steam for gasification. We will assume that 16.5% of the coal HI-IV is the steam requirement, corresponding to a steam-to-carbon ratio of about 1.7. All remaining heat will go to the bottoming cycle. We assume a gasifier coal HI-IV to gas LHV efficiency of 67%. The gas from an oxygen-blown gasifler enters an IGCC turbine at high pressure and contains a considerable amount of sensible heat. Taking into account the turbine losses due to the exhaust back-pressure resulting from the requirements for heat transfer to steam for the bottoming cycle, an effective 30% LHV efficiency may be obtained in the Brayton cycle, giving 20.1% of the coal heating value in the form of ac power. The remaining high quality heat (70% of that of the gas entering the turbine, i.e., 46.9% of that from the coal burned, plus 16.5% from the rest of the system after the requirement for steam) can be used at 38% efficiency in the steam cycle. This gives a further 24.1% of ac power, i.e., a total HI-IV As this is for comparison purposes, it and the efficiency coal-ac of 44.2%. with minimal emissions. following examples ignore the power requirements of a liquid air plant to supply the gasifier.

Fuel cell technology

551

Let us now consider some postulated fuel cell cases. The medium BTU gas, assumed to be 58 vol. % CO and 39 vol. % HZ, has a relatively high effective heating value on a per equivalent basis (about 1.34 eV). An MCFC operating on this gas at 0.73 V and 85% utilization would convert it to dc power at 46.3% efficiency. This gives the equivalent of 31.0% of the coal heating value as dc power. Assuming an inverter efficiency of 97.5%. this corresponds to 30.2% ac. Approximately 2% will be lost in gas circulation and cooling in the fuel cell stack, giving 28.2% net. The remaining heating value of the gas (67-31%) is available as anode exit gas and fuel cell waste heat. This and the remaining heat (16.5%) can be converted at 38% efficiency in a steam cycle to give a further 20.0% as ac power. The total HHV ac efficiency is therefore 48.2%. If the fuel cell can be operated at 8 atm. pressure, it may be capable of operation at a voltage of 0.87 V, rather than 0.73 V. Thus, it will provide a dc output efficiency of 0.87/1.34 on 85% of the gas, the latter being equivalent to 67% of the coal heating value. Thus, its gross electrical efficiency is 37.0% dc or 36.05% ac. The waste heat from the fuel cell and its anode exit stream and the remain&r of the system is (67 - 37 + 16.5)%. Conversion of this at 38% efficiency in the steam cycle adds 17.7% to the available ac power, giving a gross total efficiency of 53.7%, of which the fuel cell provides 67.1%. If the pressurization requirement in the fuel is provided electrically and 70 mV (50% of the pressurization gain) is required for gas supply and cooling circulation, we must reduce the output by the corresponding fraction of parasitic power or 3.0% of the coal heating value. This gives a net coal HHV to ac efficiency of 50.7%. In both of the above examples, we assumed that the anode waste stream was simply burned to raise steam. If it is used in a gas turbine cycle, essentially free pressurization can be provided for the fuel cell, and some shaft work (say 25%) can be available. The high-humidity, high C@ low-BTU depleted anode stream can be burnt at high oxygen utilization in the turbine, and the exhaust recycled to the fuel cell cathode. No waste heat for a steam cycle can be recovered from this stream. In this case, operation at 85% utilization gives 37.0% dc or 36.0% ac, and the fuel cell waste heat of 20.0 and 16.5% from the remaining system are available for the steam cycle. This will yield 13.9% ac at 38% efficiency. Finally, the 10.05% of heat in the anode gas exit stream can be converted by the turbine at 25% to give a further 2.5% ac. The net total HHV efficiency is then 52.4%. These demonstrations are highly oversimplified, since they ignore changes in gas heat content with pressure and temperature, parasitic losses resulting from gas clean-up, and other factors. However, they are useful for comparison purposes. The replacement of a state-of-the-art gas turbine with an atmospheric pressure MCFC operating at its present parameters (0.73 V on medium-BTU gas at atmospheric pressure and 85% utilization) will give a useful increase in performance of about 4 %, reducing fuel costs by 8%. However, the cost of electricity is unlikely to fall unless the MCFC stack is less costly and longer lasting than the turbine. It should therefore cost $25O/kW (1995) and have a 15-30 year life with low maintenance, which seems unattainable today. Fuel cell stacks with a life of e.g., 5 years must be rlegarded as consumables, like fuel. At 80% capacity factor, a stack cost of $3oO/kW over 5 years at 12% interest represents about 17 mils/kWh, whereas a $25O/kW (1995) turbine having a total annual charge of 20% of its cost represents about 7 mils/kWh. The fuel cost of electricity from coal at $1.50/l@ BTU ($1.42/GJ) costs only 10 mils/kWh at 50% efficiency. In addition, an atmospheric pressure MCFC requires very large piping diameters and will therefore be a costly plant. The increase in efficiency is quite insufficient to pay for the difference between the cost of the stacks with their atmospheric pressure piping and the cost of the turbine. A pressurized MCFC can give higher performance, and its gas management system would have a lower capital cost. Its improvement in efficiency, when combined with an exhaust-driven compressor, would result in a system efficiency (for the above example) 8.2% greater than that of an IGCC plant, giving 15% lower fuel costs. The addition of a fuel cell will generally only make sense when it is pressurized and works in conjunction with a turbine supplying essentially free compression, circulation work and some shaft power. In the example above, which was intended simply for illustration, a small turbine operates on 85% depleted anode exit gas. In reality, the gas output will have a larger BTU share going to the turbine in an optimized system, which may not have higher efficiency, but could have a lower cost of electricity by making better use of capital invested. The turbine might bum anode-off gas, perhaps mixed with raw gas, using depleted compressed cathode air and/or cooling air, if applicable. Let us now consider the use of a product exchange device to separate hydrogen and CO2 in the anode exit stream which uses the equivalent of 10 mV net electrical energy from the fuel cell s,tack. This corresponds to transferring 15% of the hydrogen in the anode tail gas under an electrical load of 67 mV. We assume, as before, that the cell operates pressurized at 0.87 V and that it requires 70 mV equivalent of auxiliary power for pressurization. The gross dc output from the fuel cell will now be 43.5% at 100% gas utilization, or 42.4% ac. The heat for steam cycle is now the waste heat from the fuel cell a.t 100% gas utilization (i.e., 67% - 43.5%), together with the 16.5% remaining, i.e., a total of 40%. After conversion of this amount at 38% in the steam cycle, a total gross ac efficiency of 57.6% is obtained. After correction for auxiliary power for pressurization and H2/C02 separation, the overall HHV efficiency is 53.6%. The same calculation carried out for an atmospheric pressure system shows 51.0% net coal HHV to ac efficiency, assuming a 2% parasitic loss for gas circulation. In other words, an atmospheric pressure system with a product exchange device operating with no gas turbine may be almost as efficient as a pressurized system with a turbine operating on anode off-gas, where both systems inchde a steam bottoming cycle. Again, the problem will be higher capital cost, therefore a higher electricity cost.

A. J. Appleby

552

Any trade-off between efficiency and capital cost of the fuel cell in any of the above instances will be as unfavorable as in previous instances, because of the comparatively high polarization slope of the MCFC. Hence, a high-performance MCFC coal gasification system, of whatever technology, should be regarded as one having the highest efficiency. If the system is correctly designed, it should always be mom efficient than an IGCC, because of the intrinsically higher efficiency of the fuel cell itself. If it has a product exchange device, it should be mom efficient than a MCPC-turbine combination, since any gas can be used at higher efficiency than in the turbine. It could be argued that the development of an effective product exchange &vice may be more important than that of a pressurized MCFC. If MCPC performance (i.e., polarization slope) remains much the same as at present, one will not gain much in power density at constant cell voltage by the use of pressurization. Operating under pressure will cause problems in the MCFC as we know it today. One certain problem will be dissolution of the lithiated nickel oxide cathode. Other problems, e.g., sealing and pressure gradients across the system, will also arise. For every molecule of hydrogen consumed at the MCFC anode, one molecule each of water vapor and C@ am produced. At the cathode, half an oxygen molecule and one Coz molecule arc simultaneously consumed, and no reaction product is formed in that stream. This may produce pressure gradient and flow distribution problems from the entrance to the exit of the elect&es, giving cross-leaks in pressurized systems (c.f. MC-Power, Section 26). There have been many studies of coal gasifier-MCFC systems. A discussion of concepts up to 1988 is given in Ref. 6. Some recent comparisons are given in Ref. 45. An oxygen-rich (02 : C ratio 0.46, low steam) entrained bed gasifier (Texaco) was compared with two oxygen-lean reactors (02 : C ratio 0.26-0.3. Hz0 : C ratio, 0.29), moving bed (British Gas-Lurgi) and fluid&d bed (KRW) types in the context of a small 200 MW MCFC unit. Their estimated HI-IVefficiencies increased with gasifier efficiency and were 45.1% 46.3% and 47% respectively, compared with 40.5% for an IGCC, 32.3% for a pulverized coal (PC) unit and 31.6% for an Atmospheric Fluidized Bed Combustion (AFBC) steam plant. No;? emissions (g/MWh) were “trace,” 82, 41, 450, 500 and 363, respectively. So;! emissions were 14, 113, 1.4, 36, 1790 and 1820. Another analysis of comparative emissions (in g per MWh, g/GJ, and lb./MMBTU) is given in Table 3. which includes data PC and AFBC plants and for the Shell entrained-bed gasifier, which gives particularly low N@ emissions. The N@ emissions figures for NG MCFC and SOFC systems (see below) and its measured value for the Cool Water IGCC pilot plants2 are also indicated. We should again note that sulfur emissions from the MCFC exhaust will represent a maximum of about 1.5 ppmv in the incoming gas, because desulfurization is required to avoid interference with the anodic process. This might represent only 0.2 g/GJ of coal input or 1.4 g/MWh of fuel cell output. Higher values of S& and NO2 emissions am from elsewhere in the system. N& emissions in the MCFC exhaust will be negligible. The above analysis points out the attractions and some of the difficulties of MCPC coal-gasifier systems. It also gives some alternative approaches, particularly the possible use of ambient-pressure systems with product exchange devices, provided that they and the necessary heat exchangers are sufficiently costeffective. It has also considered the advantages of gasifiers which produce a considerable amount of methane. It is generally accepted that the MCFC-Integrated Gasifier concept makes sense and should have the highest efficiency and lowest emission of Na of all systems, if technical and capital cost problems can be solved. S@ emissions will be limited to the ability of the MCFC to withstand this pollutant, and will therefore also be extremely low. However, it seems clear that the MCFC must become a proven technology in small NG slants before it is aoolied to intearated coal easifier svstems. This will reouire exnerience with (probably) two generations of r&ively ma&e MCFC &I&, i.e:, a total operating ofaa least i0 years after the introduction of the first semi-commercial small MCFC svstems. Thus. it seems unlikelv that introduction of integrated MCPC coal gasifier technology couldbe contemplated before 2010. *If all circumstances arc favorable, for example, capital costs, materials problems, and stack lifetimes are within. the required goals, the first commercial plants might start to operate about the year 2020. In this time-frame, the gas turbine is likely to make rapid strides in performance and emissions, so the future of the MCFC as a topping cycle in IGCC plants certainly cannot be assured. Table 3. Emissions from coal technologies @MWh, g/GJ, Ib./MMBTU respectively). System efficiencies in parentheses. PC = pulverized coal steam plant. AFBC = atmospheric fluidized bed combustion steam plant. IGCC = integrated gasifier combined cycle plant. KRWiMCFC = Kellogg-Rust-Westinghouse gasifier MCFC plant.

Emission

PC (32.3%).

AFBC (31.7%)

IGCC (40.5%)

KRW/MCFC (47%)

British Gas Lurgi/MCFC (47%)

S hell/MCFC (45%)

SO2

1790; 160; 0.37

1820; 160; 0.37

36; 4.1; 0.01

170; 22; 0.05

38; 5; 0.01

40; 5; 0.01

NQ?

500; 45; 0.1

365; 32; 0.075

450; 50; 0.12

410; 54; 0.125

168; 22; 0.05

<8; 1; 0.02

Fuel cell technology

553

A final aspect of integrated coal gasifier systems, whether with gas turbines, MCFCs or a combination of both, is the possibility of operating the gasifier in a baseload mode with cycling of the electrical generation load. The excess gas at off-peak periods can be used for manufacture of synthetic fuels. It can be used full-time for C@ separation for enhanced oil recovery after water-gas shifting.53 This may provide a future route for Cti sequestering, since its separation, if not its transportation, is relatively simple and low-cost. The gas used in the plant is now hydrogen, which allows an economical way of manufacturing this quintessential fuel for fuel cells, e.g., for use in hybrid fuel cell vehicles for surface transportation. This future concept of the “Coal Refinery” has been referred to in Refs. 54 and 55. 18. SOLID OXIDE FUEL CELLS:

1992 STATUS

The tubular Westinghouse Electric Company (Pittsburgh, PA) SOFC was conceived in 1980 to eliminate fabrication and interconnection problems associated with previous concepts (Ref. 6, pp. 589605). Internal resistance considerations resulting from the use of peripheral current collection originally limited the tubular cell diameter to 1.7 cm. During the mid-1980s, the cells were 30 cm long with an active zone of 20 cm, producing about 10 W per tube at 0.65 V and 0.15 A/cm 2. By 1987-88, the cells had been increased in size to 50 cm in length with a slightly smaller diameter (1.4 cm) and 36 cm active length (135 cm2). These tubes were used in 400 kW modules tested at TVA and 3 kW units tested at Osaka Gas and Tokyo Gas in 1986-1988. They operated on hydrogen, and could operate on simulated reformed gas. A $6 million pilot plant financed by Westinghouse and GRI, which could produce 10,000 tubular cells up to 100 cm long per year, was constructed at that time. Originally, calcia-stabilized zirconia (CSZ) support tubes were produced at Westinghouse by a pug-milling process, followed by extrusion. The cell operated at about 1000°C using a thin (30-50 pm) film electrolyte consisting of zirconia containing 8-10 atom % yttrium (yttria-stabilized zirconia, YSZ). The electronically-conducting airelectrode material (strontium-doped lanthanum manganite, LSM) was deposited on the support tube by filtration, followed by air-sintering at 1,350”C. This was masked, and an interconnect strip of a conductor stable in both anode and cathode atmospheres (magnesium-doped lanthanum chromite, LMC) was &posited after masking. The process used was called electrochemical vapor &position (EVD), in which metal oxides mixed with carbon black are reacted with chlorine to give the mixed chloride vapors, which are passed at about 1,250”C over the porous part to be coated. On the other side, water vapor and hydrogen is circulated. Hydrolysis first occurs to give a chemically-deposited metal oxide, which has enough oxide ion and electronic conductivity to allow further oxide formation to occur electrochemically after a continuous film forms, the products being chlorine and hydrogen at each side, respectively. After deposition of the interconnect strip, the tube was again masked to prevent the latter being coated, and electrolyte layer was deposited by EVD. A nickel powder anode slurry was then applied to this layer, and a third EVD deposit of YSZ was made in the pores of this anode structure to act as a sintering inhibitor and to give a porous diffusion anode with an extended three-phase-boundary interface. Because the growth YSZ is electrochemical, it results in an optimum electrochemical solid phase interfacial structure for hydrogen oxidation. The interconnect strip was then nickel-plated and joined to a nickel felt forming an electronic contact to the anode of the next cell. Thus the series-parallel connected tubes lie in a bundle or stack. The above adds further information to the details of construction and cell assembly given in Ref. 6, p. 591-605. The structure requires that the interconnect should be stable under both anodic and cathodic conditions. All components should have matched thermal expansion coefficients, and they must be fabricated successively with the correct porosity and other properties without mutual interference. Westinghouse has admirably succeeded in doing this, since the ingenious EVD technique gives thin, non-porous films with controlled properties. However, it is slow and requires expensive equipment. The tubular Westinghouse cells have been shown to be robust, capable of thermal cycling and will operate well, even if the nickel cermet anode is put through an oxidation-reduction cycle. Air is passed into each tube through a thin alumina tube, which acts as an internal ceramic heatexchanger. Fuel gas (reformate) is supplied co-flow to the outside. The inactive portions at the open ends of each tube passed through a hole in an alumina header plate, in which excess air (5-6 times stoichiometric, for heat removal) and spent anode gas (after 85% utilization) react, forming a ceramic air preheater. The alumina tubes continue through a second header, where they are supplied with air at 600°C from a 316SS heat exchanger. The combusted anode exit gas-air mixture is passed to heat exchangers which serve as reformers. From any point on the cell surface, electronic current is collected around the tube peripherally via the anode and in the opposite direction via the cathode, which is supplied with air on the inside of the support tube. The latter had no electronic conductivity’in the original design. Because of the long electronic pathway, the thickness of the anode was critical, and since 1991 high-performance cells have used a support tube made from electronically-conducting LSM cathode material. As a result, the internal resistance has been considerably reduced, as has area of tube and weight of raw material required per kW. Since materials costs are relatively lower than fabrication costs at the present state-of-technology, this will result in a lower per kW investment. At l,OOO°C, kinetic polarizations are small. However, as Figure 2 shows, this high temperature of operation is a thermodynamic disadvantage in that the reversible potential of the: anode tail

554

A. J. Appleby

gas, i.e., the highest possible cell potential, is only about 0.78 V at 85% utilization on pure hydrogen. It is therefore important to keep all losses as low as possible to minimize the effect of this disadvantage. On hydrogen fuel at 85% utilization and atmospheric pressure, performance at 0.65 V (about 0.280 V total thermodynamic loss) successively increased from 0.15 to 0.235, to 0.35, then to 0.45 A/cm2 in 1985, 1988, 1990 and late 1991, respectively. The latter value was for the then-experimental cell using electronically-conducting SLM air electrode material as the support tube for the cell structure. These results are shown in Figure 5.56 Results on NC reformate are about 20-30 mV less than those shown for hydrogen. In 1986, the initial polarization resistance of Westinghouse cells was about 0.95 a-cm2, whereas the initial polarization resistance of the best conventional (calcia-stabilized zirconia support tube) Westinghouse SOFCs was about 0.28 R-cm2 (3/1991 plot on Figure 5). For cells with support tubes made from electronically-conducting air electrode material, the corresponding initial polarization resistance was only 0.19 R-cm2. The effective (i.e., overall) polarization resistance of the atmospheric pressure state-ofthe-art MCFC under practical system operating conditions was about 1.05 R-cm2 at a constant 75% utilization (Figure 5). All future Westinghouse SOFC systems will be constructed on air-electrode-support (AES) tubes made from LSM, and they will give performance equivalent to or better than that shown in Figure 5. These improved cells can now be operated at current densities of 0.70 A/cm2, at 0.5 V. At the same current density, the MCFC would operate at 0.25 V or less, assuming a (doubtfully) linear polarization curve. Indeed, the present MCFC could not effectively operate at 0.5 V because the nickel anode structure would probably be damaged by oxidation under these conditions. Sources state that 100 cm AES tubes are produced for Westinghouse by Kyocera and NGK in Japan, since potential U.S. developers were unwilling to develop new components until a certain market potential was visible. However, this has not been confirmed by any of the companies in question. To achieve parity with the GTCC, the SOFC must have a LHV efficiency on NG of at least 50%. As we have seen earlier, 55% LHV efficiency will be attained at 85% utilization at 0.67 V, if internal reforming is used. The value of 55% will be degraded to about 5 1% after circulation power and dc-ac conversion are considered. From Figure 5, this corresponds to 0.38 A/cm2 with reformate, using the latest technology. However, thanks to its lower polarization than that of the MCFC, a 70 mV performance trade-off (i.e., from 51 to 45.5% LHV efficiency) would result in a per kW capital cost reduction in the cell stack of almost 20%. Due to its higher polarization slope, a similar trade-off in the case of the MCFC would give a cost reduction of only about 10%. In 1986, the SOFC performance was not an economic proposition at 0.67 V. By comparison, today’s performance is much more impressive. Reportedly, results similar to those at Westinghouse (0.65 V, 0.50 A/cm2) were obtained in late 1991 at Siemens (Erlangen, Federal Republic of Germany) on a flatconfiguration cell incorporating a metallic bipolar plate of low resistance. 57 These results are discussed in more detail in Section 27, which includes a general technology update. Elsewhere, Murata Manufacturing Co. (Kyoto, Japan)9 had shown current densities of several hundred mA/cmZ, but since no reactant utilizations were reported, it was not possible to compare the data with those of Westinghouse. Inspection of their polarization curves implied that their cells had a similar ohmic resistance to those shown by Westinghouse. 19. SOFC VS MCFC The state-of-the-art SOFC has simpler chemistry and electrochemistry, but less advantageous thermodynamics than the MCFC. It does not require a circulation of CO:! from the anode exit to the cathode. All conduction is via O= ion, so all water is formed at the anode. If pure hydrogen is available for use as the fuel, a water condenser and two heat exchangers will in principle allow 100% hydrogen utilization. This is not possible in the MCFC, which produces C@ at the anode and is not particularly suitable for use on hydrogen fuel, since it will always require a CO2 recycle system with make-up of the reactant as may be necessary. On reformate or coal gas, a separation device will be needed in the SOFC to obtain 100% fuel utilization, as in the case of the MCFC. The reversible thermodynamics of the SOFC seem to put it at a disadvantage compared with the MCFC, as do its relatively small cells. However, it is less polarized than the MCFC due to its higher operating temperature. While its materials costs may eventually fall to low levels, they are high at present, and the SOFC must therefore operate at high current densities to be economical. In practice, it is less limited by utilization considerations than simple MCFC systems. It may operate at 85% or even 90% utilization. A more important thermodynamic disadvantage of the MCFC is the fact that both 02 and CO2 are reactants in its cathode process. In effect, they compete for space. A practical MCFC system with a competitive capital cost operating at 1 atma pressure may require the addition all of the anode effluent (including product water and any water vapor remaining from reforming) into the cathode air stream. In a typical MCFC operating with system gases, with no cathode recycle for simplicity, and at utilizations of 75% for CO2 and 50% for 02, the mean cathode gas composition in the cell will only be 10.8% CO2, 9.7% 02 (Section 13). As a result, the effect of the two reactants on the reversible thermodynamic Nemst Equation is considerably increased compared with the SOFC case. In the MCFC,

Fuel cell technology

555

the mean cathode gas composition gives a 0.135 V reversible voltage loss from the standard state reversible potential of 1.014 V at 650°C, due to the teffect of the RT/4F log [p@][CO$ term. In contrast, the theoretical reversible loss in the SOFC is only 0.047 V from the standard state reversible potential of 0.909 V at 1,OOO”Cat a mean oxygen utilization of 18% in a 5.5 times stoichiometric process air flow which is also used for cooling (mean composition 18% a). This thermodynamic disadvantage of the R4CFC is compounded by a kinetic disadvantage, since reaction rates are reduced at low reactant partial pressure, hence overpotentials are increased. Finally, a low-capital-cost MCFC system will operate at lower fuel utilization than the SOFC. As a result, kinetics and thermodynamic considerations in an MTFC operating at 650°C or in an SOFC operating at 1,OOO”Cterid to compensate each other. A future SOFC may operate at somewhat lower temperatures (perhaps 800°C) to avoid the capital costs involved in high-temperature heat exchangers. However, there is no reason to believe that optimized systems will not have similar overall efficiencies to those available today. The SOFC produces better quality waste heat than the MCFC. As seen by a heat exchanger or expander, the waste heat in a future SOFC operating at 800°C will be available at about 700°C, rather than at only 550°C in an MCFC. Its waste heat can certainly be used in internal reforming, but as was stated in Section 6, this will require a careful reactor/heat exchanger design to prevent rapid cooling of the intake to the electrochemical cell by the reforming reaction, which would shut down the system. However, with careful design, internal reforming is certainly possible, and its use will be assumed in comparing both HTFC systems. Some sort of sensible heat reforming is also possible. This may result in operating the system at, say, 90% fuel utilization. The off-gas would otherwise be wasted in a non-bottoming cycle system, so it can be cornbusted in the hot cathode exit stream using a catalytic burner to provid.e all the reforming heat. A suitable heat-exchange reformer19 may be advantageous for this application. The higher temperature waste heat can be advantageously used in a more efficient steam cycle than that possible with the MCFC. However, a steam cycle cannot use temperatures above 700°C because of materials constraints. This represents a waste of part of the exergy available in the exit stream. The waste heat (hot air at 5-6 times stoichiometric, 17-20% oxygen utilization) will only really be useful if ic is made available at pressure for a turbine combustor. This requires operation of the cells under pressure, which has not so far been attempted. Pressurized operation would extend the polarization window in the SOFC. Compression to 10 atm would increase the exit potential by 0.063 V to about 0.83 V on reformate. Since the polarization curve still contains a residual amount of electrode polarization, it may permit operation at 0.67 V and 0.60 A/cmz, allowing a 33% reduction in cell capital cost. Alternatively, it may allow an increase in the fuel cell cycle efficiency from 50 to 57%. After shaft work requirements for compression, an increase in efficiency in a complete NG system, including the bottoming cycle, by 3% may be obtained. Such a system would operate in 65% (LHV) range, or perhaps slightly more. Similar considerations apply to a coal cycle. The considerations considered for the MCFC in an integrated gasifier system apply in large part to the SOFC. The main differences are the fact that it is easier to operate at a higher potential for a given gas in the MCFC than in the SOFC, but the latter has better quality water heat for use in a bottoming cycle. The MCFC is probably easier to operate pressurized, or rather MCFC stacks have been operated pressurized, wh,ereas the SOFC has not. The SOFC may have a problem of interdiffusion of components with time, but cells have operated well for very long periods. For example, cells at Brown-Boveri (Heidelberg, Germany) operated for over 30,000 hours in the 1970~.~* Westinghouse cells had been on continuous test for 3 years in 1990.s9 Compared with the MCFC, it may have minimal problems as a function of time, although this remains to be seen. As already stated, it can survive oxidation of the anode as a result of accidental over1oa.d or gas reversal, it has no management and containment problems for a liquid electrolyte, and it does not suffer from cathode dissolution and migration of nickel ions through the electrolyte. It may, however suffer from problems of component interdiffusion, which change the conduction properties of components with time and consequently reduce performance (Section 27). 20. SOFC SYSTEMS PROGRESS TO 1992 Westinghouse steadily moved forward in the 11 years from the concept of the new tubular cell design to 1991. Progress to that point has been summarized in Ref. 59. Cells with 20 cm active length (30 cm overall) had been proven individually and in bundles by 1985. A 5 kW unit with these cells operated for 500 h in 1986. New cells with 36 cm active length were successively proved to 18,000 h by 1990. By this time, similar pilot line cells had performed for 2,500 h. The Tennessee Valley Authority (TVA) tested a 400 W unit in 1986-87, which operated for 1,760 h. During 1987-88, two 3 kW units (36 cm cells) operated at the Osaka Gas Company for 3,000 and 2,600 h each, and a third unit operated at the Tokyo Gas Company.60*a1 Performance was satisfactory, although at Osaka Gas some contact problems in the nickel felt current contact between cells were noted. These cause performance degradation in stack tests, whereas the performance of individual tubes was extremely stable. 62 This problem, which is design-dependent, rather than technology-dependent, was steadily improved. Testing with a dedicated 3 kW unit operating on desulfurized pipeline NG, funded by GRI, started in 1990. It had operated for 5,500 hours by the end of that year. This unit had a built-in reformer to convert 75% of the gas, the remaining 25% being reformed on the cell anodes. No external humidification was

556

A. J. Appleby

require d for this. An external-reforming 20 kW DOE unit, which contained 50 cm cells, operated for 3,200 hours by October 1991. Cells with 77 cm length were in the laboratory in 1991, and 100 cm cells were produced at the end of that year. A packaged 25 kW test unit of compact form was delivered in late 1991 to a consortium consisting of the Kansai Electric Power Company, Tokyo Gas and the U.S. Department of Energy for testing at Rokho Island, Osaka. A similar unit went to a Tokyo Gas and Osaka Gas consortium in 1992, to be used in a cogeneration mode.63 The Westinghouse SOFC was to be developed under a 5 year DOE program. For FY 1991, this involved $64 million in Federal financing and $76 m to be provided by the developer. The objective at that time was a 100 kW cogeneration system supported by GRI, Southern California Gas and DOE to operate in 1993, to be followed by a 2 MW module in 1995. These were to use an internal reformer to eliminate the problem of chilling of the tubular cell at the entry point of the raw fuel gas. This required careful gas-flow and heat transfer design.57 Like the other fuel cells discussed, the SOFC can only produce NO2 from the system burner. In the Westinghouse design, the burner effluent consists of the combusted anode and cathode exit gases. The cathode gas is used in excess for cooling (5-6 times stoichiometric). The few measured levels have been rather low, for example 0.5 ppmv from the 3 kW Osaka unit and 1.3 ppmv from the similar Tokyo system.60*61 These correspond to 12 g&lWh and 30 g/h4Wh respectively. More recent results show approximately 0.3 ppmvs6, or approximately 7 g/MWh. These values are acceptably low. 21. SOFC COSTS: 1992 STATUS From the viewpoint of polarization performance, the SOFC is now superior to the MCFC. However, thermodynamics makes its practical polarization window very small. Even so, it is capable today of twice the power density of the MCFC at practical cell potentials and gas utilizations. The question becomes whether these power densities are indeed cost-effective. The Westinghouse structure has certainly been a technical success, but it is not without disadvantages. The active cell components originally represented about 15% of the total mass of the tubular cell or about 0.1 g/cm2 in the design supported on a calcia-stabilized zirconia tube weighing about 300 g/m (0.8 g/cm2 of active area). Fabrication costs will certainly become lower as the developers go down the learning curve, so that the relative costs of materials become correspondingly greater as a fraction of the total overall cost. Hence, cost will be a reason to remove material from the cell. The present specific power is approximately 4.0 kg/kW. This leads to an estimated cost of perhaps $2OO/kW, based on the cost of pure bulk oxides. However, estimates can vary greatly (by as much as a factor of five) &pending on the state of purity and the chemical nature of the starting materials. 12 An example is given by the cost of interconnect material (lanthanum chromite doped with a bivalent ion). In the Westinghouse system, it is deposited from the mixed metal chlorides by electrochemical vapor deposition. 6 The starting products are pure oxides, which are converted into chlorides in the deposition process. Westinghouse uses magnesium as the dopant, which is not entirely satisfactory from the viewpoint of conductivity. Strontium would be more desirable, but there is a mismatch between the chloride vapor pressures of this metal and those of the other components. Other developers (see Section 27), seeking alternative methods of manufacture to those used by Westinghouse, have opted for air-sinterable powders to reduce cost. The strontium-doped material is not readily air-sinterable, whereas calcium-doped material is, by virtue of a fugitive liquid phase.s7 However, a calcium doped powder, which sinters readily, is reported to cost $5O/kg, in spite of the inexpensive d0pant.s’ This underlines the problem of materials cost, which results from the problems of preparation of compounds with the right purity, rather than the costs of the individual components themselves. The $2OO/kW figure had to be reduced to at least $5O/kW or (better) $lO/kW, to be practical. In the Westinghouse approach, this can be effected by the complete removal of the support tube and the use of still thinner components. A three-fold reduction in thickness, still maintaining the electrolyte at 30 pm, would give a specific mass of about 0.2 kg/kW for the active components, based on 1991 performance. This would mean a materials cost of only $lO/kW. This implied that the cell stack (i.e., the series-connected structure) must be self-supporting. It also implies that current collection must be along the axis of the stack, as close as possible to perpendicular to the plane of the electrodes. The use of thinner components in a planar structure with a minimum current collection pathway would ensure that IR drop was minimized, allowing operation at higher current densities, which would further reduce cost. The incentive to develop an SOFC with low IR drop, using thin, low-cost components, was very great. This might perhaps be accomplished by a simple one-step “co-sintering” of the thin-layer components in the so-called “monolithic” concept. This is described in some detail in Ref. 6, and was being pursued by many developers, mostly now in Japan. However, maintaining the correct interfaces and preventing interference between components during sintering would require technological advances. A more conservative approach was to build up separate component layers fabricated by alternative methods. The disadvantage of this approach is likely to be increased cost. Work on the monolithic concept started at Argonne National Laboratory in 1983, and had been taken up by AlliedSignal in the U.S. and by Japanese developers. Progress had been very slow, the smallest complete systems being four-cell stacks a few cm2 in area. Other flat configurations were being examined

557

Fuel cell technology

by an increasingly larger number of developers, both in Japan and Europe. Readers are referred to the 1988 and 1990 Fuel Cell Seminar Abstracts for earlier details. More recent information is given in Section 27. Some of the more exciting concepts use metal bipolar plates made from generally unspecified alloys. Compositions of Hastelloy C, Rette 41, or Inconel600 type with approximately 15% Cr, balance Ni, with or without a few percent of iron with other components, appeared to be show some promise in earlier work. A particular problem may be hydrogen diffusion through the material from the anode to the cathode side, where it may depassivate the oxide film, causing spalling (See Ref. 6, p. 560). Developers using this approach include Siemens in Gerrnanp and Tonen Corporation (Saitama, Japan) 6s who also use a glass edge-seal, apparently with considerable success. However, it was generally considered that silicate glasses should be avoided, since this ion diffuses into the electrolyte and has a deleterious effect on ionic conductivity. Ztek Inc. (Waltham, MA) in the United States should also be cited as a company using an innovative proprietary bipolar plate which provides flexibility and stress-relief.66 A small Ztek stack in 1988 appeared to show the same performance as that of Westinghouse at the same time (0.6 V, 0.20 A/cm2 at practical gas utilization). However, the high open-circuit potential of the Ztek cell indicated that the curve was obtained under constant flow, not constant utilization, conditions as a function of current density. The Ztek cell active structure was thicker than that of Westinghouse, but used perpendicular current Icollection, giving a similar IR drop. If thin components can be used and cell structures of planar type made, the final cost of the SOFC may be very low. This will require innovative approaches and, above all, development experience. The monolithic structure, which would make a stack of limited size in a single step, may be attractive in the long term. The lower risk approaches, using a built-up stack with some metallic components, may be more costly, but stack assembly itself is unlikely to cost more than $15-3O/kW. In all of the above, a major problem is the manifolding design. This requires innovative solutions, as does built-in reforming for NG and methane in coal gas to obtain maximum system efficiency. We should certainly not disregard the possibility of the development of a lower-temperature SOFC system (operating at perhaps 8OO’C) using conductors and matched electrodes with different oxide chemistry. This will also permit ,the use of inexpensive metal containment and heat-exchangers, rather than ceramic materials. This should open up a larger polarization window with little degradation in heat quality for cogeneration, leading to greater flexibility in options and perhaps higher system efficiency (c.f. Section 27). 22. SOFC COMMERCIALIZATION

AND MARKETS. 1992

The authors of Ref. 29 (1990) estimated the SOFC markets in the United States at only 5 MW of demonstration units by the year 2000. The potential Japanese and European markets have apparently not yet been established. This reflects the concept that the SOFC is a “third-generation technology” compared with the PAFC and MCFC. As would be expected, the targeted capital costs for the commercial SOFC are expected to be lower than those for the MCFC for each sector, reflecting its perceived lower efficiency. Ref. 28 expected $6OO/kW (1995) for dispersed NG electric utility applications and $1,2OO/kW (same basis) in coal gasifier plants at HI-IV efficiency of 5560% and 45-506, respectively. The authors of Ref. 29 put the cost goals at $715/kW (dispersed electric utility, 50% HHV); $95O/kW (on-site cogeneration, 47% HHV), and $1,200 kW (all same basis) for a coal plant operating at 50% HI-IV. The SOFC may be able to achieve these cost goals as easily (or with the same difficulty) as the MCFC if its stack cost can be reduced. The SOFC requires a simpler and conceptually cheaper chemical engineering system w:ith no CO2 recycle. Pressurization will require the use of metal, rather than ceramic brick, containment. In turn, this will require either the use of costly superalloys, or alternatively a reduction in operating temperature. If pressurization can be used, the efficiency of a combined cycle SOFC integrated with a coal gasifier should be at least equal to that potentially available with the MCFC, due to, the systems trade-off in the use of its higher quality waste heat, even though the operating temperature of the SOFC is reduced to 8OO’C.

23. 1992-1995 CONFERENCE UPDATE Two major fuel cell meetings were held in 1992, first, the International Fuel Cell Conference (IFCC, Makuhari Messe, Japan, February 3-6). followed by the 1992 Fuel Cell Seminar (Tucson, AZ, November 29December 2). A number of papers related to recent work on fuel cells for stationary applications were presented at the Spring and Fall Meetings of the Electrochemical Society in the United States, at the World Hydrogen Energy Conference in Paris in June, at the International Society for Electrochemistry Meeting, Cordoba, Argentina, in September, and at a number of smaller meetings in 1992. Engineering, commercialization, marketing, and economics of the stationary PAFC are reviewed here. In other PAFC work qorted in the 1990-1994 Proceedings of the Fuel Cell Seminar and in the 1992 IFCC proceedings, improved materials, catalysis, corrosion, subscale stacks, and heat transfer were discussed. There were

eight papers from Italy, eleven from Japan, four from Korea, two papers each from Germany, and the United States, and one each from the United Kingdom, the Netherlands, China, and Brazil. These papers are not reviewed. Two Symposium Volumes of the Electrochemical Society containing papers presented at the 1993 Spring Meeting in Honolulu were published. The first 1993 Symposium Volume, entitled Carbonate Fuel

558

A. J. Appleby

Cell Technology, contained 37 papers. Of these, 15 were from Japan, 9 covering hardware design and testing, the remainder being R&D contributions covering materials, electrolyte composition effects, and electrochemistry. European groups provided 10 papers, on materials, electrochemistry, and mathematical modeling of cathode performance. There were 10 papers from the United States, including two papers on hardware testing and endurance, two on c.ontaminants in coal-gas streams, one program overview, one overview of R&D requirements, one review of electrochemistry, and three papers on materials R&D. There were also two joint U.S.-Japanese papers on kinetics, materials, and melt properties. The second Symposium Volume, Solid Oxide Fuel Cell Technology, updated the earlier Electrochemical Society Proceedings Volume on the same topic published in 1989 (the First International Symposium on Solid Oxide Fuel Cells, held in Hollywood, FL). To these should be added the Proceedings of the International Energy Agency SOFC Workshops of 1990 (in Hertenstein, Switzerland) and in 1992 (in Lausanne, Switzerland), the Proceedings of the Second International Symposium on Solid Oxide Fuel Cells, Athens, Greece, 1991, and the Proceedings of the First European Solid Oxide Fuel Cell Forum, held in Lucerne, Switzerland in October 1994. The Third International Symposium on Solid Oxide Fuel Cells was held in July 1995 in Yokohama, Japan. The proceedings of these meetings are not reviewed in any detail here, since they simply amplify the now very broad and highly specialized scope of the SOFC materials area. Interested readers are referred to the original publications. To indicate the scope of this new R8zD area, the 1993 Solid Oxide Fuel Cell Technology contains 104 papers, of which 25 were from North America, 36 from Japan, 41 from Europe, with one from India, and one from Australia. The majority of papers (65) dealt with materials research topics, and 14 dealt with system modeling. There were 4 development overviews (in the United States, Japan, Europe, and Australia), and 21 papers on cell and system fabrication and testing. Of the latter, 12 were from Japan, 5 from Europe, and 4 from the United States. A second European Solid Oxide Fuel Cell Forum will take place in May 1996 in Oslo, Norway. A useful policy review paper was published by Arthur D. Little, Inc. (Cambridge, MA) for the World Fuel Cell Council (Frankfurt-am-Main) in September 1993. Q The Third Grove Symposium was held from September 28 to October 1, 1993 at Imperial College in London. This allowed some updating of fuel cell progress. The relevant papers from this meeting were published in a special edition of the Journal of Power Sources (Vol. 49) in April 1994. The fourth Grove Symposium (September 1995) is beyond the y9;r of this review. A second International Fuel Cell Conference will be held in Kobe, Japan in February The following sections attempt to summarize prognostics and progress up to early- to mid-1995. The cut-off date varies with the subject and with the availability of information. While coverage of the PAFC and the MCFC is reasonably complete, this review gives only a partial account of work on the SOFC, particularly on SOFC materials, for the reasons discussed above. While coverage of work at SOFC developers up to the end of 1994 is reasonably complete, the specialized literature (e.g., in materials science or in solid state ionics) which may concern or be related to the SOFC could not be covered in detail. Similarly, it does not extensively review the specialized electrochemical literature pertaining to certain aspects of stationary fuel cell technology. However, it does cover available information on what is believed to be all ongoing development work in the area. obtained from published literature, from public presentations, and in some cased from anecdotal information. 24. 1992-1995 PROGRAMS,

POLICY, AND SPENDING

United States Departments of Energy and Defense: Funding in the United States by the Department of Energy for FY 1992 was divided as follows: PAFC, $8.853 million; MCFC, $18.42 million; and SOFC, $14.17 million, with $1.444 million for Advanced Research, a total of $42.89 million ($45.6 million 1995). For FY 1993, the amounts appropriated for the same four categories were $3.909 million; $28.623 million; $16.671 million; and $1.564 million respectively, a total of $50.772 million ($52.7 million 1995). In addition, the FY 1993 budget contained a provision for the Army, Navy/Marine Corps, and Air Force to share equally in the installation and demonstration of NG fuel cell units in production in the United States for a total cost of $18 million ($18.7 million 1995). There was also $11.48 million ($11.9 million 1995) to provide a demonstration of high-temperature fuel cell technologies operating on logistic (diesel) fuels. This was used to fund (via NASA) a Westinghouse SOFC demonstration to be performed at Southern California Edison Company, and an ERC stack demonstration. It was determined that the $18 million procurement would be used to demonstrate 200 kW PC25 systems at military installations, especially in areas where air quality improvements were needed. After the change of administration in 1993, the White House proposed no increase in the FY 1993 fuel cell budget by reallocation of funds. However, the DOE allocation for the near-commercial PAFC was eliminated, $91,000 was deleted from the Advanced Research budget, leaving $1.473 million, and $2.0 million was added to each of the MCFC and SOFC budgets, giving $30.623 million ($31.8 million 1995), and $18.671 million ($19.4 million 1995) respectively. The DOE appropriation for stationary fuel cells for FY 1994 was MCFC, $31.498 million, SOFC, $15.786 million, with $1.385 million for Advanced Research, giving a total of $48.669 million ($49.7 million 1995). The Defense appropriation for FY 1994 included $6.25 million in procurement funds, together with $2.0 in operating funds for each service to extend the FY 1993 demonstration program. In

Fuel cell technology

559

addition, $1.25 million was appropriated for the Advanced Research Projects Agency (ARPA) to examine methods of reducing the production costs (on a cost-share basis) of PAFCs operating on pipeline gas. A total of $7.5 million of FY 1995 ARPA funds was transferred to DOE Morgantown, WV Energy Technology Center (METC) for MCFC product development. Of this, $5.5 million was spent at ERC, and MC-Power received $2.0 million to cover costs of transfer of its proposed 250 kW demonstrator from the Kaiser Permanente Hospital site in San Diego to Miramar Naval Air Station. For FY 1995, the DOE appropriation was MCFC, $29.134 million, SOFC, 17,629 million, with $1.415 million for Advanced Research (total $48.178 million). The Defense appropriation for FY 1995 included an $18 million “buydown” for IFC PC25 customers under the Climate Action Plan to reduce greenhouse gas emissions. This would represent a subsidy of $l,OOO/kW to those new customers paying $3,OOO/kW for on-site units, with a preference for units at DOD sites. ARPA also transferred $4.4 million to METC for ERC IIR-DIR MCFC product development, and $7 million was used for the development of a logistic-fuel PA:FC at IFC using a partial-oxidation reactor. The proposed N 1996 appropriation included approximately $38 million for the MCFC, $112million for the SOFC, and approximately $1.5 million for Advanced Research, together with ARPA appropriations of $7 million for MCFC development, and $12 million for a further PAFC “buydown.” If the ARPA contributions are included, funding (in millions of 1995 dollars for FY 1993,1994, 1995, with estimate for 1996) for the MCFC was $34.3, $39.7, $34.2, and $44.3, and that for the SOFC was $22.5, $16.1, $18.0, and $12.3. To these should be added the GRI and EPRI budgets for HTFCs, which were for example (for calendar years 1995 and 1996) $3.75 million and $4.5 million (GRI) and 167million and $7 million (EPRI). The U.S. programs were influenced by the fact that the PAFC was reaching commercialization status, and required less support compared with the more advanced technologies. The Department of Energy aimed at maintaining U.S. technological competitiveness, and continued to aim to develop coal-f:as-fueled baseload plants, and systems with NG back-up fuel. The Department was actively cooperating with GRI on the development of on-site systems with NG fuel for cogeneration, and with EPRI on environmentally benign electric utility fuel cell power plants operating on coal gas, NG, and liquid fuels.‘ja The Department of Energy program to improve pressurized PAFC technology terminated in 1992 with demonstration of current densities increased by 20% to 0.24 A/cm2 at rated cell voltage.69?70 Demonstrations were up to short stack level, and included components of the proprietary “Configuration B” type indicated (although not described) in earlier work. a Results obtained showed a 40 mV improvement at 0.22 A/cm2 over average results reported in 1985-1986, with a lower IR drop, allowing operation at up to 0.37 A/cm2 at 0.73 V in a short stack. Data in subscale cells were about 50 mV higher. Part of this performance increase was due to the use of improved alloy catalysts in a higher equivalent loading.70 This followed work reported in 1986 at a 0.9 mg/cm2 cathode loading which allowed a performance of 0.73 V at double the standard operating current density, i.e., at 0.43 A/cm2 after 1,000 operating hours.8 The logarithmic decay rates made it clear that these cells would give 40,000 hours lifetime within performance specifications. Even so, major issues for the PAFC in 1992 still included stack fabrication costs, the verification of a 40,000 hour lifetime, and verification of long-term systems operation. All three U.S. MCFC developers were funded in FY 1992, however, but funding for IFC terminated during the year, according to plan. Two MCFC product development contracts were planned for systems in the 0.5 MW to 1 MW class. Prototype manufacturing facilities were in operation, and commercialization plans were being implemented. The most mature SOFC technology, the Westinghouse tubular system, was making steady progress. In the systems area, it was recognized that cold clean-up of coal gas, a.nd the use of oxygen-rich gasifiers were not the best system options. The first required many heat exchangers with high capital cost, and both involved substantial loss of system efficiency. In the latter case, loss of efficiency was due to the effect of the heating value of the hydrogen- and CO-rich , rather than methanerich, product gas on fuel cell performance. This has been discussed in Section 17.68 Electric Ufilifies: EPRI studies have shown that generation or electrical storage equipment which is connected electronically to the grid can give significant savings in cost-of-service. For example, the extensively tested 20 MWh, 10 MW pilot lead-acid battery storage facility in Chino, CA, has been proven to effectively eliminate a requirement for 200 MW of additional capacity. Fuel cells in the 500 kW to 5 MW range are ideal for this application. In urban California applications, the cost of service to a utility might be in the range 7.0-12.5 cC/kWh (1995). whereas fuel cell benefits can be in the 1.3-8.9 #/kWh (1995) range. The financial benefits of fuel cells may therefore outweigh their direct generating costs. The trend in the future for electric utilities is likely to be specialization, with companies becoming long-distance electricity transportation companies (TRANSCOs), generating companies (GENCOs), and distribution companies (DISCOS). The dispersed fuel cell would interface most effectively with the latter. The question most likely to arise was whether a DISCO desired to become part of the business of power generation, or whether a dispersed fuel cell would be owned by some other entity (e.g., an NG distribution company). A capital cost of ca. $1,65O/lcW (1995) was again considered low enough in 1992 to give large market opportunities for fuel cell distributed power (c.f. Ref. 16). 71 It was pointed out that there will be competition to utility fuel cells. By mid-1992, the Public Utility Regulatory Commission under PURPA had granted licenses to 100 GW of non-utility capacity, i.e., 15% of the total. Thus, 50% of new capacity was then being developed by non-utility generators. The 1990 Clean Air Act was intended to force

560

A. J. Appleby

reductions in SO2 and NO2, which was likely to encourage the adoption of fuel cells. The 1988 NOM0 aimed at systems greater than 1 MW, but smaller dispersed units should certainly be economic. This was illustrated by the benefits or avoided costs for a dispersed 400 kW photovoltaic array, which were estimated in 1990 to be equal to $45O/kW (1995). assuming an environmental credit of 10%. Some of the advantages of fuel cells were the production of the highest-quality ac (or dc) power, load-following capability, and excellent peak-shaving capability. Fuel cells also showed the highest system security benefits. In addition, short-term financing could be used instead of the long-term bonds necessary for conventional large generating equipment. Fuel cells would be particularly advantageous for the 2,200 public authorities who purchased 80% of their power, and relied on 180 other companies for transmission access. Fuel cells were ideal for hydrogen and renewables. It was even suggested that the United States should rely as little as possible on grid-connected central power. 72 One advantage of fuel cells which was not discussed is the electronic buffer represented by the inverter, which has been shown to stabilize the system in the case of battery load-leveling units. Cost-benefit ratios of 2 MW fuel cells in different locations had been evaluated, and showed attractive results.73 Finally, it was pointed out that the marketplace, not government agencies, determines commercialization. Early buyers must be put in the position of strategic advantage, not financial disadvantage, and no single sector (end-use, manufacturing, or government) could take all the financial risk involved in the initial penetration of a new technology. 74 How this is to be most effectively planned remains to be seen. It is suggested that organizations such as the Fuel Cell Commercialization Group,4s which represents ERc’s MCFC technology, are the best media to help commercialization.74 National Energy Strategy: Fuel cells should be an effective way of reaching the goals laid down in the National Energy Strategy (NES) announced by President Bush in February 1991, which looks towards a more efficient, less vulnerable and more sustainable energy future. The NAS predicts that by 2010, up to 200 GW of additional electrical capacity will be required in the United States. Between 1992 and 2030, the total generating capacity is expected to grow from 685 GW to 1.295 GW, i.e., at an average growth rate of 1.7% per year. This allows for both expected economic growth of 3%. and expected improvements in enduse efficiency. The 1991 forecast of the North American Electric Reliability Council and the Gas Research Institute Baseline Forecast estimates total required capacity additions to be 89.3 GW by 2000. Of these, 71.6 GW will be electric utility additions, with 17.7 GW of non-electric utility cogeneration. Of the electric utility additions, 15.9 GW were in construction; with 55.7 MW not yet identified. In contrast, total demand growth during the same period is expected to be 105.6 GW, which exceeds projected capacity increase by 16.3 GW. During the interval from 2ooO to 2010, required capacity additions are expected to be 112 GW. In this decade, up to 72 GW of additional capacity may be required using equipment with a short construction lead-time. If its cost-performance and reliability characteristics were perceived as satisfactory, the dispersed fuel cell had an excellent chance of filling a significant part of this capacity. Its opportunity during the following decade should be even more.promising. The driving forces favoring the fuel cell would be its efficiency, its cost credits as a dispersible non-polluting technology which interfaces electronically with the grid and allows cogeneration, and its elimination of new above-ground or underground right-of-way corridors in large cities. Policy I&lications of Global Warming: The National Academy of Sciences’ report Policy implications of Global Warming, issued in April 1991, recognized the uncertainties surrounding the phenomenon of climate charge due to the accumulation of “greenhouse gases” such as CO2 from fossil fuels and destruction of tropical forests, methane, nitrous oxide, chlorofluorocarbons, tropospheric ozone and other man-made pollutants. Nevertheless, the report advocated action to slow accumulation of these gases. Higher efficiency power generating systems were acknowledged as one proven way to reduce these emissions. Higher efficiency systems include fuel cells operating on fuels with lower carbon contents, for example NG, especially in cogeneration applications. 68 At the United Nations Conference on Environment and Development (the so-called “Earth Summit”) in Rio de Janeiro in June 1992, 153 countries, including the United States, signed the Global Climate Change Treaty, which would require individual nations to reduce their C@ emissions to 1990 levels by the year 2000. The Treaty was to become binding after ratification by 50 signatory nations. Six months after it became binding, each nation was required to submit a CO;! Emissions Reduction Plan to the United Nations. By August 1993, the treaty had been ratified by 31 nations, the United States being one of the first to do so, in spite of the resistance of the Bush Administration to either the inclusion of timetables for emissions reduction, or the stronger language favored by certain European Commission (EC) nations, which would have requited a further 20% reduction early in the next century. The majority view in 1993 was that this would probably require the imposition of carbon taxes. However, the EC could not agree on this point, the major holdout being the United Kingdom, who insisted on stabilizing emissions at 1992 levels by 2000. As a result, none of the EEC nations had ratified the Treaty by August, 1993. The subsequent history of the stronger language and the carbon tax is given in subsection Europe, below. National Energy Policy Act: The NE8 became the National Energy Policy Act of 1992, which was signed by President Bush on October 24 as Public Law 102-1018. It concentrated on energy efficiency, requiring new efficiency standards for lights, electric motors, and commercial heating and cooling systems. It ended certain utility monopolies by permitting independent producers to make wholesale electricity, encouraged utilities to invest in improvements in energy efficiency, and contained incentives for the use of

Fuel cell technology

561

alternatives to oil. It encouraged improved clean coal technologies and coal utilization, encouraged enhanced NG supply, and removed restrictions on the purchase of Canadian gas. A tax reduction equal to $1.1 billion over five years was offered to independent oil and gas producers. All of the above should aid the development and application of fuel cells. Title XVI dealt with the subject of Global Climate Change. This required the Secretary for Energy to submit a report to the President by October 24.1994 on the social and economic implications of stabilizing greenhouse gases in the United States by 2005, including the feasibility of a 20% reduction from 1988 levels. The report was to include an assessment of the recommendations made in Chapter 9 of Policy Implications of Global Warming, an assessment of the U.S. effort to reduce emissions compared with those in other countries, which was required by the Global Climate Change Treaty. The Act required that the National Energy Policy Plans imposed b;Y the Department of Energy Organization Act, submitted to the Congress by the President on or after February 1, 1993 shou1.d contain a Least-Cost Energy Strategy. This was to take into account the implications of stabilizing and eventually reducing greenhouse gas emissions, of increasing the efficiency of the. nation’s total energy use by 30% by the year 2010 compared with 1988 levels, an increase in renewable energy use by 75% over 1988 levels by 2005, and a reduction in oil consumption from about 40% of total energy use to 35% in the same year. The Strategy was to include an inventory of all energy and efficiency resources, including renewables and nuclear power, with the life-cycle costs of all energy production facilities, forecasts of short-and long-term energy needs according to “low or “high” economic growth assumptions, and identification of relevant federal enforcing authorities. Emphasis should be on lifetime energy costs, and economic and social consequences. Standards for improved energy efficiency were required, as well as new technologies with lower greenhouse gas emissions, including the use of renewables, electricity generation using so-called “Clean Coal” technologies, and advanced nuclear fission and fusion. The Department of Energy was to establish the post of a Director of Climate Protection within six months of enactment (i.e., by April 24, 1993). The Secretary for Energy was also to submit a report to Congress by the same date on alternative means of controlling greenhouse gas emissions, which would include caps on emissions, trading programs, new Federal standards, and incentive programs. Guidelines for a national inventory of greenhouse gas emissions would be required at the same time, and an Innovative Environmental Technology Transfer Program was to be established to aid other countries, with a plan for projects required within 150 days of enactment (i.e., by March 23, 1993). These milestones were not met by the officials (of the new administration. A Global Climate Change Response Fund was also to be created for foreign aid for Global Warming. The Department of Energy’s Fuel Cell Systems Program Plan for FY 1993 emphasized the high energy efficiency of the MCFC and SOFC, which it assessed at 60% and 55% for MCFC electric utility and on-site NG plants. The corresponding values of on-site plants were given as 55% and 50%. It targeted the corresponding capital costs for installed units (1990 dollars) at $6OO/kW, and $8oO/kW for electric utility plants, and $8OO/kW and $l,OOO/kW for electric utility plants (respectively $685, $910, $910, and $1,140 in 1995 dollars). The target capital costs of 50% efficient coal-fueled plants were given as $1,2OO/lcW for the MCFC, and $l,OOO/kW for the SOFC ($1,370 and $1,140 in 1995 dollars). All efficiencies are based on the HHV of the fuel. It remained to be seen whether electric utility plants could be more efficient and also cheaper than simpler, less efficient on-site plants, although the capital costs of the latter would include equipment for waste heat recovery.

Introduction: In 1991-92, European energy politics were dominated by two factors. The :iirst was the “green” movement, which was aimed towards cleaner air and a substantial reduction in greenhouse gas emissions, to 20% below those of the late 1980s by the year 2005. This could be at least partially achieved by imposing carbon taxes (see following). This also reflected the general decline of coal, and the rise of NG, whose carbon emissions are about 41% less than those of coal on an LHV unit energy ‘basis (about 44% less on an I-II-IV basis). Increasing efficiency of end use and the “tightness” of European electricity grids should result in broader application of combined heat and power (CHP), i.e., cogeneration, schemes, and improved transportation energy efficiency. Both of these were expected to increasingly use fuel cells. The second factor was the privatization of energy production and conversion, which drove a desire for greater cost-effectiveness. Coal for power production was supplemented in Europe by imported oil after World War II, then by nuclear power. After the 1974 OPEC incidents, France emphasized the nuclear heat as the major form of central power generation. After referendums since Chernobyl, nuclear power was being phased out in Italy, Sweden and the Netherlands, and slowed down in Germany and in the United Kingdom. Increasing availability of natural gas, first from the Netherlands, the North Sea, and North Africa (in Italy), then from Russia and the Southern Republics, and increasingly severe emissions regulations (acid rain) have made combined cycle plants (including those with cogeneration) attractive. The Netherlands had 4 GW of lowemission cogeneration (combined heat and power, CHP, used, e.g., for greenhouse heating) capacity in the 25 MW to 400 MW range in 1994. The market was about 200 MW per year. The muffled noise levels of the latest units were very low (45 dB at 50 meters). The approximate cost of reducing emissions to legal values in older units was ca. 0.25 $ (U.S.)/kWh. The capital cost of GTCC CHP units (average 50% LHV

A. J. Appleby electrical) was $770-870/kWh (1995). Such equipment was at least in the 25 MW class, whereas the pressurized IFC PAFC was planned as a 11 MW unit. However, a large (100-150 MW) gas turbine system was a major capital investment, which might be deferred if smaller FC systems were available at attractive costs. Otherwise, in a Netherlands context, it would apparently be impossible for a 47% LHV efficiency pressurized PAFC to compete on a cost-of-electricity basis. However, the grids in different European countries differed in degree of integration. A technology which might not be economically appropriate in the Netherlands, might find economic applications in Eastern Germany, Southern Britain, or in parts of Italy. How fuel cells might replace or complement sub-l MW CHP capacity in the United Kingdom has been discussed.75 Gas-fired capacity in the Netherlands and the requirements for fuel cell systems to compete were reviewed in 199 1.76 Whether the on-site PAFC can compete will depend on its capital cost, and on the evolution of small gas engines for CHP applications. The typical CHP utilization requirement (e.g., in Germany) was over 4,000-4,500 hours per year. If renewable fuel (e.g., landfill gas or biogas) was used, the electricity produced had a “guaranteed buy-back” of 16.8 Pf&Wh (10.5 e U.S.) in 1994. In mid-1994, the Netherlands and Germany had gas engine CHP units from 100 kW to >I MW. The majority (85-90%) of Germany’s total CHP capacity of 700 MW was in the several hundred kW range. About 100 MW of small diesel capacity existed in Southern England. Small-scale CHP may therefore represent a large market. Compared with conventional equipment, it offered a 25-40% reduction in fuel costs, and a 99% reduction in emissions. In the distributed CHP mode, it represented an advantageous way to reduce carbon dioxide greenhouse gas emissions, which were expected to be lowered by 25% in the residential sector by 2010. In addition, the PAFC could be used relatively near-term with landfill gas and biogas as fuel, in such applications as wastewater treatment. In a simplified and less capital-intensive form offering somewhat higher efficiency, the PAFC could also be used where excess industrial hydrogen was available, e.g., along the German and NetherlandsBelgian (Rotterdam to South Belgium) hydrogen pipeline systems, and in Italy, where electricity from chemical by-products (e.g., hydrogen) could be sold at premium prices. For the chlor-alkali industry, companies expected to lease, rather than buy, FC generating equipment, following an industry tradition. In other applications, gas companies might use their own equipment to sell electricity (and cogenerated heat) to users, e.g., hospitals, who do not want the responsibility of owning and operating their own equipment. This was also the attitude taken by ENRON and ONSI in the United States (see Section 25). Hospitals and many other major users of electronic equipment require high-quality uninterruptible power, and may be prepared to pay a premium price for it. This power, separate from the house-keeping load, may be provided by the dispersed PAFC rather than by rechargeable batteries. As in the United States, concerns about EMF effects (as well as esthetics) mean that new transmission,capacity may be limited, which will favor dispersed generation. Finally, the pollution concerns in historic city centers and in Eastern Europe, together with resource pressures, favored energy efficiency and cogeneration, preferably via FCs if their capital costs were acceptable. European fuel resources are limited. For example, 80% of oil was imported, and 17% of Germany’s energy requirements depended on natural gas, yet the North Sea reserves were rapidly diminishing (e.g., to 7 years supply in the British zone in 1994). Advantages of the PC25 (or similar equipment) for small-scale European dispersed power applications would be its ultra-low chemical and unmuffled noise emissions, together with its unattended, remotedispatch operation and very long time to forced (and planned) outage. According to 1988-1992 North American Electric Reliability Council Generating Unit Statistics for 1988-92, average run times before shutdown of fossil, geothermal, and nuclear plants were 600, 500, and 1,400 hours, respectively. Similarly, according to GRI figures,* the average mean time between forced outages for reciprocating machines in the 60 kW, 80-800 kW, and >800 kW classes were approximately 500, 250, and 350 hours respectively. For combustion turbines in the l-5 MW, 5-25 MW, and >25 MW classes they were approximately 150, 675, and 1,000 hours. In contrast, the mean time to shut-down (planned or forced outage time) for operational PC25As was 1,500 hours (in 1993), with 2,700 hours then expected for the mature PC25A. A 1995 update on the performance of PC23A is given in Section 25. Inevitably, the major issue would be the cost of power. Small diesels had electical efficiencies of 3639%. compared with about 40% for the PC25. Their capital costs (in 1994 DM/kWe) were about 3,OOO/kWe ($2,05O/kWe, 1995) in the 40-50 kWe class, which was intended for the residential market but which was not widely installed. In the 200-500 kWe and >l MWe classes, the installed costs were about 2,OOO/kWe ($1,37O/kWe, 1995), and 1,500-2,OOO/kWe ($1,025-1,37O/kWe, 1995). respectively. The operational lifetimes of these units were 40,000 hours, similar to that initially expected for the PAFC stacks (although not for the BOP, which had an expected 30 year lifetime). The very smallest CHP units (in the 67 kWe class, intended for domestic applications) cost 3,000-4,000 DM/kWe ($2,050-2,730/kWe, 1995). In many applications, $2,5OO/kWe (1995) for a PAFC system would be considered an acceptable selling price. To cover the broadest market, capital costs should i&ally be in the $1 ,OOO-1,5OO/kWe range. To compete with diesels in Sweden, the capital cost should be $1,550-1,65O/kWe (1995)” The on-site PAFC would compete directly with small diesels, which require expensive sound muffling. It would have many advantages, including much lower noise and pollution levels. However, noise must still be reduced for use in residential areas, particularly in Germany, where the upper noise limit at night is 35 dBA. This would require silencing of the cooling system for FC units with air-dump cooling. Regulations on system use also * Reliability of Natural Gas Cogeneration Systems,January i990-September 1992.

Fuel cell technology

563

require major revision, since they are left over from those for conventional equipment (c.f., the New York 4.5 MW unit treated as a “refinery”). An example was the requirement for expert safety reports for each German site (even when FC units are moved) and the requirement for analysis of the product water.fll As is the case in Japan, care should be taken in comparing costs in the different European Union (EU) countries with those in the United States. The ratios between their U.S. dollar PPP and trading exchange rate BT~all greater than unity, and in some cases their total hourly costs for manufacturing are even higher than those in Japan when.compared at the trading exchange rate. For example, costs in Germany, Switzerland, Belgium, Austria, the Netherlands, and Sweden were 57.2%,48.3%, 33.5%. 25.8% 24.7%, and 10.8% higher than those in the United States in September 1995, whereas those in Japan were 28.7% higher.* The potential European fuel cell market was reviewed in late 1991.32 By 1994, it was expected that a total of at least 5 MW would be installed, including a 0.4 MW Westinghouse air-cooled, hydrogen-fueled PAFC in Norway, a 2 MW MCFC, the 1 MW PAFC in Milan, and on-site units. The total was only 3.2 MW at the end of 1994, and consisted of the planned on-site units and the Milan 1.2 MW PAFC demonstrator (see below). Carbon Taxes: In 1993, the United Kingdom insisted that both a 20% reduction of the 1990 level of CO2 emissions by 2005 and the imposition of a carbon tax were economically unrealistic. Hence, the EC shelved these issues. The EC countries then ratified the Global Climate Change Treaty, which finally became effective in 1994. In January 1995, the EC again failed to agree on the common carbon mx, but the United Nations Conference Trade and Development suggested trading of CO2 permits instead, analogous to that of SO2 permits under the 1990 U.S. Clean Air Act. No issues were settled at the first Conference of the Parties to the United Nations Framework Convention on Climate Change (COP-l), held im Berlin in April 1995, apart from the conclusion that attaining 1990 CO2 emissions levels by 2000 would be impossible. The first round of talks in a two-year program to agree on a timetable by 1997 started in Geneva on August 21, 1995. The results were inconclusive, although the Alliance for Small Island States (38 small islands nations, including Fiji and Madagascar, who may be subject to catastrophic flooding in a greenhouse world) still insisted on a 20% reduction from 1990 levels by 2005. By the late summer of 1995, the EC had determined that a carbon tax would be optional for European Union (EU) member countries. An example of such a tax was in Norway (not an EU member). The tax there was instituted in 1991, and was equal to about $3.5O/GJ or $3.70/MMBTU for NG (HHV) in 1995. This exceeded the sales value of Norwegian gas. It was about 85% greater than the spot market price of NG in the United States, where an imposition on this level would be politically unacceptable. Based on the tax per unit of CR liberated, this is equivalent to $6.3O/GJ or $6.6O/MMBTU for coal, or more than four times the minemouth price in the United States. Denmark (an EU member) proposes to use a carbon tax, which would be phased in from 1996, and become fully effective in 2000. Three levels of tax were recommended, $4.47 per metric ton of C@ for energy-intensive industry, $16 for emissions from applications with moderate intensity, and $107 for general heating. For NG, these proposed taxes represent 22 $, 79 $, and $5.30 per GJ (23 U, 83 $, and $5.55 per MMBTU) respectively. Sweden (now an EU member) also has a carbon tax on all users, and considers it to be a “moral duty,” which gives its industry a competitive edge by “encouraging energy-saving innovation ahead of foreign competition.” This view is of course not universally shared.79 Competing power generation technologies have been examined from a European viewpoint in terms of the cost of lower CO;! emissions. Netherlands studies have concluded that the marginal cost will be $65-130 per metric ton of CO2 for a required reduction of 40%, about $100-200 per metric ton for a reduction of 60%, rising to.$130-290 per metric ton for 70% reduction. These will clearly favor fuel cells and renewab1es.w Funding: It was reported that total European fuel cell spending in 1991 had reached a rate of 55 million ECUs per year (then about $66 million, about $73 million in 1995 dollars) for terrestrial puirposes, the majority of which was for stationary applications. An additional $13.8 million (1995) was spent on the development of space alkaline fuel cells (AFCs) by the European Space Agency (ESA). In comparison, U.S. and Japanese spending (government and industry) were each estimated to be about $4;! million in 1991-92, assuming the then yen-to-dollar trading exchange rate. *l This apparently indicated a European desire to catch up, since most programs were quite recent, with starting dates in 1988-90, with the exception of Italy (under ENEA sponsorship), and the Netherlands (under NOVEM sponsorship), whose start dates were in 1986. The amounts included sums spent directly by the Commission of the European Ccommunities (CEC, now the European Commission, EC), which always required at least a 50% cost share by industrial recipients, although the EC did fund R&D at the 100% level in Universities. In addition, individual countries had substantial programs, and also generally required major cost-sharing when funding industry. Joint multi-level programs existed between industries and other organizations in different countries, with national governments and the EC sharing part of the costs. In 1992, the EC was spending or proposing to spend about 8 million ECUs per year on MCFC and SOFC development. The Netherlands was spending about 6 million ECUs on the MCFC, Italy 10 million ECUs, mostly on the PAFC, with some -work on the MCFC and proton exchange membrane (PEM) system for small applications. Germany was spending 25 million ECUs, mostly on the SOFC, with some work on the AFC for smaller systems using hydrogen fuel. * The New York Times, October 15,1995.

564

A. J. Appleby

Spain was spending 3 million ECUs on MCFC R&D, Denmark 1 million on the MCFC and SOFC, Norway 0.7 million and Switzerland 1.5 million, both on the SOFC.81 Programs had started in Sweden in 199 1 (MCFC R&D) and in the United Kingdom. In general, European developers felt that they were behind in PAFC stacks, but not in systems. The companies developing the MCFC, i.e., Ansaldo srl (Genoa, Italy), Deutsche Aerospace Airbus (DASA, part of Daimler-Benz AG), Brandstofcell-Nederlands (BCN), and Hidroelectrica-Spain, felt that they could compete by working with U.S. and Japanese developers. Work on more advanced systems included that on the PEMFC (by de Nora and Johnson-Matthey, by Siemens under license from General Electric, and by Vickers in the United Kingdom working with Ballard in Canada) and on the SOFC (by Domier, Siemens, Sultzer Brothers, TNO, and Danish and Norwegian associations). The European developers of the more advanced systems considered that there was room for them to compete world-wide. A 1994 repor@ lists European developers in detail, and clarifies some of the complexities of EC programs funded through the Framework Programs of the Directorate General XII (DG XII) for Science, Research, and Development. These Framework Programs for Technological Development and Research give support over five-year periods, the third of which was completed in 1994. Fuel Cell R&D is part of much larger activity on NonNuclear Energy and the Rational Use of Energy. From 1985 to 1992, total EC program expenditures for FC R&D (MCFC and SOFC, with some AFC support) were estimated at $10 million (current U.S. dollars). This was followed by the developer-led JOULE program for MCFC and SOFC development from 1989 to 1992, with some university research activity on direct methanol systems. The total expenditure (EC plus industry) for this effort was $30 million in current dollars. From 1992 to 1995, this has been continued as the $30 million (total) JOULE-II program, with a further $16 million (total) continuation (JOULE-II top-up) from 1994 to 1997. A further DG XII activity (from 1985 to 1997) is the BRITEEURAM program for Industrial and Materials Technologies applied to FCs. This had spent approximately $16 million (total) since 1985. Finally, the Energy Directorate (DG XVII) offered an energy demonstration program called THERMIE, which had spent a total of $14 million along with industry on FC demonstration activity from the late 1980s to 1992. 82 Similarly, for 1992-95, total EC-initiated funding was estimated at 32 million ECUs, of which 23 million were for 22 projects in the JOULE programs, 7 million ECUs were for five BRITE program manufacturing activities, and 2 million ECUs were for three THERMIE demonstration programs.83 These sums approximately correspond to those given in Ref. 81, assuming a 1994 trading exchange rate of 1.0 ECU = $1.25 (the September 1995 rate was $1.29).

Introduction: The Japanese emphasis on environmental protection and energy conservation was similar to that in the United States, with more emphasis on renewable energy, and less on coal. Under MITI’s Urban Energy Centers Project, which started in 1991.5 MW PAFC units would be developed, with 1 MW of on-site units for installation in urban buildings. Regulations were being relaxed concerning the sale of electricity from new small power sources, to facilitate their introduction. Starting in April 1992, Japanese utilities could purchase electricity from such plants, with some restrictions and conditions. MlTI had also proposed tax incentives and low interest loans, from 1990 and 1991 respectively, to encourage the introduction of fuel cells. Costs were expected to be reduced from Y9OO,OOO/kW($7,5OO/kW in July 1992 on $8,57O/kW in July 1993 at conventional trading exchange rates) to USOO,OOO/kW($4,17O/kW in July 1992 or $4,76O/kW in July 1993) by 1996, with a further reduction by a factor of two or more for commercial units by the year 2000. In September 1995 dollars at the then trading exchange rates, these represented $9,9OO/kW (in 1991) and $5,5OO/kW (in 1996). At the PPP rates, they would be $6,6OO/kW and $3,65O/kW (1995 dollars). These investment costs were expected to be reduced by a factor of two by the year 2000. At the 1993 Grove Fuel Cell symposium in London, Ryoji Anahara, then Executive Chief Engineer and director of Fuji Electric’s fuel cell development program, and now Secretary-General of the Japanese Fuel Cell Development Information Center (Chiyoda-ku, Tokyo) presented an overview of PAFC development in Japan. The 1 MW Chubu unit had operated for 1,018 hours and the 1 MW Kansai unit 2,045 hours during 1987 and 1988. However, the 200 kW 1989-technology Mitsubishi Electric unit at the Plaza Hotel operated for 13,038 hours, and the 200 kW Fuji Electric methanol unit on Okinawa Island operated for 8,449 hours. Over 100 PAFC units had then been installed in Japan. In 1993, Rokko Island had 14 Fuji Electric units of 50 kW each and one 200 kW Mitsubishi unit. The longest cumulative hours on any unit was approaching 20,000 in late 1993, half way to the goal for commercialization. He stated that the R&D philosophy adopted by Japan Government was different from that elsewhere. It could be characterized as “Total Development” involving MITI, NEDO, the electric and gas utilities and manufacturers, involving all aspects of development, including safety, for example the explosion testing of reformers, and improvements to burners. The industry in Japan was being helped by the enlightened attitude of the electric and gas utilities, and by the fact that the fuel cell developers were vertically integrated electric equipment manufacturers, possessing expertise in areas varying from robotics to electronic controls. This “Total Development” philosophy had enabled the Japanese developers to catch up very quickly in technology. The aim for commercialization would be increased power density, longer stack life, improving current density distribution, acid management, and improved materials, as well as plant simplification and standardization, improved mass production techniques, and quality control.”

Fuel cell technology

565

Japan certainly did not exclude the demonstration and testing of U.S.-manufactured PAFCs. By the end of 1994, there were a total of 23 PC25As installed in Asia, 22 in Japan and 1 at the Korea Gas Corporation. A useful update on Japanese fuel cell developments, which included a listing of the plants and demonstration projects in operation, was available in mid-1994.85 AISDIMITIINEDO: The Agency of Industrial Science and Technology (AISD) of the Ministry of International Trade and Industry (MITI) has provided the financing of the Moonlight Project, under management of the New Energy and Industrial Technology Development Organization (NEDO). Spending in billion Yen was Y3.38, 3.55, 3.70, and 3.18 from FY (Japan) 1987-1990. During this period, the percentage devoted to the PAFC fell from 70% to about 15%. The amount devoted to the MCFC rose from 24% to 78%. with the SOFC making up the difference. In 1991, the PAFC was eliminated from the R&D program, and government support then took the form of a new commercialization program with a ,under the Agency for Natural Resources and Energy (ANRE). The AISD budget rose steadily from 1990, to Y3.74 billion in 1991 and Y4.33 billion in 1992, of which 88% was for the MCFC, the remainder being for the SOFC. In 1992, a small amount was allocated for the proton-exchange-membrane (PEMFC) system. This rose to about 4% of the total budget of Y5.17 billion for 1993, of which the MCFC represented about 82% and the SOFC 14%. All programs required cost-sharing by developers, and there was speculation that the total spent on each is three times that provided by the Japanese Government Agencies. If this is so, the total amount being spent was $170 million (1995) per year at the trading exchange rate, or about $112 million (1995) at the PPP rate. Certainly, private industry has spent liberally on fuel cells, for example, the cost of the 11 MW PAFC demonstrator at Goi was approximately $150 million (1990) at the then conventional exchange rates. The development of practical MCFC plants was expected by 2000, with installation of large units expected by 2010. The fuel cells of the next generation (MCFC and SOFC) were being developed under the continuing Moonlight Project,% which was renamed the “New Sunshine Project” in-1992. As Section 12 has indicated, the Japanese market as estimated by MITI in 1990 was for a total of 2.25 GW in 2000 (presumably largely PAFC), and about 10.5 GW in 2010. The latter was projected to consist of 2..8 GW in commercial use, 2.4 GW in industry, and 5.0 GW of utility capacity, including 3.1 GW of PAFC plants. The AIST-NED0 estimate for the potential PAFC market around the year 2000 was 2.4 GW per year in units exceeding 1 MW in size, not considering sub-MW (e.g., 50kW to 200 kW) units. Thus,, the total market estimated by MIT1 was about 10% of the potential market for larger FCs estimated (using different assumptions) by AIST-NED0.35 Because of this large potential market, MIT1 and NED0 encouraged Hitachi Ltd. (Chiyoda-ku, Tokyo; R&D Center and works, Hitachi-shi, Ibaraki) to re-enter PAFC development and manufacturing in 1991-92. In addition, the Japanese Government supported the PAFC by offering up to one-third of the cost of installation during the fiscal years 1992-94.*7 While only Y800 million was appropriated for this purpose at the beginning of 1992, the amount was expected to increase rapidly. Anahara presented oral data at the 1993 Grove Symposium showing that cumulative spending on fuel cells through the year 1996 (in million v) would be 2,590 for basic R&D (100% government support); 13,509 for pilot plants (100% government support), 4,650 for demonstration plants intended to accelerate commercialization (50% government support), and 1,270 for field trials (33% government support). These sums represented about $150 million (1995) at the PPP rate, and $225 million at the trading exchange rate. The field trials subsidy would be granted for the construction and operation of all fuel cells (i.e., PAFCs) in Japan during the period 1992-94, with possible later extensions. This would also apply to fuel cell power plants built by off-shore developers. Going beyond the MIT1 projections for the year 2010, he stated that Japan expected to have 30,000 MW of central fuel cell power generation (in sixes from 50 kW to 11 MW), 15,000 MW of gas utility on site capacity (from 12.5 kW to 1 MW), and 1,000 MW of other capacity (in sizes from 4 kW to 200 kW). In 1995, it seems improbable that the PAFC industry could expand at the necessary rate to fill the proposed market. However, even if its development is less than anticipalted, some of the potential Japanese capacity might be provided by U.S. developers.

25. PAFC PROGRESS Ynited States The IFC 200 kW On-Site System: Activity on stationary PAFC generators in the United States is now almost entirely represented by the manufacture of the 200 kW IFC PC25 on-site system, together with the manufacture of stacks of PC23 type at IFC for sale to others. The only other company known to be considering PAFC development is the acquirer of Westinghouse technology (see below). Activity on PAFCs at ERC, from whom Westinghouse acquired its technology, was on hold due to the requirements of its ambitious MCFC program. The PC25 was the only fuel cell system which could be said to be close to true commercial application in 1994- 1995. The 200 kW on-site unit was first proposed by IFC to gas utilities in 1985-1986.4s Originally, it was intended to use a 0.34 m* CSA using the new “Configuration B” low-resistance ribbed-substrate technology operating at 0.22 Alcm2.63 Later, this was changed to 0.47 m* and 0.25 A/cm* to reduce the overall CSA

566

A. J. Appleby

height. The higher current density was permitted by performance improvement.@*rO Recent developments have allowed further reduction in the number of cells in the CSA. Since the decay environment at 0.65 V under atmospheric pressure conditions is much less aggressive than at 0.73 V and 8.2 atma pressure, there appeared to be no question that the lifetime performance of cell components would be as specified. Other improvements to the system are discussed later. The PCX Prepromypes: The development of the PC25 was made possible after four PCX preprototype units were constructed and sold to Japanese customers. PCX-1 and PCX-2 were tested by TEPC0,88~89 PC25YX-1 by Osaka Gas;90 and PC25YX-2N by the Nippon Petroleum Refining Company.91~~ The PCX-1 unit was installed outside at the Shin Tokyo thermal power plant and started operating in October 1988. Its CSA was replaced after deterioration during the first thousand hours of operation. Performance fell by about 25 mV between 180 and 3,250 operating hours (i.e., by about 4% from rated cell voltage). It fell from approximately 0.63 V to 0.605 V at 0.3 A/cm2 (c.f., 1985 short-stack performance of 0.62 V at 0.3 A/cm2, Fig. 3 and Ref. 8), from 0.675 to 0.65 V at 0.2 Alcm2, and 0.705 V to 0.68 V at 0.1 A/cmz. The net ac electrical efficiency was close to 38.5% (LHV, 41.8% gross, with incell efficiency 47.3%) at full load, and 41.8% (gross 44%, in-cell efficiency 49.5%) at 150 kW (75% load). Overall cogeneration efficiency (LHV) was 88%. Harmonic distortion was less than 3%. noise was less than 50 dB at the site boundary, and NO2 emissions were 3 ppmv (7% oxygen, dry basis, i.e., 5.4 g/MWh). The PCX-2 was first installed in the basement of the Kandenko building in the Shiba-ura district of Tokyo. Its operation started in March 1989. By August 1990, the two TEPCO units had performed for 5,210 hours (876 MWh) and 3,780 hours (409 MWh), with 1,393 and 409 maximum continuous hours by August 1990. In March 1990. the PCX-2 unit was transferred to a subterranean location at the Shiba-ma District Heating and Cooling PlanF after operating for 3,509 hours at the first site with 31 forced outages (8.9 per 1,000 operating hours). The PCX-I unit was terminated in late 1990 after completing 6,762 operating hours 1,032 MWh), with a maximum continuous run of 1,393 hours, with 56 forced outages (8.4 per 1,000 operating hours). By August 1991, PCX-2 had operated for 10,697 hours with a maximum continuous run of 3,245 hours, a world record at that time. At its second site, it showed much more reliable operation (1.7 forced outages per 1,000 operating hours).27 By November 30, 1991, it had attained 11,141 hours (1,059 MWh), with a forced outage rate of about 1.4 per 1,000 hours since its transfer to Shiba-ura. The maximum net ac LHV efficiency was 38.5% at 150 kW output. It was 33.5% at 200 kW without heat recovery, and 31.5% with heat recovery. Its overall cogeneration efficiency was 67% to 70.5%. However, when operating at 100 kW and below, it required a 65 kW electric heater to raise make-up steam for reforming, which substantially reduced its efficiency under these conditions. At 100 kW electrical output, the average gross ac LHV efficiency lay between 35 and 38%, but net ac efficiency was only 22.8-27.24, depending on the external heat requirements, which included a heat pump. Overall electrical and heating efficiency under these conditions was between 60% and 64%. Its measured NO;? emissions were well within the 25 ppmv specification, viz. a maximum of 13 ppmv in 1992. Its cell voltage showed a drop of 6.5% per 1000 hours, which appeared to be associated with system shutdowns. It was determined that improvements should include better stability, lower cost (i.e., much less than $8,000-$lS,OOO/kW in 1990 dollars), and lower part-load parasitic power requirements.89 At 14,500 hours, the CSA was replaced by a Toshiba-manufactured unit, and by August 1994 the BOP had accumulated 28,000 hours, then a world record.93 The Osaka Gas PC25YX-1 unit started up in April 1989, and operated in the Umeda Center Office building for 3,800 hours by July 1990. Its NO;! emissions were at the limit of detection, 2 ppmv. The user stated that power section durability required improvement. 90 The PC-25YX-2N at the Nippon Refining Company was a 130 kW (nominal) unit modified to include enhanced desulfurization for operation on lowsulfur naphtha (boiling range 28’C-72’C, 0.1-0.3 ppm by weight of sulfur). It started up in March 1990, and had operated for 4,808 hours up to the end of 1991 at an average load of 106 kW. It was intended to eventually develop a system which could operate on No. 1 kerosene (boiling range 19O”C-258‘C, 10-100 wt. ppm sulfur) using a Haldor Topsoe kerosene reformer. 91$2 An adsorption catalyst for fuel desulfurization with a life of 40,000 hours was developed in 1991. It was capable of desulfurizing both naphtha and No. 1 kerosene to the 0.01 ppm by weight level. The Haldor Topsee kerosene fuel processing unit had been tested for 10,745 hours at 77% average load up to the end of 1991. It was capable of loadfollowing at the ramp rate of 75% per minute, and had a 3.5 hour start up time. The naphtha-fueled PC25YX-1 had operated for 4,808 hours up to the end of 1991 at an average load of 106 kW. Its ramp rate was 10 kwfsecond and start-up time was 4.5 hours.92 PC25A: Following the delivery of the PCX preprototypes, the PC25 design was refined to give greatly improved performance, both from the viewpoint of emissions, efficiency, and decay rate. The 200 kW PC25A on-site cogeneration unit was &signed to operate at 40% LHV electrical efficiency (about 90% total LHV efficiency). It was to be manufactured by the ONSI joint venture created in 1990 by IFC and Toshiba, with a minority participation by Ansaldo srl of Genoa, Italy (see below).83 Under the venture agreement, ONSI would produce on-site cogeneration PAFC plants up to 1 MW,. Toshiba and UTC had determined that IFC and Toshiba products would not compete in Japan, but might compete elsewhere. While Toshiba had its own plans for on-site packaged PAFCs, it had agreed not to compete, i.e., to export prepackaged PAFC units, before 1998.

Fuel cell technology

561

A new production facility to manufactuxe the ONSI PC25A and its successors at IFCs facility in South Windsor, ff (the old United Technologies Power Systems Division) was started in 1990. Initially, the production line was planned to produce 10 MW (50 units) per year, with eventual growth to 40 MW (200 units) per year. The first delivery of the initial PC25A version was in the winter of 1991-92, and production reached the initial level of four units per month in mid-1QQ2.w A list of PC25 units which were scheduled for operation in Japan during 1992-94 was given in 1992.950 Three ONSI units were then expected at Tokyo Gas, Osaka Gas, and Toho Gas, making a total of 31 which were to operate in this timeframe, out of the 55 manufactured or on or&r from 26 customers in 10 countries.94 A oral update of developments was presented by Whelan at the 1992 IFCC.% Production capability had reached 6 units per month by mid-1993. In the United States, a total of 19 gas industry units were operating by mid-1993, 10 at Southern California Gas (SoCalGas), three at Columbia Gas, and one each at Atlanta Gas and Light, Brooklyn Union Gas, Consolidated Natural Gas, Equitable Gas, Natural Fuel Gas, and People’s Gas, Light, and C0ke.w A preliminary report on the operation of the SoCalGas PC25A at the Irvine Hyatt Hotel was given in 1992. The electrical load of the hotel was three times the output of the fuel cell, so absorbing it presented no problems. The hotel’s thermal load had seasonal and daily changes, which would require future system modifications, including hot water storage and a change in the start of laundry hours from 07.30 to 17.00 hours.98 The unit at the South Coast Air Quality Management District (SCAQMD) in Diamond Bar, CA had encountered problems involving corrosion of valves, which required stack replacement. It was reported to be operating well in September 1993.99 Early data on nine European units (up to July 15, 1993), the earliest of ,which first operated on June 10, 1993, was given at the Third Grove Symposium.tw By September 1993, the total cumulative PC23A operating hours worldwide were 140,000. They were 215.620 on December 31, 1993, with 38 units then operational, with a worldwide ovemll average availability of 93.5%, and a U.S. availability of 95.4%. The highest availability was then 99.3% for the unit at Pittsburgh International Airport. At the end of 1993, the first Southern California Gas unit (No. 9004) had accumulated 11,031 hours, at 92.3% overall availability. The Irvine, CA, SoCalGas unit (No. 9005) had 10,554 hours at the end of 1993, (96.4% availability), and the unit at Brooklyn Union, NY (No. 9025) had 9,428 hours (94.9% availability). By May 1994, the units in field tests had accumulated over 300,000 operating hours. The Tokyo Gas Company had seven PC25As installed between July 1992 and January 199,4. The two oldest units, installed in July and September, 1992 at the R&D Center, had accumulated 11,133 and 10,500 hours by August 1994. A third R&D Center unit, installed in November 1992, later transferred to the Senju Building, had accumulated 8,653 hours at the same time. Degradation rates on 3 PC25As (Tokyo Gas R&D No. 1, Tokyo Gas Senju Building, and Sodegaura Works), which had approximately 1 l;DOO, 9,900, and 8,650 operating hours by August 1994, were compared. All showed lower degradation than that predicted (an estimated 10% voltage decay, following a linear relationship with the logarithm of time over 40,000 hours). In the first two cases, some early decay occurred, which was followed by relative stability. Both CSAs were operating about 20 mV above the estimated decay curve. The unit at Sodegaura Works (installed June, 1993, 8,653 hours in August 1994) improved with time over 5,000 hours, and was substantially (ca. 55 mV) above the decay curve at 8,000 hours. However, it had had 11 forced outages. It appears that performance decay was less apparent with newer PC25A units, since the three represent mid1992,late-1992, and mid-1993 technologies respectively. The Sodegaura Works unit (N. 9039) had had a continuous run of 6,325 hours (from August 19, 1993 to May IO, 1994).101 One Tokyo Gas PC25A unit was converted by Toshiba to produce cogenerated steam, rather than 60°C or QO’C hot water.9z@l Number 9001, the oldest of eight units ordered by Osaka Gas, which replaced the PC25YX-1 in the Umeda Center in Osaka, started up in August 1992. It was at 10,716 hours at the end of 1993, with 95.4% availability, and a then-record 5,476 hours of continuous operation. It had reached 14,6Q2 hours in August, 1994 with 8 forced outages. The second Osaka Gas unit (9010) was at 12,441, with a longest run of 3,427 hours (3 forced outages).‘02 By March lQ94,16 PC25As were operating in Japan (at Tokyo Gas, Osaka Gas, see above; with one at the Toho Gas Head Office), with a total of 105,896 hours accumulated .ssa A mid-1994 listing shows 52 units o erating or about to operate in 1994-95, with the whole series apparently completed by May 1994.9 9b By December 31, 1994,51 PC25A units out of 56 ordered had been installed worldwide, and a total of 501,434 hours accumulated, with a mean availability of 95.1%. The Sydkraft, Sweden unit, delivered in June 1992. had accumulated almost 13,000 operating hours by March 1994. By December 31, 1994, it had accumulated 18,590 hours. Its performance and degradation were within the expected norms from stack bench testing. It had the distinction of requiring only 7 days from delivery to a prepared concrete pad to power generation. The Korea Gas unit, delivered in September 1993, was also operating 7 days after being placed on its prepared concrete pad. The SoCalGas units installed in September 1994 had completed 3,700 hours by the end of 1994, in a continuous run representing 100% availability. On August 28, 1995, one unit (No. 9041) had had a continuous run of 8,451 hours from September 6, 1994 to August 24, 1995, and the other (No. 9041) had continuously operated from September 7, 1994 (8,509 hours at 100% availability). By August 21, 1995, nine units had exceeded 20,000 operating hours (SoCalGas No. 9004, 24,121 hours; No. 9005,22,405 hours; Osaka Gas No. 9001, 21,752 hours; Imatram Voima Oy (IVO, Finland) No. 9021, 21,713 hours; Sydkraft No. 9006, 21,481 hours; Brooklyn Union Gas No. 9025, 21,237

568

A. J. Appleby

Thyssengas No. 9012, 21,064 hours; Equitable Gas No. 9023, 20,459 hours; and Ruhrgas No. 9011,20,067 hours). Three others had exceeded 19,000 hours, and a total of 21 had exceeded 16,000 operating hours. A total of 19 units had had continuous runs exceeding six months.103 When the PC25A was announced, it was hoped that about 100 orders would be rapidly received. However, this period coincided with economic slow-down. The purchase cost goal for the first approximately 50 units was quoted as $2,500 per kW ($2,850 per kW, 1995). The unit cost was about $3,3OO/kW(1995) for early units, which rose to .$4,5OO/kW(1995) or more, including training services, as the real costs of assembly labor became mote accurately determined. True production costs were apparently higher than the selling price. For example, the cost per kW of the SCAQMD unit, including purchase, installation (April, 1992), and O&M, was $4,500 per kW ($4,900 per kW, 1995). It was expected in 1991-1992 that the purchase cost would be $l.SOO/kWfor a production run of 700 units. Only 56 orders for the PC25A resulted, of which 19 were from California, 9 from the rest of the United States, 1 from Ontario Hydro, Canada, 10 from Europe, 22 from Japan, and 1 from Korea Gas Corporation. In 1993, ONSI had stated that 40 further orders for the PC23A or its successors were then pending.laa The smaller production run had the effect of increasing costs beyond the original estimates. In addition to the 56 PC25As. 12 relatively similar PC25Bs procured under the FY 1993 military demonstration funding appropriation were being installed on military bases starting in 1994 in a cost-shared program with IFC. The first unit was installed at Vandenberg Air Force Base, CA, beginning in March, 1994. All these units would have a five-year warranty, and would be tested for five yearala Other units were installed (installer and servicer in parentheses) by July 1995 at the Natick Research, Development, and Engineering Center, MA (Commonwealth Gas); Twentynine Palms Marine Corps Base, CA (ONSI); Newport Naval Complex, RI (Providence Gas); and at the 934th Air Reserve Station, Minneapolis, MN (Minnegasco). Other sites selected were Kirtland Air Force Base, NM, West Point, NY; the US. Navy Submarine Base, Cr, Picatinny Arsenal, NJ; Fort Eustis, VA; Camp Pendleton, CA; and Nellis AFB, NV. It was hoped that installation of the 12 FY 1993 units would be completed by the end of FY 1995. A total of 18 PC25Bs were then expected to be installed by the end of 1994, after the FY 1994 appropriation became available. hours;

Operating Experience: As has been indicated, performance of the PC25A has exceeded specifications for CSA decay rate. The fact that a representative number of PC25As have now exceeded 50% of their planned stack life, without surprises, gives excellent reason to have confidence in the electrochemical part of the technology. The BOP is close to standard chemical and electrical engineering practice, and there appears to be no reason why this should not have a lifetime consistent with industrial norms, i.e., a BOP life of 30 years, with appropriate maintenance and replacement as required. Availability had been excellent, and had improved with time, so that the latest units have shown 100% over 12 months from start-up. The negligible emissions of the PC25A as measured in California (0.45 ppmv NO2,2 ppmv CO, 4 ppmv total hydrocarbons at 15% oxygen, dry basis, compared with California combustion engine standards of 36 ppmv for NO2,2,000 ppmv for CO, and 250 ppmv for reactive organic gases, ROG), resulted in its receiving a blanket emissions exemption from SCAQMD in 1993.91 The San Francisco Bay Area Air Quality Management District also granted a blanket exemption in 1995, and the Commonwealth of Massachusetts was reportedly considering a similar exemption. In 1995, the average emissions of delivered units were even mom impressive, 0.45 ppmv N&, 1.4 ppmv CO, and 0.03 ppmv ROG, compared with specifications of <3 ppmv NO2,
Fuel cell technology

569

dependent on thermal recovery requirements, needed constant review, since in some cases elaborate or parttime thermal recovery was not warranted. By August 1994, the NAFOG units had accumulated 125,000 hours, including the then world record uninterrupted run of 7,570 hours at Southern California Gas. NAFOG members stressed the excellent user manual, the user-friendly control system which could be monitored remotely by members and ONSI via modem, instant technical backup by telephone during working hours (within 30 minutes at all other times), and finally the overnight parts delivery service. These had resulted in a raw availability of 88.4% including scheduled outages, which with parts back-up and service personnel in a lo-unit fleet would translate to 95.5% availability. Considering the many mechanical and electrical parts in the system (apart from the CSA), this is remarkable. Up to the time of reporting in 1994, there were 50 forced outages, 12 of which were in ventilation fans and process air controls, and 14 in the electric systems. In addition, 26 inadvertent operations of shut-down buttons occurred, 11 of which were due to operator inexperience. The mean time to forced outage was then 2,500 hours. Since about half of the reasons for outage have been designed out of the new 1995-96 PC25C. a future rate mean time to outage of 5,430 hours was projected. The improvement is shown by the mean time to outage during the fleet history. It was about 1,000 hours during the fit half of 1992, 1,820 hours in the corresponding period in 1993,2,320 hours in the same period in 1994, and 3,290 hours from June 1, 1994 to August 14, 1994. This compares with the North American Electric Reliability Council Generating Unit statistics (1988 to 1992) of about 500 hours for fossil plants, 400 hours for geothermal plants, and 1,400 hours for nuclear plants. Similarly, the January 1990 to September 1992 Gas Research Institute statistics for cogeneration plants show mean time to forced outage of 500 hours or less for reciprocating engines (60 kW to 800+ kW) and gas turbines from l-25 MW, with a figure of 1,500 hours for units over 25 MW. NAFCOG members expressed satisfaction at the low performance decay rate. They also stated that IFC-ONSI had been very responsive and supportive.1°6P By mid-1995, the group’s experience was rapidly accumulating. How units could be better integrated from the thermal viewpoint at a wide range of sites was being investigated, e.g., even where steam boilers existed, heat could be recovered for feed-water preheating. The wide range of heat recovery conditions (46OC to 82’C, depending on flow rate) offered flexibility in use for water heating and space heating, including use a heat pump sources. In simple cases with short heat interconnects, an installation cost of $250-$4OO/kW was achievable if no elaborate esthetic requirements existed. Since the PC25C had a built-in disconnect switch and sideinterconnect cluster, this should minimize installation cost, which should be further reduced if the optional air-dump system could be mounted on the fuel cell unit. It was considered that incorporation of this unit was essential to give maximum flexibility. Unlike Japanese users, NAFCOG considered that steam beyond 2 atma (12O’C) from a glycol loop was of limited value at most sites. Any concerns raised about internal components with safety issues, e.g., the gas-fired start-up heater or the mil-spec internal wiring had been eliminated by the granting of a seal of product approval by the American Gas Association. The electric interface requirements also varied from site to site, including grid-connection and non-grid-connected uninterruptible power source applications,lMb e.g., at the AT&T Bell Labs computer center in Crawford Hills, NJ.ssC Excellent inverter electronics gave maximum flexibility, but care was still required in interfacing, because in some low-power-factor applications, power consumption (in kW) at the user could be cut off more rapidly than the reactive power of the unit (in VAR). The fuel cell would be best used in applications with a high load factor. Average time for interconnect approval had been four to eight months, with a maximum of 2.5 years. It was hoped that this could be completed for follow-up sites in the territory of a given utility within a few days. In 1995, the NAFCGG fleet had accumulated 228,000 operating hours with a mean time to forced outage of 2,240 hours, about three to four times better than that for gas turbines under 5 MW (842 hours), and natural gas engines over 80 kW (507 hours). Corrected for correct parts inventories and servicing, the overall availability had been 96.2%. In the PC25C, the raw availability was expected to increase from NAFCOG’s 88.7% to >95%. Again, careful design to avoid undetected cascading problems and user-friendly interfacing at the operational and servicing level was stressed, A computer model to calculate utility costs under real conditions with and without a fuel cell was required to help determine economics under given field conditions. 106~ Some progress in this respect was being made in Japan using Optimal Planning Models. 1s6d Based on PC25A experience, the PC25C promised to be an outstanding machine whose ability to supply 100% load for extended periods should be best made use of. To activate the market, real commitments to purchasing PC25Cs were required.la6b In 1993-1994, IFC was working with regulatory bodies on a product which will satisfy the large number of often contradictory international codes. Block licensing was important for rapid and widespread application. In Japan, MITI had issued a block license for 8 units. The power plant would have normal commercial guarantees. The developer intended to establish extended life warranties with potential customers of later PC25 models. For the PC25A, warranties were for only one year,97 This was also initially proposed for the PC25C,aSb although extended watranties could be purchased.95c In contrast, the warranties for the military PC25B were reportedly for five years.l@t Improvements and Cost Reduction: IFC-ONSI had made a major effort to reduce the cost, weight and volume of components, which included those of heat exchangers, the CSA, the inverter, and the reformer on going from the experimental PC25A to the “precommercial” PC25C. This would result in reduced production costs. The PC25C will weigh 18,200 kg (40,000 lb.), compared with 27,300 kg (60,000 lb.)

570

A. J. Appleby

for the PC25A, and 36,000 kg (80,000 lb.) for the PCX prototypes. Its dimensions would be similarly reduced. The PCXs were 3.5 (height) x 3.5 x 11.3 meters (11.5 x 10 x 37 ft), whereas the PC25A was 3.5 x 3.0 x 7.3 m (11.5 x 10 x 24 ft), and the PC25C will be 3.0 x 3.0 x 5.5 m (10 x 10 x 18 ft). The optional air-dump cooling unit for the PC23A for non-cogeneration applications was 2.5 x 2 x 2.5 meters in size, and weighed 3,200 kg.*O” This was also to be reduced in size and weight. The current density of the PC25 has been progressively increased from the original value of 0.22 A/cm2 as performance has improved. It is now some 30 mV better than 1985 single cell data (then 0.62 V at 0.33 A/cm*), and the shortened 231-cell PC25C CSA (originally 320 cells) will operate at close to 0.3 A/cm2, reducing CSA height, therefore its weight, volume and cost. Mechanical parts have been reduced by 25% in the PC25C, and cooling improvements increase its reliability and time-tc+overhaul. In spite of its increased compactness, accessibility for maintenance has been improved. Since most of the final cost is in assembly, the effect of the reduced parts count on cost is important. The component count in the fuel control system has been reduced by 60%. giving a 70% reduction in cost. Improved fabrication methods yield a CSA cost per unit area which is 40% less. Combined with the effect of a higher current density, the total cost of the CSA has been therefore reduced by 60%. Heat exchanger weight is down by about 70% by the use of improved flat plate technology to replace tube and shell structures. Improvements in the inverter (conducted with Toshiba) have allowed a 5 ton weight reduction and an approximate 70% volume reduction. It now uses Insulated Gate Bipolar Transistors (IGBTs) to eliminate many inductors and transformers.lo7 Production and Marketing: The PC25C was originally expected to be available starting in March 1995 at $3,OOO/kW (1995), a reduction of about $2,OOO/kW compared with the previous version. For viable production, the initial output of PC25C units should total 10 MW (50 units) per year for three years, with increasing production thereafter. Inevitably, a major investment or subsidy, estimated by IFC at $75 million, and by Arthur D. Little, Inc. at $150 million,s3 would be necessary to achieve the goal of a production rate of 200 commercial units per year, and so reduce the selling price to commercial levels following the normal learning curve process. Orders had been obtained for approximately 50 units by October 1995, with three units to be delivered by the end of the year. In spite of the relative maturity of the units, all were factory-tested before delivery.lo3 IFC-ONSI considered the PC25 models (and their successors) to be customer-side-of-the-meter, gasutility products, whose use would be market driven. The company’s production goals were an improvement in manufacturing capability accompanied by R&D to reduce manufacturing cost, a constant focus on the definition of improved products, the development of an effective product-customer support infrastructure in which the gas utility owns, installs, and maintains the equipment, together with a marketdriven expansion of applications. The philosophy is remote dispatch and remote monitoring of equipment, with a service requirement of only one call per year. Maintenance will not require equipment shut-down. R&D will be an on-going activity to make a more competitive product and to aid commercialization. Areas of required R&D include materials improvements, unit cost reduction, increase in power density, therefore in cost-effectiveness, increase in efficiency, and a broader fuel capability. Emphasis in the approach to the commercial model will be on. fuel processor, cell and stack improvements. Some improvements would be necessarily gradual, whereas other could be put in place rapidly. One example of a rapid and very cost effective upgrade would be the replacement of 1985 inverter technology with 1992 equipment.97 The aim was to reduce the cost of true commercial units (the PC25D) to about $1,5OO/kW in 1998. Its weight was expected to be reduced to 14,000 kg (30,000 lb.), and its volume would be 25% less than that of the PC25C.lo3 The first commercial cogeneration niche markets should become available at a selling price of $2,5OO/kW,. IFC had identified 100,000 buildings which would meet their target criteria for PC25 installation in the United States, for which a capital cost of $1,5OO/kWe or greater would be economical. Half of these building would have economical installations at $1,800/kWc. The goal for installation cost was an additional $375/kW,.g7 Another important, high-value market was expected to be the use of the PC25 to consume landfill or digester gas. This must otherwise be disposed of by flaring, or must be carried away in costly, custom-built pipelines after expensive upgrading to pipeline-quality gas.30 When it is used with landfill gas, the PAFC (or other fuel cell technology) would benefit from a 95 $/MMBTU (9O@/GJ)tax credit. An IFC-EPA program on the use of landfill gas in the PC25 was summarized in 1994.108 A PC25 was tested at the PG&E Penrose Landfill site in Sun Valley, CA, supplying electricity to the Los Angeles Department of Water and Power. In mid-1995, the unit was moved to a Northeast Utilities landfill site in Groton, CT. Another project will use gas derived from municipal waste in a purpose-built anaerobic digester located at Folsom Prison, California. 109 In another EPA program, PC25s will use cleaned-up anaerobic digester gas produced from wastewater treatment plants, starting in the Northeast in early 1996. Cost Reduction: In a new production development, assembly teams completing each unit continually study methods of simplifying assembly and reducing assembly time and cost, so that the next unit will be less expensive. Thus, IFC has already made considerable progress in fuel cell system design innovation to reduce cost.48 Toshiba envisages the use of a small water-cooled inverter in the future.93 Future improvements to the reformer (with Toshiba) and to other heat-exchange structures are envisaged. As the promise of increased production has taken place, and as vendors become more aware of the requirements of

571

Fuel cell technology

the technology, parts are being integrated. For example, it was now possible to envisage a combined valve, gauge, and pump assembly, rather than using separate vendor-supplied items.rn3 Graphical materials provided by IFC-ONSI which are included as charts in Ref. 83a (p. 392-395) show that the stack Power density doubled between 1984 and 1994, increasing by 7% per year. At the same time, the reduction in stack cost per unit area was reduced by about 15% per year, giving an overall reduction in stack cost per kW of close to 20% per year. Since the early 199Os, the cost of the fuel processor had also fallen by approximately 20% per year. The fall in the cost of the power conditioner, which had been reduced in weight and volume by 80% over 3 years, was close to 35% per year. Heat exchanger volume fell by 75% and assembly and ancillary equipment costs by 80% in three years. For a new and growing technology, the cumulative RD&D, preproduction, and finally production manhours grow exponentially or approximately exponentially with time. A learning curve can be constructed in the normal way, as a log-log plot of falling unit cost against cumulative production for a mature technology, or as log-log plot of falling unit cost against cumulative man-hours for a less mature technology. The latter should be the same as a semi-log plot of constant dollar cost as a function of year. The constant-dollar cost per kW of PAFC systems produced by UTC-IFC has fallen linearly by a factor of 30 (1.5 aorders of magnitude) between 1970 and 1995 when log cost is plotted against time.110 This corresponds to a fall in per kW cost of approximately 13% per year, which is not inconsistent with recent IFC-ONSI experience with the PC25A, B, and C. This indicates that with reasonable confidence, the per kW cost of the PC25 may be expected to be reduced by a factor of two in 5 years. We may also examine cost based on production experience, instead of as a function of time. The classical learning curve (cost as a function of cumulative production) assumed for PAFCs in Refs. 6 and 8 had a log10 slope equal to approximately -0.2 (i.e. each doubling of production gives a product with 87% of the previous cost). The real experience curve for the constant-dollar cost of the PC series of on-site units (based on the limited data available), had a much steeper logto slope, which was close to -1.1. i.e. each doubling reduced cost to 47% of the previous value. 110 This appears to be characteristic of an immature technology, and was in turn greater than the range of values assumed in Ref. 83,* which a.ssumed a probable value of -0.4 (to 76% of previous cost per doubling of production), which is characteristic of moderately complex systems. For example, the value for systems of low average technology such as supertankers was approximately -0.3 (to 81% of previous cost per doubling), whereas the value for chemical plants and pipelines was -0.33 (to 80% of previous cost per doubling),

and that for relatively

mature complex systems such as nuclear power plants was -0.5 (71% of previous cost per doubling). Based on the fact that the materials cost of the PC25C was tending to less than $600 per kW, there seemed to be little doubt that a commercial plant could be profitably built for $1,500 per kW towards the end of the decade, provided that customers liked the product, and provided that means could be found to identify a sufficient number of niche markets (or financial incentives) to make early PC25C models financially attractive. A range of products was ultimately possible, from 50 kW to larger than 200 kW. The problem was the cost-effectiveness of small sizes if the mature cost per kW varied with unit size to the -0.6 power, which was a standard learning formula.97 If this should prove to be the case, a 50 kW system might be sold for $3,500 per kW, a 200 kW unit for $1,5OO/kW, whereas a 1.25 MW unit would have a selling price of only $500 per kW. The latter in particular seemed highly improbable, given the materials cost constraints and postulated CSA costs. A more probable scenario, given the Japanese experience with smaller units (see later) was $2,000 per kW for 50 kW, $1,500 per kW for 200 kW, and $1,000 per kW for 1.25 MW, giving a -0.22 power curve. A 1.25 MW unit with 6 PC25C (or D) CSAs, with 4 single modules for respectively fuel processing; air supply, control, power distribution, controls, and water treatment; power conditioning; and cooling was in the planning stage in 1994.r*r The commercialization prospects for the PC25C successor appeared to be good in 1995. Because of the risks inherent with new technology, innovative marketing approaches were essential. One basic assumption of the TARGET program of 1967-1975 was that gas distributors, not energy users, would own the fuel cell equipment. A similar philosophy was proposed for the PC25. In May 1994, ONSI and Enron Emerging Technologies, Inc. (EETI) agreed to market energy product services (delivered electricity and heat) using the PC25 as the vector. EETI was established in January 1994 as a subsidiary of Enron Corporation, a major gas pipeline company. Under the agreement, the customer would not involve the risks of owning or operating the unit.112 Leasing of equipment to users was another possible approach, but a better solution was considered to be the sale of power by intermediaries, so that customers who are sophisticated in their own domain (e.g., hospitals and other electronic-intensive clients requiring highquality uninterrupted power, c.f. Europe, below) would not have to buy their own FC power generating equipment. Westinghouse-FuelCell Corporation of America (Large, PA): Westinghouse, ERC’s PAFC licensee, had been improving their air-cooled stack up to early 1992. This had shown itself to be capable of 0.69 V at * This reference uses a “b” value, which is equal to 1 + c, where c is the (negative) slope of the log10 learning curve.

572

A. J. Appleby

0.27 A/cm2, 19O’C and 4.8 atma, at synthetic reformed gas hydrogen utilization of 83% and 50% oxidant utilization. Newer technology with a 0.705 V operating point with 50% of the previous degradation rate was under test in 1990. This included two 2.5 kW stacks in 10,000 hour tests, and a 100 kW stack in a 1000 hour test. A 375 kW module was then being prepared for testing,‘” which was carried out in 199192.114 Improved cooling methods were being investigated. 115 A 16 MW unit, which could be configured from 3 MW to 50 MW, was planned for industrial applications, i.e., those where a supply of hydrogen or hydrogen-rich gas already existed. *14 The first stage of this was to be an industrial demonstration of the module, which could operate at 400 kW on hydrogen at an initial efficiency of 55.4% (LHV). A three-year test program starting in 1992 was planned with Norsk Hydro. A unit would operate on hydrogen produced at a chlorine plant at Rafnes, Norway. 114 This program was abandoned in mid-1992, and in March 1993 Westinghouse sold its air-cooled phosphoric acid technology to a new entity, the FuelCell Corporation of America, based in the same location at Large, PA in the leased Westinghouse facility. The Defense Department was supporting a program with the company to design and build a 400 kW plant using an existing stack module, which would be demonstrated at the Concurrent Technologies Corporation facility in Johnstown, PA.9sb Europe General: In 1992, the potential development of PAFC fuel cell generators in Europe was hindered by the lack of stack manufacturers, but this was effectively made up by the ready availability of developers of chemical engineering systems (KTI, Haldor Topsoe) and of inverters (Siemens, Philips, AEG, etc.). PAFC units therefore used purchased stacks, e.g., from IFC for the 1.2 MW unit for AEM, the Milan utility, which had two 670 kW stacks of PC23 type similar to those used at Goi. Stacks for the two 25 kW PAFC units built by KTI in the Netherlands under Italian-Dutch-CEC sponsorship were similarly purchased from Fuji Electric81 These were assembled into systems by KTI (see Ref. 12), but further work on this collaborative effort had been reportedly discontinued by 1994. Demonstrations with purchased on-site units were in progress or planned in several countries in 199192, for example in Sweden (two 50 kW Fuji Electric units at the utilities Sydkraft and Vattenfall, one 200 kW PC25A for Sydcraft co-sponsored with Nutek); Germany (three PC25As for Ruhrgas, I-IEAGlState of Hesse, and Thyssengas); Denmark (one PC25A for Naturgas Syd Sonderjyllands Hojspamdningsvaerk); Finland (one PC25A for Imatram Voima Oy, IVO, co-sponsored by EA Technology, United Kingdom); Austria (one PC25A for Austrian Femgas); Spain (one 50 kW FP-50 Fuji Electric unit for Enagas); Italy (one 50 kW FP-50 Fuji Electric Unit for SNAM/Eniticherche, one PC25A for CLC-Ansaldo); and Switzerland (one PC25A for SIG).asa*b This gave a total of nine PC25s (manufactured by IFC subsidiary ONSI) and four 50 kW FP-50 Fuji Electric units to be demonstrated in Europe up to that time, in addition to the two KTI units with Fuji Electric stacks. European companies interested in various PAFC components included CLC-Ansaldo (Italy, stacks and complete systems), Johnson-Matthey (United Kingdom, catalysts), KTI and Haldor Topsoe (the Netherlands and Denmark, balance of plant). Three major markets were seen in Italy (and in Europe in general) for the packaged PAFC. These were for cogeneration applications in residential and tertiary sector buildings, where electricity prices are generally highest; for use with “waste” fuels (e.g., landfill gas, municipal waste, and renewables) which many Government regulations force utilities to use; and for quality power applications requiring high-quality uninterruptible power supply (UPS) systems. For the first and second application, regulations were required to oblige the use of ultra-low emissions equipment rather than internal-combustion cogeneration machinery to make fuel cells the technology of choice. The second application, which has recently opened up new markets for internal combustion engine manufacturers, will also be favored by the low fuel cost, high fuel cell efficiency, and the high electric utility buy-back prices for the resulting power. The applications in this sector included those where hydrogen is considered to be a waste gas from the chemical industry. Since the trend was towards higher (unsubsidized) electricity prices for electricity-intensive processes, e.g., in the electrochemical industries, autoproduction would become more widespread. This application strongly favored the PAFC, which would be more efficient and cheaper when operating on hydrogen fuel, for which gas turbines were not designed. The final UPS market area was strongly favored by the very high availability of the PAFC operating as a primary power source, and its power quality compared with, e.g., diesel back-up equipment.116 Operating Experience: The ONSI PC25A at Sydkraft was delivered in June 1992, and was operating seven days after being placed on the prepared concrete pad. By September 1993, it had operated satisfactorily for 9,000 hours. Its progress has been reviewed above with that of other PC25 units worldwide, which include emissions, data. A very brief review of the Austrian Ferngas PC25A performance was available.rr’ Initial problems with the Sydkraft Fuji Electric Company FP-50 50 kW unit included self-commutation of the inverter when it sensed line fluctuations. This was essentially a software problem. After this was corrected in May 1993, the Sydlcraft unit (first operated on 1 November 1991) had operated 4,300 hours continuously from June to November, 1993, and had completed 7,000 hours operation by February 1994.11a By mid-1994, the longest continuous run had been 4,400 hours.” A 1994 report was available

Fuel cell technology

513

on operation of Vattenfall’s 50 kW FP-50 Fuji Electric Company unit at Varberg, which was installed in January 1993. It operated grid-connected for 2,739 hours in three runs (longest continuous, 1,611 hours) to the end of 1993 at approximately 36.5% LHV efficiency (79% total, LHV). Suggested improvements concerned start-up time (4.5 hours from cold, 1.5 hours from warm stop to stand-by, and 20 minutes from 0 to 50 kW output), too many alarms (66%) resulting in automatic shutdown, the requirement for manual load-up when grid-connected in 5 kW steps each lasting two minutes. This decreased possibilities for use on independent loads. Performance degradation appeared to be satisfactory, but ac harmonic distortion was 6%, 1% higher than the tolerable limit. Acoustic emissions were 70-72 dB at one meter, depending on direction. In regard to emissions, organic sulfur (as tetrahydrothiophene) was undetectable, CO was 0.210.24% (limit l%), and N@ was about 8 ppmv (peak maximum), but more commonly 1.5-4 pprnv at 12% oxygen in the raw exhaust, i.e., 6-16 g/MWh. 119 A discussion of the progress of all four units up to July 15, 1993 was given at the Third Grove Symposium. *a(~ The four European FP-50 units were taken out of service during 1994. The Sydkraft unit had operated for 7,700 hours, with a longest continuous run of 4,200 hours. The three remaining units operated for approximately 5,000 hours each. The Sydkraft unit was to be restarted with a new stack and a number of other improvements in February 1996.118 European operators of the nine ONSI PC25A and four Fuji Electric Company FP-50 50 kW units reported to the European Fuel Cell User’s Group (EFCUG). However, this organization did not include exchange of information on the 1.2 MW PRODE project in Milan (see below). Reactions were generally satisfactory, and there was enthusiasm for the very low 1-2 ppmv NO2 emissions. However, theIt was still great uncertainty in regard to long-term operating costs. So far, fuel cells had been purchased. by utility R&D departments, and it would be necessary to convince commercial departments of their operating economics and utility in the future.” Another report loo indicated that generic operating experience with dispersed PAFC fuel cell systems in Europe was generally satisfactory in 1993, and improvements were required to BOP, rather than to the cell stack assemblies (CSAs). It was stated that certain components in the PC25A were difficult to access and maintain. The PC25A had a specific power of 2.6 kW/m3 (7.3 kW/metric ton), whereas the corresponding figure for the Fuji Electric FP-50 was 4.9 kW/m3 (10 kW/metric ton). Footprints required reduction without compromising maintainability (the PC25C will have specific power figures of 4.0 kW/m3 and 11 kW/metric ton). Control systems must also be adapted to individual customer requirements (c.f., comments on the Sydkraft FP-50, above). The need for available heat to operate absorption chillers was also emphasized. 100 The necessity for the equipment to correspond to European technical and safety standards was continually stressed (see CLC-Ansaldo, below).77*100 The PAFC could be designed to produce 170°C steam,* an ideal temperature for double-acting absorption chillers in the commercial sector. This is the plan for CHP in Japan, where (c.f. review of PC25A, above) Toshiba was modifying PC25s to produce steam rather than hot water.93@0@1 Other Japanese developers are also developing steam-producing PAFC equipment (see later). While the PAFC would have to have an installed cost of less than $1,700 (1995) per kW to compete with small gas-engine equipment in Germany, it would benefit by being exempt from the German NG tax of 0.36 DM per 100 kWh (about 64 $/GJ or 67 e/MMBTU, 1995). This would effectively increase its efficiency advantage. The Baverian Solar Energy Project (Solar Wasserstoff Bayem, in Neunburg vorm Wald, 180 km from Munich), a partnership of Bayemwerk AG (60%), BMW, Daimler-Benz/Deutsche Aerospace Airbus (DASA), Linde AG, and Siemens AG (10% each) was founded in 1986. It had 250-280 kW of amorphous silicon photovoltaic panels, a 50 kW MBB electrolyzer, and included an 80 kW nominal (79.3 kW dc, 7 1.1 kW ac on NG) Fuji Electric - KTI PAFC cogeneration system which could operate on hydrogen or NC. The cathode was also capable of operating on 50% oxygen-enriched air, which would have allowed 48% (dc) LHV efficiency using hydrogen fuel. It was first expected that the PAFC plant would operated in late 1991 after completion of PAC testing and the installation of the stacks. 12 The latter were tes.ted at Fuji Electric Company in November 1990, but a 10% degradation in performance occurred while they were in storage up to the spring of 1993. The system was intended to be operated in late 1993,*w and after a large number of problems concerning peripheral equipment, it was operating in 1994. PAFC Developers: Anticipating a large mature European PAFC market, Ansaldo srl (Genoa, Italy) announced in 1992 that it had established CLC srl, a company with exclusive rights to ONSK’s 200 kW PC25 for Europe.l2O The license covered units up to 1 MW. CLC-Ansaldo intended to manufacture a European&d PC25 to different standards from those of the U.S. model, to comply with differing European standards and regulations. In the first year of operation, however, CLC planned to import complete PC25s from the United States. In the second year, European-manufactured BOP would be used with CSAs imported from IFC-ONSI. Following this, complete stacks would be manufactured in Europe for integration with European BOP. By 1994, European graphite vendors had been identified, and stack parts were being manufactured by CLC-Ansaldo. A 50% efficient hydrogen-powered unit was on offer at $Z,OOO/kW (1994 dollars) in the summer of that year. lzl The prototype of the Europeanized PC25 200 kW pre-packaged PAFC plant was constructed starting in mid-1993. It used parts which complied with European technical and safety standards, and which were as far as possible those which could be obtained on the European market. It was equipped with an ONSI-supplied stack, but most of the BOP components * The PC25 is optimized to produce 74’C hot water. degrade its electricaJ efficiency.

Steam production will require design compromises,

which will somewhat

574

A. J. Appleby

were of Italian manufacture. Significant differences compared with the ONSI PC25 were in the pressure vessels, which were designed and manufactured in Italy to comply with European codes, in the use of advanced Italian inverter electronics, and in the completely redesigned control system. By mid-1994, the prototype was undergoing testing.rr6 Since 1992, Siemens AG (Erlangen) has studied the development of cogeneration turn-key PAFC units in the l-2 MWe class in a joint venture with potential users, using technical input under an information exchange agreement with the Fuji Electric Company. These systems would be “market openers” for other fuel cell technologies. Stacks would be supplied by vendors, for example, IFC, Ansaldo, Fuji Electric, or Mitsubishi Electric, with Siemens supplying BOP. Partners in a joint feasibility study on plant design, control systems, and licensing arrangements were GEW-Kbln (17%), Ruhrgas A.G. (8%), Thyssengas Gmbh (SS), and Siemens KWU (67%). The plants produced electricity at lo-15 Pf/kWh (7-10.5 e/kWh). While PAFCs over 10 MW operating on natural gas were unlikely to compete with gas turbines, Siemens was interested in the potential of 10 MW units operating on hydrogen-rich gas from chemical plants.r~z Diamler-Benz was studying the possibility of using hydrogen-fueled PAFC systems combined with electrolyzers for off-peak electrical storage, peak-shaving, remote distribution, and power conditioning as an alternative to lead-acid batteries.1” Italy, PRODE Project: Progress was reported on the 1.2 MW PRODE project unit for Milan. In 1987, it was intended that this should have four 260 kW Fuji Electric stacks operating at 5 atma pressure and 19O’C. However, design work was finished in 1990 on a unit which would contain two 670 kW lFC stacks of PC23 type, similar to those in the 11 MW plant in Goi, Japan, operating at 8.2 atma, 207’C. Ansaldo, the designer, tested the self-commutated GTO inverter in 1990. Plant specifications were 1.15 MW ac power rating, and 1.16 MWn., cogeneration heat, 40% LHV efficiency on NG, operating range standby and from 30% to 100% of rated power, and less than 10 ppmv N02.r24*125 The fuel processing system was designed by Haldor Topsoe, and the twin turbochargers by ABB. The twin Ansaldo inverters had 55% voltage tolerance, ~5% harmonic distortion, and +l% frequency tolerance. Construction started in May 1991, with completion in late 1992. 126 The unit started operating in the late summer of 1993. While no published progress reports were available at the time of writing, sources in January 1996 considered its performance history to be excellent to date.

Toshiba (R&D Center and Works, Kawasaki ), Toshiba’s PAFC commercialization plans included the investment to IFC to establish ONSI, and the building of a 1 m2 stack production facility, both in 1990. Commercial Toshiba electric utility PAFC plants were to have a 0.09 m2/kW footprint to allow installation for example in the basements of downtown buildings, 127and a 1.1 m3/kW volume. It would have a larger stack than the PC23 (1.1 MW compared with 670 kW), and a transportable reformer in the 11 MW class.128 The manufacturing facility for the improved PC25 was described in 1992. Units were expected to be commercially available in 1993, and would contain a compact, low cost reformer with a lower steam-tocarbon ratio than that of ONSI PC25 .lzs It was later specified that the ratio was to be reduced from 3.2 : 1 to 2.5 : 1, which still allowed stable reformer operation. This made more steam available for cogeneration use,g3 e.g., for absorption chillers .93~roe~ror Toshiba shared the development and manufacture of the reformer and electrical subsystems of the 56 PC25As delivered by ONSI. It was actively pursuing cost and weight reductions with ONSI on these and other components. The first Toshiba-manufactured PC25 was delivered to the Kawagoe Power Station of the Chubu Electric Power Company in December 1992. It had accumulated 14,131 operating hours by March 1995. ssb The performance decay rates of the CSA of this unit and that of the replacement Toshiba CSA for the PCX-2 unit at Shiba-ura have been reported. During the period between 4,000 and 10,000 operating hours (at Kawagoe) to 14,000 hours (at Shiba-ura), a negligible reduction in stack voltage was observed. The evaporation rate of electrolyte from the internal reservoir in each cell was uniform over the surface of the cell, and loss rates indicated that the quantities were sufficient for the 40,000 hour stack design life. Two PC25s supplying steam were delivered to Osaka Gas and to the Tokyo Electric Power Company in 1994. It was expected that the Toshiba-built PC25 would be later modified to use other fuels (e.g., naphtha, kerosene, LPG), as well as biogas from sewage treatment (c.f., Refs. 30, 108, 109). Toshiba was also manufacturing a 1 MW on-site atmospheric pressure unit in work supported by the PAFC Research Association.93 This is described below. Fuji Electric Company (Yokosuka R&D Center, Kanagawa): Indigenous Japanese on-site systems have been intensively tested since the late 1980s. After the tests of 1 MW units in the mid-1980s, the two companies chosen for demonstrations of the “low-pressure low-temperature” units (i.e., 3.4 atma, 19O“C. Fuji Electric and Mitsubishi Electric)6 were able to take a lead in indigenous atmospheric pressure on-site units, compared with their competitors for the high-pressure high-temperature systems (8.2 atma, 205OC, Toshiba and Hitachi).6 Fuji Electric’s work has been centered around the 50 kW FP-50 system.ja Fuji Electric’s stacks for these PAFCs are water-cooled. We should note that a 50 kW-class dielectric liquid-

Fuel cell technology

575

cooled Fuji Electric stack (see early 1980s development by Engelhard Industries, Ref. 6, p. 480) was proposed for the U.S. methanol-reformer bus project. This system was intended to operated at 38% LHV efficiency at a steam-to-carbon ratio of 1.5, and had a 40 minute start-up time. Its total weight was 1,550 kg, including 200 kg for the reformer and 583 kg for the 55.2 kW dc stack. Measured emissions were NG2, 0.5 ppmv, CO 30 ppmv. These are several orders of magnitude less than those for internal combustion engines.129**30 Fuji’s commercialization plans for on-site units are discussed in a following section. An early report on one of the early Fuji Electric FP-50 units (at Tokyo Gas) was given in 1990.131 This FP-50 unit started UP in April 1990, and had operated for 2,500 hours by the end of August of that year. The system used manganese dioxide instead of zinc oxide as a chemical &sulfur&. Its reformer was a compact single burner, single tube system, and it incorporated five heat exchangers in two units using plate and fin technology. It showed an optimum electrical efficiency of about 41% (LHV) when the total healt recovery efficiency was about 35%. The N@ emissions were 2 ppmv (7% oxygen, dry basis, i.e., 4 g/MWh).13’ A 200 kW version of the Fuji Electric power plant was designed to use methanol fuel for applications on the 300 inhabited small islands off the main Japanese coasts, in conjunction with diesel generators and photovoltaics. Its HI-IV efficiency was 39.7% at full load, 40.6% at 75% load, and 36.7% at 50% load. Its NO2 emissions were 2 ppmv, with negligible SO2. By August 31, 1990 it had operated for 3,600 hours and had produced 493 MWh at the Okinawa Electric Power Company location on Tokashiki Island.r32 By September 1993, it had operated for 8,449 hours. By November 1991, the Kansai Electric Power Company (KEPCO) installed six 50 kW FP-50 NG units on Rokko Island near Kobe under NED0 sponsorship for tests in conjunction with solar and wind power facilities. Eight more, together with a Mitsubishi Electric 200 kW unit (see following) were installed by March 1992. Operations were then scheduled at least through the end of 1993. By the end of 1991, utilization of the six generators had been around 85%, generating time had averaged about 5,000 hours, and average continuous generating time was about 1,200 hours. There were 187 operating stoppages, about one-third being in the electrical subsystem and two-thirds in the chemical-electrochemical elements of the system. Only 15% of outages were connected to the CSAs. Harmonic distortion was 4% at 1 km, and 67% at 10 km (c.f., Ref. 119). However, this could be reduced to 2% and 34% respectively by the addition of capacitors.133 By March 1994, the FP-50 units with the largest numbers of operating hours were numbers 1 (start-up June 1990) and 4 (February 1991) at Rokko Island, with 17,528 and 17,469 hours. Units numbers 2 and 3 (February and March, 1993) 15,976 and 15,750 hours, and three others had exceeded 10,000 hours.*5a By March 1995, unit no. 1 was at 23,518 hours, unit no. 2 at 21,139, unit no. 4 at 19,028, and unit no. 3 at 15,897. Except for unit no. 12, 9,892 hours, all had exceeded 10,000 operating hours.ssb The two oldest of the eight FP-50 units at Tokyo Gas (start-up in February and May, 1991) operated for 5,508 and 7,002 hours, and had shown 3 forced outages per 1,000 operating hours. They were no longer operating in August 1991. Later models (start-up in July and August 1992) had greater reliability, with 1.3 ostages per 1,ooO operating hours. These two had attained 10,990 and 10,970 operating hours in August 1994. Later versions showed even better reliability with less than 1 outage per 1,000 hours. About 31% Iof outages were in electrical systems, 16% in the CSAs (see above), 21% in the fuel processor, and 31% in water systems. Generic PAFC problems were stated to be clogging of filters with phosphate due to carry-over of phosphoric acid in the shut-down purge gas, air filter cleaning and replacement, and (as the most costly maintenance item) replacement of ion exchange resins in the water treatment system. Improvements in these items, in CSA durability, and in outage frequency were required in commercial systemstar At Gsaka Gas (a total of fifteen FP-50 units installed by March 1994), &QItwelve were operating in August 1994.102 The two 1991 units (start-up March 1991) attained 15,037 and 12,005 hours of operation.lp One of these reached 18,827 hours before termination in November 1994. The other had reached 14,884 hours in March, 1995.85b By August 1994, six operating units had exceeded 10,000 operating hours, the longest then being 13,762 hours at the Fuji Denki Office Building (start-up September 1991, longest continuous run, 2,644 hours, about 3 forced outages per 1000 operating hours). The unit at the Koshien Printemps Department Store (start-up, June 1993,9,090 operating hours in August, 1994, approximately 0.25 forced outages per 1,000 operating hours) had the longest continuous run of 4,865 hours.r02 The Department Store and Fuji Denki units were terminated in October 1994 and March 1995 at 11,638 and 13,891 hours, respectively. By March 1995, all operating units had exceeded 10,000 hours. That at the Hanky0 Head Office (installed March 1993) had the highest time, at 14,617 hotns.ssb The average forced outage rate of FP-50 units had been reduced to 0.8 per 1,000 operating hours (about twice that of the PC25A). Similar observations to those at Tokyo Gas were made on the life of ionexchange resins, which varied greatly according to operating conditions. It was noted that microorganisms sometimes proliferated in the water treatment systems, which required system changes.102 Operating experience with an FP-50 unit installed in mid-1993 at the Korea Electric Power Corporation was given in 1994. Emissions were 1 ppmv for Ne, and noise at 1 m was 62 dB.134 Two 50 kW Fuji Electric units (delivered in 1989 and 1990) were operated on desulfurized naphtha at Idemitsu Kosen Co. They used Co-Mo/znO and Cu/ZnO &sulfurization and shift catalysts, but requited Ru/Zr@ reforming catalyst to prevent the carbon formation which deactivated Ni-based catalysts in a few

hundred hours. The catalyst would operate well even at the theoretical steam-to-carbon ratio of 2, but the practical scaled-up system used 2.5-3.13s

516

A. J. Appleby

Information on larger Fuji Electric on-site systems (100 kW, 500 kW) is given in the subsection describing On-Site Plans, below. Mitsubishi Electric Company (R&D Center and Works, Amagasaki, Hyogo: MELCG is the other Japanese developer of indigenous on-site units. A 1990 review of development work shows the improvement in stack performance and stability as a function of time.136 Average decay for MELCO water-cooled PAFC stacks in 1990 was less than 2 mV/lOOOhours, with a 7% reduction in performance expected at 40,000 hours (from 0.65 V to 0.60 V at 0.20 A/cm2, 1 atma, 20S°C, 80% and 50% fuel and oxidant utilizations). The same report gives data on the 100 kW methanol-fueled pilot plant for use by the Hokkaido Electric Power Company on isolated islands. This had operated for 4,575 hours (330 MWh) to August 1990. Its total LHV efficiency was 87% (40% electrical, 41% at beginning of life). It had been subjected to 245 stop-start cycles, with a start-up time of 2 hours (cold) and 1.5 hours (hot). Its load following ramp rate was 30% per minute, twice the requirement, and its NO2 emissions were under 1 ppmv. The 1989 version of the 200 kW MELCO unit at the Plaza Hotel in Osaka had measured NO2 emissions of 4 ppmv at 7% oxygen in the exhaust, with negligible SO2 and particulates. Testing started in March 1990, and by the completion of the government-industry and private tests on October 31, 1991, 13,038 generating hours (1,797 MWh) had been accumulated, with 60 start-ups and a maximum continuous run of 2,656 hours. Its electrical efficiency was 40.0% (LHV) at full load (89.5% total), and 35.0% at 25% load (76.0% total). Performance degradation was very acceptable (less than 5% over the total operating time, and 7% projected to 40,000 hours). tsr*t3s The unit reportedly weighed 25 metric tons, allowing considerable room for weight and volume reduction. 4s Further 1992 technology reviews139st40showed a 50% increase in current density (to 0.30 A/cmZ) in subscale (100 cm2) cells, which was to be confirmed in 0.36 m2 stacks. The compactness of the 200 kW on-site unit was improved from the 0.16 m?kW of the 1989 version, which operated at 0.15 A/cm2 with a steam-to-carbon ratio for reforming of 3.5 : 1, through the 0.15 ms/kW of the 1991 version (0.20 A/cm2), to 0.12 mj/lcW (0.25 A/cm2, steam-carbon 3.0 : 1). and finally to 0.08 m3/kW (0.30 A/cm2, steam-carbon 2.5 : 1) expected in 1996 and beyond. The improvement in steam-carbon ratio would raise the output of 17O’Csteam successively from 18%, to 21%, then to 25%. All plants after 1992 were to have fully automatic control systems. It is recalled that the ONSI PC25C has a 0.08 m2/kW footprint. Early PC18s had a value of 0.2 m2/kW, whereas the values for PCXs and PC25As were 0.2 and 0.11 m2ikW. Current Fuji Electric systems have footprints of 0.1 m2/kW.too The proposed 1 MW Toshiba atmospheric pressure system will have the same footprint (see below). By March 1994, four 200 kW MELCO units were in operation. They were at the NED0 site at Rokko Island (start-up February 1992, then 14,504 hours), at the Chugoku Electric Power Company’s Yanai Power Station (May 1993,4,416 hours), at the KEPCO Research Institute (June 1993, 3,607 hours), and at the TEPCO Kyobashi Center (February 1994, 477 hours). *sa*t4r These units had attained 18,428, 8,497, 6,310, and 6,998 hours by March 1995.8Sb TEPCO Goi II MW: Specifications of the 11 MW Toshiba system at Goi, Chiba Prefecture, which uses IFC stacks of the type developed for the PC23, am given in Ref. 26, and measured emissions (1 ppmv NO2) in Ref. 27. However, later reports simply stater42*143“less than 3 ppmv.” The objective of the plant was to demonstrate a large cogeneration plant, verify performance of its components, clarify its operational characteristics and environmental acceptability, and determine what would be needed for reliable automatic operation. The plant was based on the PC23 system, using IFC CSA technology (sixteen 670 kW stacks) and system design, Toshiba site engineering and Japanese BOP. Construction started in January 1989, and the plant was completed in 13 months. The process and control (PAC) test was conducted without the cell stack assemblies (CSAs) from June to November of 1990 in only 82 days (2.7 months), instead of the planned 128 days, which was considered to be a great advance. For example, that for the TEPCO Goi 4.5 MW unit in 1983-85 took 12 months .t‘t*~*~~Preparations for the PAC testing have been described.r‘t4 The plant reached rated power in April 26, 1991. The HHV efficiency was 43.6% (gross ac, 41.8% net) at 11 MW, 41% at 7 MW, and 35% at 4 MW. These figures are about 0.7% greater than specifications. In July 1991, a continuous run of 875 hours at an average load of 70% was conducted. During this period, the voltages of all 16 stacks were very uniform under load. By the end of August, 1991,10,263 MWh had been generated. At the end of August, 1992, the system had operated for 4,041 hours (23,435 MWh), with a longest continuous run of 1,173 hours, and with 16 start-up cycles. Waste heat was used to air-condition the control building in a cogeneration demonstration.ra Specific problems which developed in 1991 included a vibration-induced breakdown of the recycle blower impeller, which was replaced with a heavier damped part, a GTO failure in the inverter due to negative electric bias at low load, which required a higher bias voltage, a controller circuit board failure, which required enhanced dust and moisture protection, and erosion-corrosion-induced water leakage in heat-exchanger bypass piping, which was replaced by stainless steel. A major failure was corrosion of graphite in six of the CSAs, which was shown by an insufficient voltage rise during standby-to-transient operation. This caused leakage of the external purge gas into the reactant stream. The reason was the use of reformer burner exit gas as the purge, which was intended to save the cost of using nitrogen. This gas contains small amounts of oxygen, CO2, and large amounts of water vapor. Clearly, it was capable of

Fuel cell technology

511

causing corrosion under pressurized PAFC operating conditions, where graphite is locally operating at its corrosion limit.8 As a result, nitrogen was being used as the purge gas, and the system is currently operating at 67% of design capacity with six CSAs disconnected. Outages have been rare apart from the above problems. Inverter and reformer operation was satisfactory, and operation has shown how improvements might be incorporatedl~ Encouraging news was that the operating stacks showed much less than the specified decay :rate for the first 500 hours, so that the total voltage and efficiency loss over an operating period of 40,,000 hours extrapolates to 74, rather than 10% i.e.., effective stack life to 37.6% net efficiency may be 100,000 hours, rather than the 40,000 anticipated, provided that a sufficient supply of electrolyte was in place. The system was to continue operation, but in 1992, there were no plans to replace the defective stacks.143 By March 1994, the plant had operated for 9,272 hours .ssa It had reached 12,960 operating hours in March 1995.85b On-Site Plans: Impressive aspects of Japanese PAFC work were the numbers and scale of precommercial testing, the planned number of equipment manufacturers. In the United States during the 197Os-198Os, about 2 MW in 40 kW units had been tested, the 1 MW brassboard system had been operated at UTC, and the 4.5 MW unit had been installed in New York City, but not operated as a generator. In contrast, Japan had operated four large projects with a total of 16.5 MW, plus 25 smaller units, at electric utilities from 1983-92, giving a total of 19.7 MW. r4s Fuji Electric’s commercialization plans have been reviewed several times.36*146*147Orders for FP-50 units had reached 31 by 1990, 27 of which were for Japan, and the four units previously indicated for Europe, with one for Thailand. Sixteen units were then being installed at Rokko Island (KEPCO), and the remainder were for Tokyo Gas (four), Osaka Gas (four), and Toho Gas (one). The three gas companies, as a consortium, had options on 50 more.148 By the end of 1991, 32 Fuji Electric on-site units were installed, totaling 2.4 MW.i& Fuji Electric’s packaged 50 kW and 100 kW on-site cogeneration plants in place or planned totaled 85 at the end of 1992, with a total capacity for precommercial demonstration of this technology equal to 4.35 MW. They included units operating on naphthas6siss and LPG for remote-site use.s6*147 By March 1994, 48 FP-50 units were operating in Japan, 14 of which were at Rokko Island.~*r4t The highest operating time (for the oldest Rokko Island unit, which started operation in June 1990) was then 17,528 hours.85a “As we move to commercialization with an increasing number of precommercial PAFC plants achieving satisfactory operation, Fuji Electric is confident that the PAFC will become a commercially viable product in the not too distant future.” 36 The target cost would be Y25O,OOO/kW.149 This is $2,65O/kW at the Septe:mber 1995 trading exchange rate, and $l,775/kW at the PPP rate. MELCO planned to build units totaling 200 MW by the year 2000. These would include units with 1 MW-class reformers and 500 kW to 1 MW 0.8 to 1.0 m2 stacks. These were in course of development in 1991. Very long-term tests (to 16,000 hours) were conducted on 0.36 m2 stacks, without acid replenishment. These had shown ca. 10% voltage decay at 0.15 A/cm2. This had been reduced to 20 mV per 10,000 hours in later stacks.139 Demonstration plans for on-site units by gas companies (Tokyo Gas, Osaka Gas, and Toho Gas) have been summarized,r49 as well as those at electric utilities .*45 In early 1992, it was predicted that electric utilities would introduce about 30 PAFC units in the 50-200 kW class by 1995 as a first step to building up to more than 1 GW by the year 2000.1so In reality, their rate of introduction has been much slower. At the Tokyo Gas, Osaka Gas. and Toho Gas consortium, eighteen FP-50 units were to be in test operation by the end of 1992, with 7 more expected. Market introduction was then expected in 1993.151Brs2 By March 1994, nineteen were operating.ssa*r41 Fuji Electric was continuously improving the performance of its on-site units. For exampl.e, the stack power density had been successively increased from 0.1 W/cm2 in 1989, to 0.16 W/cm2 in 1991, and to 0.2 W/cm2 in the 1992 “precommercial” model .I46 In addition to the FP-50, Fuji Electric had also produced a 100 kW FP-100 on-site unit .t49*rs2 Its specifications were similar to those of the FP-50, but it could deliver 20-25% of its cogenerated heat as 160-17O’C steam, rather than entirely as hot water.10t*t52 Four of these were to be in operation at the end of 1992, with about 16 expected, with commercial introduction expected in 1993. Three were operating by the end of 1992, and thirteen were operating in March 1994.asav141 Of the four FP-100s operating at Tokyo Gas in August 1994, the oldest (start-up July 1992) had then attained 9,263 operating hours. As with the FP-50, 1993 models showed a lower incidence of forced outages (1.7 per 1,000 operating hours, the same as that of the company’s 1993 PC25As).ro1 Five units were operating in March 1995, the oldest having logged 9,977 operating hours.sSb The oldest of the eight units at Osaka Gas (start-up April 1992) had attained 9,451 hours (longest continuous run 2,334 hours) by August 1994. The forced outage rate had fallen to 0.8 per 1,000 operating hours for 1993 units, down from 1.5-2 in early units. toa In March 1995, 11 (out of 14) were operating, the highest time unit (at Osaka Gas) having 13,237 hours.asb Two of the improved PC25 units for test at Tokyo Gas-Osaka Gas were manufactured by Toshiba in 1993, and several further units were to be available in 1994.9a*rs2 One was operating in March lgg4.ss0tr

578

A. J. Appleby

Fuji Electric was manufacturing two 200 lcW units for Osaka Gas in 1993, and MELCO was also developing improved 200 kW units. Finally, Fuji Electric had developed a 500 kW unit, one of which was in operation in 1993 at the Torishima works, with two others on or&r for the Asia Taiheiyo Trade Center. These were installed in March 1994.ssp*14tThe two Trade Center units had attained 1,948 hours (longest continuous run 1,127 hours) and 1,080 hours by August 1994.101 In March 1995, the three units were at 9,846, 3,123. and 3,123 hours respectively. *sb The specifications of the 500 kW atmospheric pressure unit (0.8 m2 active area) have been given.*sssls4 Osaka Gas had 32 PAFC units on test in March 1994 (15 x 50 kW, 8 x 100 kW, 3 x 500 kW Fuji Electric units, and 6 x PC25A~).85~~141 However, in 1992 it had been expected to have 41 units totaling 5.75 MW in operation by December 1993 (17 x 50 kW, 8 x 100 kW, 3 x 500 kW Fuji Electric and 13 x 200 kW units from three sources).tsz PAFC Research Association: The PAFC Research Association (PAFCRA, a consortium of Tokyo Gas, Osaka Gas, Toho Gas, and Saibu Gas, along with ten electric power companies, and NEDCYMITI) sponsored a six-year program at Toshiba to design and build a 1 MW NG PAFC atmospheric pressure unit intended to operate in 1995-96.rst*tsz The unit was to operate at an electrical LHV efficiency of 240%. and an LHV heat recovery efficiency of 240% (steam 25.5%, hot water 14.5%). The footprint of the 3.6 m high plant is CO.1 m2/kW. It has two 414-cell, 500 kW 1 m2 stacks operating at 0.25 A/cm2 and at 2OY’C, and a single multi-tube reformer operating at a 2.5 : 1 steam-to-carbon ratio. It will produce 25.5% of total HHV energy as steam. Manufacturing started in 1993, with field-testing proposed for 1995-96 in Minatoku, Tokyo.*ss Instead, installation was at the Tokyo Gas Tamachi site. By August 1994, all components had been delivered, and process and control (PAC) tests were in progress in mid-1994.93 Testing started in March 1995.*5b The PAFCRA also planned to develop the three-story NG Fuji Electric PAFC units in the 5 MW class.36~141~147~1s1,152,155,156 These would have a 0.8 m2 cells arranged in 6 CSAs (connected in two parallel strings, each with three in series to inferface with the inverter) and a single monotube reformer of Haldor Topsoe design, licensed to Kobe Steel. It would operate at 0.30 A/cm2 and 0.75 V at 6 atma and 2OO’Cwith an electrical efficiency of 46.6% LHV, and a total efficiency of 78%. Its footprint would be 0.27 m2/kW. It would use the advanced desulfurization catalyst developed by Osaka Gas (see below) to improve efficiency, and would have an inverter with 300 A, 600 V IGBTs developed by Fuji Electri~.r~~ Testing was to take place at Amagasaki in Hyogo Prefecture. lss#6 The schedule was originally intended be the same as that for the 1 MW unit, but it was interrupted due to technical problems with certain subsystems. Testing of short stacks for 10,000 hours took place during 1992, to ensure that voltage decay would be less than 10% over 40,000 hours. By 1993, the system was complete except for the stacks, and the PAC test was in progress (but delayed) during 1993-94.156 Operation started in March 1995.ssb

New Developem: MIT1 and NED0 were encouraging Hitachi Ltd. to re-enter PAFC development and manufacturing, in view of the size of the anticipated market. Hitachi expected to use an improved stack with a ribbed bipolar plate with porous ribs (see Ref. 6, pp. 518,531, 535).ls7 Other recent developments applicable to PAFCs for stationary applications include systems operating on light petroleum fuels,ls8 and systems with fuel flexibility for telecommunications use. rss*t@~Work in Japan on improved reformers has also been described. These include a much improved desulfurization catalyst taking sulfur down to ppb, levels at Osaka Gas to prevent any carbon formation on the reforming catalyst at a low (2.5 : 1) steam-tocarbon ratio. This allows the production of more waste high-grade waste heat. Both the reformer and the shift converter are improved in compactness. 161*162New developments in the efficient and compact Haldor Tops@e heat exchange reformer were reported from Japan163and Denmark.164 This has an exit gas temperature under 600°C and the capability of being sized from 100 kW to 30 MW, and has been operated at steam-to-carbon ratios down to 2.5 : 1.r64 It is to be used with the Fuji Electric 5 MW system.163 Testing to verify varying steam-to-carbon ratios and NO2 production under pressurized conditions has been conducted .]a,164 The latter was 50 ppmv when the burner effluent was passed into the combustion air supply, and was about 10 ppmv when lean fuel and lean oxidant were used.163 An advanced desulfurization process is being developed at Osaka Gas to replace conventional hydrodesulfurization catalysts such as Ni-Mo or CO-MO,followed by a ZnO absorption bed. Under favorable conditions, these can reduce sulfur concentrations to 20 ppbv, but slow poisoning still occurs. The new process uses an oxide-supported metal catalyst which requires much less hydrogen than conventional &sulfurization. The process reduces residual S to the ppbv level, and operates most effectively at 200”-300°C, but it will work at room temperature. The process decomposes inorganic and organic sulfur compounds, even thiophenes, without cracking hydrocarbons, so no carbon deposition occurs.tu The new process can be combined with reforming using new, very durable catalysts which allow operation at a steam-to-carbon ratio of 2.5 for greater PAFC efficiency and the ability to raise more steam.166 Other reported developments were improved motor-driven control valves for PAFC systems,‘” and air-bearing turbocompressors from Kobe Steel sized for the 5 MW system. They operate at 25,000 rpm, and have an efficiency of 74%.r6g

Fuel cell technology

579

Concl~lsions: The rate of development of the Japanese PAFC industry, which has been greatly helped by the “Total Development” philosophy, 84has been most impressive. A good overview of PAFC fuel cell systems as seen from the Japanese viewpoint up to mid-1993 was given in 1994.1a9 In August 1994, 87 units totaling 20.8 MW were installed in Japan (including the complete complement of stacks at Goi). However, of this 14.4 MW had been supplied by IFC-ONSI. I41 Total IFC-ONSI PAFC parts production to date (including the 11 MW Goi unit) is about 39 MW. On an absolute basis this is very small, about the same total power as that of a single large aeroderivative gas turbine. By September 1995, a number of indigenous Japanese PAFC on-site units had exceeded half of their CSA design lifetime of 40,000 hours. For example, the two oldest Rokko Island FP-50 units had reached 24,000 and 21,000 hours. Operating time on the MELCG 200 kW unit at Rokko Island was 18,000 hours. The 200 kW Toshiba stack in the PCX-2 at Shiba-ura had exceeded 20,000 hours, and the BOP had exceeded 35,000 hours. Finally, the 11 MW Goi plant had reached 16,000 hours. Information updating Ref. 85a, giving the PAFC units in operation and their hours of service to March 1995 became available in late 1995.*sb The longest continuous run on a Fuji FP-50 unit was 7,200 hours. Twelve older FP-50 units had been terminated (one at the Shikoku Electric Company, May 1992-March 1993, 16,317 hours), two at Tokyo Gas (May 1991~October 1994,7,003 hours, and January 1991~October 1994, 6,827 hours), and nine at Osaka Gas (oldest March 1991-November 1994, 18,827 hours). In addition, three FP-100 units had been terminated at Osaka Gas. In March 1995,92 PAFC units with a total of 24.75 MW capacity were operating in Japan, of which IFC had supplied 10.7 MW (excluding the non-functional stacks at Goi). The cumulative hours obtained on those operating and terminated were 1,135,595. 26. MCFC PROGRESS United States Energy Research Corporation (Danbury, CT): After evaluation of responses to the APPA’s 1988 Notice of Market Opportunity (NOMO), the MCFCs being developed by Energy Research Corporation (ERC) were selected as the most suitable technology for commercialization. As has been described in Section 16, ERC promised attractive capital costs for production volumes of 100+ MW per year production for plants operating at 50% LHV efficiency on NG, thus competing with the GTCC. ERC founded the Fuel Cell Commercialization Group (FCCG) in 1990 as a users’group. 45~1~~All ERC stacks are cross-flow and are externally-manifolded. Scale-up from the 0.37 m2 cells (4 ft2) in the experimental 20 kW directreforming stack which operated at the San Ramon, CA PG&E facility, to 0.56 m2 overall area cells (6 ft*) for the lOO+ kW stacks intended for the 2 MW Santa Clara plant has been recorded.“’ These stacks contain a built-in external compression system to maintain contact (see below). From 1988-1990. eight 2 kW short stacks with 0.37 m2 area were tested, followed by a 5 kW indirect internal reforming (IIR) stack with similar cell areas. This was tested successfully for 5,000 hours, during which time it was given three thermal cycles. A subscale 5 kW, 60-cell stack was built and tested to determined issues related to height. Two 8 kW stacks were then tested, one of which used IIR in reforming plates and operated on NG, while the other operated by direct internal reforming (DIR) in the anode chamber on simulated coal gas fuel containing some methane. ERC established the Fuel Cell Manufacturing Corporation (FCMC, Torrington, CT) to manufacture internal reforming CSAs (maximum capacity, 10 MW per year in three shifts), and the Fuel Cell Engineering Corporation (FCEC), to implement systems design and installation in 1990.170 The “simplified plant” was designed in collaboration with Fluor-Daniel, Inc. (Irvine, CA), using Jacobs Applied Technology for CSA packaging. By the end of 1990, the first 20 kW 0.37 m2 IIR stack had been completed, and a start had been made on a >2OO-cell,100 kW-class large stack. Issues which were solved in fabricating large stacks included the close dimensional tolerances of components, distortion of hardware by thermal gradients, the application of ceramic coatings by thermal spraying, and the use of appropriate manufacturing techniques. Special 1.25 cm wide gaskets between the metallic manifold and the cells were used to control the migration of electrolyte (c.f., Ref. 41).171 Sheet metal parts of the bipolar plates consist of nickel-clad stainless steel between 0.375 and 0.5 mm (15-20 mils) thick, which is optimum from the viewpoint of cost-effectiveness.17z By the end of 1991, a 54-cello.37 m2 stack had been constructed and tested at both the ERC facility for 400 hours and then at PG&E’s San Ramon Site for 1,000 hours, after which it was again thermally cycled. It had one reformer plate per six-cell group. One 2 kW stack using 1988-1989 technology (0.37 m2, five cells) completed a 10,000 hour endurance test, 30% greater than its predicted life from an electrolyte loss model. This required a reduction in current density from 0.14 A/cm2 at 7,000 hours to 0.11 A/cm2. A 300 cm2, five-cell stack with optimized current collectors and manifold seals intended to accelerate electrolyte loss effects by a factor of 15 was given a successful 7,000 hour test. Using a full-size stack, it allowed a loss of 75 mV to be projected over 40,000 hours, mostly a result of increasing IR drop. A short stack had then successfully completed six thermal cycles. Following assembly of a simulator stack, a 234 cell, 0.37 m2 (4 ft2.0.325 m2 active area) 70 kW stack was constructed at ERCs R&D facility in 1991 for testing in 1992. Its height (3.5 m) was determined by

580

A. J. Appleby

the considerations for vertical transportation. 173 This unit (designated AF-100-l) was the first stack to incorporate both a lightweight sheet-metal manifold, and a pressurized bellows tie-down system. It was also the first operational stack to incorporate a flow distributor to equalize gas flow distribution between cells. These refinements are discussed below. During 1992, it was tested to 70 kW at fuel utilizations up to 76% on methane at an average cell voltage of 0.77 V (57% LHV efficiency). At 86% utilization, an LHV efficiency of 65% was attained Following these tests, it was shipped to the PG&E facility in San Ramon, CA (described in 1990174) for grid-connected testing on pipeline NG.175 Moving the stack by truck to California provided valuable experience in determining the necessary constraints uired, including limiting shock and vibrational accelerations to 2g. The 70 kW CSA was operated for 2, Zl hours, including 1,400 hours (33 MWh) grid-connected at the Pacific Gas and Electric (PG&E) facility at San Ramon, CA, in May, 1992. It operated at approximately 65% load during most of the test period, but it demonstrated nominal power at 0.12 A/cm2 at 0.77 V (71 kW). Between 0.06 and 0.12 A/cm2, it had a linear polarization curve with an overall polarization slope of 1.46 R-cm2.17s After the initial scale-up to 0.37 m2, ERC standardized on a 0.56 m2 (6 ft2, active area 0.50 m2) cell size for preliminary demonstrations. 175 Preliminary work and plans were given in 1991.45 The first large-area IIR stack constructed at FCMC contained 54 0.56 m2 cells (20 kW nominal). It was tested for 100 hours at ERC on NG, producing 32 kW (cell voltage 0.74 V) at 800 A (0.16 A/cm2). It was then shipped to the Destec Energy Corporation’s Plaquemine, LA gasification facility,l7a where it was operated for 4,022 hot hours (1,800 hours on-load) on coal gas. It operated at about 26 mV lower cell potential than the value with NG on the lower-BTU fuel. It gave 0.77 V at 660 A (about 0.133 A/cm2), and had a polarization slope of only 0.95 R-cm2 in the current density range between 0.06 and 0.16 A/cm2. Metallurgical testing was conducted after stack tear-down at ERC in 1994, where it was demonstrated that component corrosion rates were consistent with data obtained on NG, and that corrosion and electrolyte losses would permit a 40,000 hour stack life. A 0.2 kW laboratory stack from ERC was tested during 1992-94 for 11,000 hours at RWE, Germany, on Winkler gasifier product, including the expected contaminants.177 In 1994, it was proposed that a CSA should be tested in Anoka. MN, for operation on landfill gas. EPRI notes that 749 U.S. landfills have been identified with a potential individual capacity greater than 2 MW, with a total of 6 GW. A stack may also be operated in the future on ethanol and biogas on Maui. The 2 MW (nominal) demonstrator in Santa Clara, CA was first proposed in 1990.17* Reports on the progress of design and construction became available in 1992. 179 The plant, planned with the collaboration of Fluor-Daniel, was to be a “simplified design,” eliminating heat exchangers to reduce cost. Because of the use of internal reforming, the system would behave as if natural gas is used directly. Thus, its gross effective LHV efficiency at 0.76 V and 0.75% fuel utilization is (0.76 x 0.75)/1.040 (54.8%), where 1.040 V is the LHV of methane. A d.c.-a.c. inverter efficiency of 97% and parasitic power losses bring the overall LHV efficiency to 49.8%, an attractive figure for a commercial system. The LHV heat rate of 6,850 BTU/kWh (49.8% LHV efficiency), was expected to fall in stages to 6,350 BTlJ/kWh (53.7% LHV) in a commercial 2 MW version costing $l,OOO/kW (1990) in a production run of 1,600 MW per year. An intermediate stage (400 MW per year) was expected to have a heat rate of 6,515 BTU/kWh (52.4% LHV). The demonstration unit was expected to cost $9,OOO/kW (1990). 17s The total cost of the project was $46 million (1992, fixed price),“9 including R&D and 10,000 hours of testing. The latter would include 9,000 hours of endurance tests, following 1,000 hours of acceptance testing to determine heat rate, power quality, noise, and emissions. The cost of the CSA modules was given as $16 million (1994), i.e., $8,9OO/kW (1994, fixed price) based on the net ac output of 1.8 MW. FCEC was the prime contractor of the plant, with Fluor-Daniel of Irvine, CA as subcontractor. A flow diagram and plant description are available. Fuel pretreatment included the elimination of higher hydrocarbons and hydrodesulfurization. The water required for steam was of conventional boiler-feedwater quality. tsea*b The specifications included maximum emissions of ~0.18 g/MWh NOz, cl.4 g/MWh S@, noise level of 60 dBA at 30 meters (compared with 60 clBA at 10 meters for the PC25A), >90% availability, ~40 hours start-up time,from cold, ~30 minutes from hot stand-by to operation, and reactive power (in MVAR) +/-1.67.r*Ob In 1992, 258-cell stacks were expected to be manufactured and shipped from the FCMC during the period late 1992 to early 1994. BOP procurement would be from the start of 1993 to mid-1994. Acceptance testing was (then) expected to be in the last quarter of 1994, with demonstration for almost two years starting at the beginning of 1995. The Bay Area Air Quality Management District (BAAQMD) had already granted an emissions exemption in 1992, and the State had declared a Negative Declaration under the California Environmental Quality Act, i.e., no events of environmental significance were anticipated.17a Commercialization issues required the FCCG members to acquire 20 units (40 MW), with expansion to 35 units (70 MW), with 30 MW of further precommercial units, leading to eventual delivery of commercial plants in 1998.18’ Stack definition and production took longer than anticipated, and ground-breaking for the Santa Clara plant took place on April 7, 1994. Direct participants in the project included the city of Santa Clara (host), utility departments of the cities of Los Angeles and Vernon, EPRI, the United Power Association (UPA, i.e., the National Rural Electric Cooperative, NREC), the Sacramento Municipal Utility District (SMUD) and Southern California Edison. Additional funds were from the California Energy Commission (CEC),

Fuel cell technology

581

the Northern California Power Agency, the city of Palo Alto, and the Arizona Salt River Project. Equipment was being funded by DOE, with co-funding from FCEC and Fluor-Daniel. A complex series of agreements was required, which included licensing intellectual property to FCEC until 2005, when commercialization was expected.t*s The utilities and FCEC were contributing $3.15 million each, EPRI $5.4 million and the city of Santa Clara initially two utility shares, i.e., $6.3 million, with the option to search for another partner. It was granted $0.65 million by the CEC to cover costs during BOP testing during 1995.*saa~a As Section 13 shows, a 1990 state-of-the-art MCFC would have been expected to operate at 0.73 V and 0.12 A/cm2 under “reference gas” operating conditions, i.e., on natural gas reformate at about 75% utilization and on air with 30% CO2 oxidant. 41 By using a number of important advances, ERC could obtain this performance on practical system oxidants (about 10% CO2) by early 1992. By 1993, the polarization slope had been improved to less than 1.0 Q-cm2 under system gas conditions (c.f., the 54-cell Destec stack, above). The performance of the 258-cell Santa Clara CSAs was expected to be 0.76 V at 0.133 A/cm2 at 75% fuel and 75% C&, 50% 02 oxidant utilizations (see Section 13). Each IIR CSA would produce 130 kW.tg3 The first 3.5 meter tall, 246-cello.56 m2 IIR stack of a series constructed and operated between early 1993 and mid-1994 operated at 0.83 V at 0.06 A/cm2, and 0.80 V at 0.12 A/cm2, i.e., at about the same voltages as the Destec stack. It was tested for 250 hours at 65% fuel utilization, including 100 hours at 123 kW (0.80 V at 0.125 A/cm2). This is considered to be baseline beginning-of-life performance. It was lost due to the development of an external short unconnected with the dc generation part of the stack. The next stack (AF-100-2) was tested during the fourth quarter of 1993, and showed similar performance, with the same very low polarization slope (about 0.5 Q-cmz) up to a current density of 0.11 A/cmz. It was operated for 1,800 hours, including 870 hours at 0.125 A/cmz, typically at 62.5%-65% fuel and C&-in-oxidant utilizations. Under these conditions, it showed a slightly higher polarization than the previous stack (117 kW versus 123 kW, i.e., 0.77 V compared with 0.8 V). It was given two thermal cycles, which had a very small effect on performance. At 1,632 hours, it was briefly operated at 0.14 A/cmz, at which it gave 0.715 V average cell voltage and an output of 123 kW. This corresponded to a considerably higher polarization in this current density range than the Destec stack, which (at least early in life) was capable of operation at 0.766 V under these conditions, and was still in the linear polarization region with a polarization slope of 0.86 SZ-cm2. This test served to establish the emissions of ERC stacks under real operating conditions as 0.04 ppmv N@ in the raw exhaust (0.35 g/MWh), with S& below the limit of detection (co.01 ppmv). The expected SO2 emissions in the exhaust (based on the residual sulfur in the feedstock, after desulfurization to 0.1 ppmv) was 0.005 ppmv, i.e., 0.06 g/MWh. Thus, NO2 emissions were four times better than 2 MW system requirements, and Sa emissions were 20 times better. The fact that the combusted anode tail gas is passed over the catalytic cathode surfaces before exiting explains why the N& emissions (in g./MWh) are considerably below those of the PAFC, which vents raw lean reformer burner exhaust. The noise level from stack AF-100-2 was 60 dBA at 10 meters, the same as that of the IFC PC25A, and well within the specification for the Santa Clara system. Another 125 kW IIR* stack (AF-100-3) operated at a similar performance level to that of the first 246cell stack, giving 123.1 kW at 624 A (0.1253 A/cm2, based on an active area of 0.498 m2, which appeared to vary slightly in successive stacks). This corresponded to 0.802 V unit cell voltage, the same value as that for the fist 246-cell stack. Variations in voltage between groups of cells were within Z!Z 2.5%.lwa Earlier stacks operated at about 65% fuel and oxidant utilizations, less than the 75% powerplant specification. The final stack in the series @F-100-4) produced 197.1 V at a current of 660.1 A (130 kW), i.e., 0.764 V at 0.14 A/cmZ, in IIR operation on NG at 74% utilization (55% gross LHV efficiency) with dilute system oxidant (74% CO2 utilization, ca. 50% 02 utilization). *Mb The estimated polarization slope on this stack between 0.06 A/cm2 and 0.14 A/cm2 was 0.6 Q-cm2. These successive stacks have all been characterized by a series of improvements. The 234~cell70-kW stack (1991, AF-100-l) used a Belleville washer tie-down system. This occupied an external volume which almost doubled that of the stack itself, but most important, it gave a compression variation of +1.2, -0.7 kg/cm2. This was replaced by a compression bellows starting with stack AF-100-2, which showed a variation of only Xl.1 kglcm2. In early stacks, a flow maldistribution between cells was seen. For example, cells in the lower half of a 234-cell stack might receive up to 3% more flow than average, whereas those in the upper half could receive 2% less. This was corrected (starting in stack AF-100-2) by flow distributor hardware, which gave approximately -f:0.5% in 1994 for the anode side. At the cathode, a larger maldistribution can be tolerated, and this was held to f 2.0% in 1994 designs. The change with the largest technological impact is in temperature distribution inside the stack. Because DIR catalyst lifetime has improved, more reliance can be place on reforming in the anode area, which has been increased to about 25% from the previous 20%. This has allowed changes in catalyst distribution in the IIR plates, together with changes in IIR manifolding. Stack AF-100-2 showed a hot spot ??

Ref. 184a neglects to say that this was an IIR stack,

582

A. J. Appleby

at the anode-cathode exit comer of the cell, which was at about 650°C. The average temperature of the cell was about 620°C, with an area near 64O“Cclose to the anode inlet, towards the cathode outlet, which had an exit temperature of 595OC. The anode exit temperature was 604°C. An island in the center operated below 6OO’C. The thermal profile in a modified 20 kW system removed the hot and cold spots, giving a 3oOC improvement in temperature uniformity, and raised the anode and cathode exit temperatures to 651°C and 664’C. respectively. The temperature profile was adjusted by manifolding the IIR plates so that maximum cooling (i.e., maximum reaction rate) occurred at the oxidant/fuel exit corner, i.e., at the IIR fuel inlet, The higher average temperature enabled fuel utilization to be raised from 65% to 75% in later stacks, without loss in performance.rs4P The average temperature of the cell in stack AF-100-4 is given in Ref. 184b as 615’C. but this depends on the method of averaging used, the largest part of the area being at approximately 645OC. It used an inlet oxidant (i.e., also coolant) temperature of 585’C. The cell temperature at this side of 600-615’C range, with high spots up to 63O’C at the fuel inlet. On the oxidant exit side, the temperature varied from 645 C (fuel inlet) to 68O’C (fuel outlet). The temperature of the NG entering the IIR plate was 542’C, whereas that at the cell fuel inlet was 619°C. The average fuel and oxidant exit temperatures were about 639°C and 664OC, which limits electrolyte evaporation, which in any case does not go to thermodynamic equilibrium at the relatively high space velocities used. Cell performance was extremely uniform. This information,r~P*b together with that obtained in earlier stack testing over a total of 30,ooOhours to 1990, and a total of 80,009 hours to 1994,rrs~*7’suggested that excellent performance over the predicted stack lifetime of 40,000 hours could be obtained. Future systems were expected to operate at 0.21 A/cm2 at 0.76 V under the same conditions via careful control of internal resistance losses. This must be considered to be a remarkable achievement. Stacks for such systems were expected to be scaled up by ERC to about 0.8 m2, with about 300 cells, so that each CSA will &liver about 375 kW. The cost of balance of plant for future 2 MW units, with a 20% discount for a run of 10, without extra engineering costs, was quoted at $800-9O%W. However certain stack components, particularly the pressurized gas bellows, represented a major proportion of CSA cost. This would require careful attention in future. lr@ Commercialization issues required the FCCG members to acquire 20 units (40 MW), with expansion to 35 units (70 MW), with 30 MW of further precommercial units, leading to eventual delivery of commercial plants in 1998. The commercial target cost was $l,OOO/kW (1990, $l,lOO/kW 1995). In 1994, the aim was to have orders for 50 units, of which 35 would be for FCCG members.170 Assuming that the Santa Clara 2 MW demonstrator successfully showed its performance goals, the group of 35 utilities had promised to purchase 35 units at $3 million each, corresponding to $1,67O/kW (net ac, current-year dollars).9sb Delays in the manufacture of 258-c& 0.56 m2 (130 kW nominal) stacks at FCMC and their delivery to the Santa Clara site have pushed back the operating schedule for the 2 MW demonstrator. Two-thirds of the stacks had been manufactured by the summer of 1995, and the first of four four-stack submodules had been delivered by the first week of November, 1995 after pressure-integrity and electrical-integrity testing at FCMC. Delivery of the second and third modules occurred in December, 1995, and that of the fourth module in January 1996. Operation was scheduled for March 1996.18’j In December 1994, ERC was awarded a $146 million contract (current dollars) by DOE to build and operate a 3 MW demonstrator at Fresh Kills, Staten Island, NY, hosted by the New York Power Authority. It was estimated that the system cost would be $40 million, i.e., $13,3OO/kW.*s6 ERC personnel have reviewed MCFC matrix and electrolyte materials,18’endurance issues (corrosion and electrolyte management),ts* and the effect of contaminants in coal gas on performance.rs9~190ERC is studying a military version of the MCFC operating on logistic fuels (JP-8, no. 2 diesel fuel) under the $11 million FY 1994 Advanced Research Projects Agency (ARPA) defense fuel cell power plant initiative. The objective is to develop a suitable fuel processor (with Haldor Topsbe) to operate with a 32 kW IIR CSA. Fuel containing up to 0.5% S (military specification VV-F8OOD,compared with 0.05% for new Clean Air Act regulations) is hydrodesulfurized, and scrubbed with ZnO. It is then reformed, methanated, and shifted to produce a high-BTU gas containing a large percentage of methane. This is performed in an adiabatic converter, so that the reactant and product gases have the same heating value per equivalent. Upconversion to hydrogen occurs using the waste heat from the IIR fuel cell. An on-site 2 MW system for military bases was proposed.rar MC-Power Corporation (Burr Ridge, IL): The other major U.S. developer, MC-Power, had a users’ group (the Association to Commercialize Carbonate Technology, ACCT) consisting of 44 utilities, three independent power producers, five industrial corporations, seven foreign members, and five industry associations, including EPRI and GRI. The company’s technology team consists of MC-Power (stack construction and testing), the Institute of Gas Technology (IGT, Des Plaines, IL, technology research and development), Bechtel Corporation (San Francisco, CA, BOP engineering), and Stewart and Stevenson (Houston, TX). The latter company specializes in the packaging and delivery of General Electric aeroderivative gas turbines for utility customers, and it will play a similar role for the MCFC power plant. The team members will be partners for all plant design, fabrication, and installation, and for future commercialization. MC-Power has a 8,000 m2 area stack manufacturing facility which includes very large tape-casting machines and large continuous-sintering furnaces. It was equipped with automatic stacking machinery in 1994.

Fuel cell technology

583

The company has standardized on an internally-manifolded. parallel-flow 1.0 m* cell of “Internally Manifolded Heat Exchanger,” IMHEX@ type. Unlike the designs of ECN (Netherlands) and IHI (Japan, atmosphericsee below), it is counter-flow rather than co-flow. In contrast to the internal-reforming pressure approach taken by ERC, the MC-Power system will use external reforming at 3 atma pressure. At the cell operating cell potential, internal reforming decreases the heat which must be removed from the stack by about 62-654 (see Section 6). Thus, external reforming requires a higher cathode gas circulation with a feedback loop, To increase performance and reduce piping requirements, operation is at 3 atma pn~ssure. After scaling up its internally-manifolded IMHEflM stacks from 100 cm* bench units to 1,000 cm* from 1988 to 1990, MC-Power then made progress on scale-up to cell sizes with an active area of 1.0 m2.192 From 1988 to 1991, IGT tested six successive 1,ooO cm* IMHEX@ CSAs, culminating in a 70cell version tested at MC-Power to check for any problems in vertical scale-up. This stack (MCP-2,70 cells, 1,000 cm*, 8.7 kW, 0.12 W/cm*) was tested in 1991 for 1,580 hours under EPRI sponsorship to determine lifetime issues, particularly electrolyte migration. This was found not to significantly occur in the internally-manifolded stack structure, which had no continuous gasket, therefore no carbonate film extending from the top to the bottom of the stack (c.f., Ref. 41). Full size rectangular 1.0 m* components were ready by early December 1991. They superficially resembled the IHI design (see below and Ref. 6, p. 451). but used triangular holes in the internal manifolding, with the point towards the internal parallel gas distribution channels. Testing of large components was to be supported by GRI. The ACCT commercialization program was supported by the Department of Energy, the State of Illinois, SCAQMD, San Diego Gas and Electric (SDG&E), Southern California Gas, Union Oil of California (Unocal), MC-Power, IGT, EPRI, and GR1.193 MC-Power’s general R&D is additionally sponsored by the State of Illinois, Niagara Mohawk, and Tenneco, Inc.194 MC-Power had operated 20 kW CSAs of different sizes for l,OOO-2,000 hours at atmospheric pressure by early 1994.1% The fiit full-area stack (MCPS) with 19 1.0 m* cells was tested during 199:2 for 2,000 hours, including two thermal cycles, including 1,300 hours of steady power output. An output of 22 kW was achieved, 10% greater than the design point. A second full-area stack (MCP-4.20 cells) was ready for testing by October 1992.195 Like ERC, MC-Power was able to register a considerable performance increase on the cell level from 1990 to 1993. On standard diagnostic reference gases (anode inlet 75% Hz, 25% CO*, 25%’H20, i.e., shifted naphtha reformate, and cathode inlet 30% CO*, 70% air) the overall performance of stack MCP-3 under counter-current flow conditions196 corresponded to the predictions of the 1985 Physical Sciences, Inc. (PSI, Andover, MA) numerical model. 19’ Its performance at 1,600 A (0.16 A/cm*) was 113.8V (0.73 V average cell voltage) at atmospheric pressure, with fuel and air utilizations of 75% and 50%, respectively. Its mean IR was 0.6 fi-cm2, and is polarization slope was 1.65 R-cm*. However, it showed lower performance on practical “system gases” (cathode at 9% CO*. 9% 02, c.f., the work reported at ERC, shown in Fim 3) than the PSI model predicted. Stack MPC-4 was started in late 1992, and had operated for 1,000 hours by May 1993. It was generally similar to stack MCP-3, but had a modified flow pattern to improve reactant distribution with a larger manifold area corresponding to the requirements for a 250-cell stack.l% Its components, like those of MCP-2, were relatively conventional (Ni-Cr anodes, in-situ oxidized NiO cathode!;, standard LiAlOZ/LiKCO3 matrix and electrolyte). Testing was to verify the semi-continuously manufactured components. the larger manifolding, and start-up and operating procedure. Start-up proceeded smoothly, with binder removal between 200’ and 400°C, and NiO formation was accomplished with no more than a WC temperature gradient across the cell surfaces. Some outboard leakage was detected. Th’e stack was tested for a total of 1,560 hours (777 hours on reference gases and the remainder on system gases). On reference gases, its performance was similar to that of stack MCP-4, and it had the same polarization s10pe.198p The results on system gases for stack MCP-4 corresponded to the predictions of the PSI model, giving an average of about 0.69 V at 0.16 A/cm* at 60% fuel utilization, with 9% Ca, 9% 02 in the incoming cathode feedstock.l% A similar stack, MCPJ, was operated for 500 hours (40 hours on reference gases and 100 on system gases). Its objective was to verify operation on wet system gases, to examine alternative fuel flow configurations, and to verify performance after hot hold, During start-up an accidental valve malfunction caused uneven binder removal, giving low performance. After 200 hours, the test was stopped for mechanical pressure repairs and the use of an external cement to eliminate a small outboard leak. This was successful, and performance then reproduced that of previous work after thermal cycling. This showed the ability of the IMHEX@ stack components to permit successful mechanical repair. The next 20-cell stack (MCP-6) used similar but continuously tape-cast components. This test was intended to verify these components, the use of wet system gases, the results of hot hold, and a new clampdown system. It was operated for 1,071 hours (533 hours on reference gases, 538 on wet system gases).l* In spite of using continuously-manufactured components, its IR drop was improved over that of previous stacks. At 75% fuel utilization on reference gases its performance at 0.16 A/cm* (based on 19 cells) was about 30 mV better than that of the previous stacks. 19&b Performance in early 1994 at 3.0 atma on system gases was 0.743 V at 0.20 A/cm*, at a fuel utilization of 75%, and oxidant utilization of

584

A. J. Appleby

30%. The goal was 0.80 mV under the same conditions. The constant utilization polarization slope was 0.83 f&cm2. In early 1994, it was stated that full size cells were expected to operate at 1.1-1.2 lcW at atmospheric pressure (0.69-0.75 V) and at about 1.3 lcW at 3 atma (0.8 V).tH Two more 20 lcW-class stacks to verify improved component technology were planned in 1995.1% These are discussed below. Like ERC, MC-Power favored a AISI 316L stainless steel sheet-metal thickness of about 0.5 mm. While SS310 may be more desirable from the corrosion viewpoint, it is less easy to form because of its higher chromium content. Maintaining tolerances becomes more difficult as thickness is further decreased, and due allowance must be made for the thickness of the scale which forms on the cathodic side of the bipolar plate (about 0.06-0.08 mm after 40,000 hours, Ref. 41). The channel size of the bipolar plate had been optimized for operation at 3 atma, although all 20 kW stack testing had been at 1 atma, since MCPower had no pressurized stack test facility. Materials savings were being examined in 1994, by the use of electrodes which were 0.5 mm, rather than 0.75 mm, thick. During 1992-1994, simplification of bipolar plate construction was examined, with the aim of producing a two-piece pressed structure (see below). The approximately 250-cell stack for the demonstration tests was to be 1.96 m tall. Because of the dimensions of the internal manifolding, the height of unit stacks was limited to 400 cells. In production units, the stacks would be integrated in the pressure vessel (which will be only about 3 mm thick) with the IHI flat-plate reformer.19 which may be licensed and built in the United States in the future. The reformer would have a volume equal to about 25% of that of the stack, and it is expected to cost somewhat more than 25% of the cost of the latter. Sulfur removal would use the ambient-temperature process and catalyst developed at Tokyo Gas, which avoids the need for hydrogen recycle (c.f., Osaka Gas, Refs. 161,162). About 5-10% of system power was expected to be ac from the turbocharger shaft. System simplification was a priority, for example, in the elimination of control valves.194 In 1992, it was hoped that a 250 kW demonstration would be started in Brea, CA, at the Unocal Fred F. Hartley Science and Technology Center in late 1993, with a second semi-integrated plant for the Kaiser Permanente Hospital in San Diego in late 1994.19s Design of the Unocal system was complete in October 1993, and in November 1993 its start-up was expected to be in April 1994. Start-up of the Kaiser Permanente demonstration was expected to be in January 1995.194 By mid-1994, the first 250-cell, 250 kW (nominal) stack had been completed, and a skid-mounted acceptance test facility had been constructed at MC-Power, which would perform bum-out, electrolyte impregnation, open circuit verification, and 25% load (400 A) testing at 1 atma. The speed of component production for the second stack was being improved by about 33%. and the bipolar plate had pressed, rather than laser-welded rails, reducing the number of metal components from 13 to 3.ra*a About 40% of the cost of the Unocal stack was the bipolar plate, and 30% of this was involved in welding. Approaches to lower cost would further reduce the weight and complexity of the bipolar plate, which was about 60% of the total weight (22.5 kg/m2) of the cell repeat parts. The welding cost had already been considerably reduced by using the 3-piece design. The next goal was a two-piece plate, and the ultimate goal a one-piece plate. About 75% of the total plate cost must be removed, which will then represent a reduction of 45% in stack cost. Simplified tape-cast elements (reduction from 3 matrix tapes and 2 electrolyte tapes to 2 and 1, respectively) is a further goal. In parallel, the power density would be increased.194 In 1995, a new separator plate concept which reduced material requirements by 30% and which further simplified welding had been developed. It incorporated the feed rails and one of the seal rails into the main stamping. The die was being modified to improve tolerances in the seal areas.19& Work on components for the Unocal plant in Brea began in April 1994. The Unocal unit had a conventional KTI reformer with an air-fired burner operating on NG (not anode effluent), in a unit containing the hydrodesulfurizer. Steam for reforming was taken from the Unocal steam loop, and steam generated from stack waste heat used this loop as a sink. The plant had a prepackaged BOP skid with the catalytic anode effluent combustor, turbocharger, cathode gas recycle blowers, cooler, and anode and cathode gas inlet electric preheaters. This skid was fabricated by Stewart and Stevenson. The 1.96 m high cell stack (on a separate concrete pad), had electric preheaters within the pressure vessel, and used 4 atm nitrogen in the pneumatic stack bipolar plate compression device. The pressure vessel was nitrogen-purged. The plant was operated by a distributed control system (DCS). The inverter was in a separate building.t99*~b Siting problems occurred at the Kaiser Permanente Hospital in early 1994, and in April, 1994, it was decided that it would be installed at Miramar Naval Station, starting later in the year. Both plants were sponsored by DOE, EPRI, GRI, with participation of the South Coast Air Quality Management District (SCAQMD), Southern California Edison, Southern California Gas, and Unocal in Brea, and SDG&E at Miramar. Tests of 4,ooO operating hours were expected.199a*b The Miramar unit was to be more integrated than the Unocal unit, and would incorporate an integrated steam supply. The IHI flat-plate reformer19 incorporated its own catalytic converter operating on anode off-gas. Instead of being supplied with air, the reformer would use cathode effluent as the oxidizer, giving higher efficiency and automatically maintaining pressure equality between the anode and cathode exit gases in the CSA.ra9 The BOP (desulfurization, turbocompressors, cathode recycle blower, cathode recycle cooler, and heat recovery) was again to be provided as a skid by Stewart and Stevenson. Other skids provided instrument air compression, purge gas storage, NG compression, and boiler feed water treatment. Again, the inverter was to be a separate unit. The plant was to occupy an area of 10 m x 20 m.194*199 By mid-1995, it was planned that the Miramar demonstrator would use two successive stacks. The first would use lower-cost separator plates compared with those in the Unocal stack, using the 3-piece

Fuel cell technology

585

components described above. The simplified plates and current collectors had reduced both the manufacturing time and cost of these components by 50% compared with that of the corresponding components for the Unocal demonstrator. 198~ By 1994, the technology for new low-chromium nickel anodes and new stabilized cathodes with low nickel oxide dissolution had been transferred from ET to MC-Power.lm Components were being routinely manufactured to the highest possible specifications. In 1992, cathodes had f 5% thickness variation, f 1.8% porosity variation, and f 0.3 pm in mean pore size.l9s Drying and sintering speeds had been doubled by changes in furnace atmosphere. The p:rocedures for tape-casting these components included a reformulation of the mixture used, which resulted in a tripling of tap-casting speed. Furnace modifications (completed in 1995) were required to sinter the new cathode. Components could be manufactured on a three-shift basis. 198b In consequence, the active components in the fist Miramar stack were manufactured in 50% less time than those in the Unocal stack, and a cost reduction of 20% was achieved by developing continuous manufacturing. The overall Miramar stack cost and manufacturing time were reduced by 40% and 50% respectively compared with that of the Unocai Stack. The components for the first Miramar stack were verified in the fifth 20 kw-class short-stack test in 1995. The second Miramar stack would use advanced active components (including low-chromium anodes and dissolution-stabilized cathodes) transferred from IGT and would use a further simplification of the separator plate. It would be the first to use Li-Na electrolyte (see below), which along with the improved cathodes should ensure 40,000 operating life. Again, its components would be verified in a 20-kW class short stack.l9*C The Unocal stack was qualified at the MC-Power Acceptance Test Facility198a in November 1994.198c Acceptance Testing involved heating to ensure binder burn-out and collapse of the stack components to their definitive height, with controlled oxidation of the cathode under the controlled conditions established in the start-up of short stack MCP-3. 198a Testing included gas- and electricalintegrity, open-circuit verification, IR verification, and limited low-power operation. Start-up of the Unocal Brea unit was delayed in June 1995, after an operational control problem resulting from instrumentation failure occurred, which resulted in a stack start-up malfunction. As a result the Miramar plant was expected to be the first to operate (in 1996). In December 1995, it was expected that the Unocal plant would be operated using a new stack. Which technology this would use was not clear. In November 1993, a 1 MW commercial “preprototype” was expected in 1997, sponsored by DOE, EPRI, Southern Cal Edison and PSI Energy. This would contain two CSAs because of the 400 cell height limitation. In January 1995, a three-year DOE contract for $104 million (current-year dollars) was awarded for the 1 MW demonstrator, which will be located at the Southern California Edison Highgrove Generating Plant in Grand Terrace, between Riverside and San Bernardino, CA. Operation was expected in 1997. Market entry with a modular 1 MW unit was expected in 1999. It was to contain four 400-cell istacks and the reformer in a horizontal pressure vessel. 203 This would be followed by production at about 20 MW per year, which approaches the commercial production range. The goal was a stack cost of $45O/kW (1995), of which the materials cost would be 50%, and a total installed cost of $155O/kW (1995) or less at 20-30 MW per year. One important market was for the compressors of gas pipeline companies.. who now work under environmental constraints, and require efficient machinery. 1g4 Deliveries of commercial IMHEXrM technology were expected in 1998.200 How the ImM system would be used by SDG&E up to the year 2010 was reported in 1992. The company planned 2,600 MW of new capacity, which will give the MCFC a broad opportunity in the form of 250 kW to 1 MW cogeneration units with distributed pollution-free generation which would avoid new transmission corridors.2o1 Further details of the probable distribution of cogeneration unit size were given in 1994. In two areas studied, 30 units co.5 MW might be required, with 28 units in the 0.5 t’o 1.5 MW range, and approximately 15 units in the 1.5 to 2.5 MW class. In larger sizes, the number required fell rapidly. For the best net present value, a cogeneration unit costing $1,5OO/kW with only 35%’electrical efficiency (e.g., a PAFC) was best sized to the thermal load, and would typically produce only Z!O%of the electrical power requirement of a model building. However, a 50% efficient unit with the same c:apital cost was more economic if it was closely matched to the electrical load. zo2This appeared to show that the cogeneration PAFC and MCFC may complement each other. Materials work and supporting studies by MC-Power partners have included an update on the use of copper anodes.zo4 However, copper may no longer be favored as a cost-reducing element in stack construction, because of the perceived difficulty of recycling stainless steel stack parts when copper anodes and cladding axe used. The basis of this argument is that stack hardware (nickel-clad stainless steel) can be directly used as an additive for the manufacture of new stainless steel. However, the scrap value of the hardware is small compared with replacement stack costs (perhaps $4O/kW depending on the weight of nickel per kW, and assuming its scrap value to equal 80% of the London Metal Exchange price). This is about the same as the change in materials cost if nickel is replaced by copper.205 Ref. 205 assumes that copper must be in the form of coated ceramic particles in the anode to prevent creep, as in work at the General Elecaic Company in the early 1980s (Ref. 41, p. 177). It correctly points out that such particles are likely to be costly ($5O/lb., compared with 90$/lb. for copper, and about $6/lb. for nickel). However, the use of electroless-plated deposits, or of copper alloys which can be dispersion-hardened at temperature, may be possible. This should result in much lower costs. If the IIR-DIR approach is used and if the anode itself serves as a reforming surface, one problem with copper may be its low activity as a reforming catalyst (c.f.,

586

A. J. Appleby

Ref. 41). As an alternative, conventional nickel-based anodes may be used with copper-clad bipolar plate sheet metal. This should be possible because interdiffusion rates between copper cladding and dispersionhardened nickel do not appear to be very rapid Lifetime issues, including nickel transport from the cathode, have received considerable attention at MC-Power’s partner, 1GT.m New approaches to the problem of the bubble barrier include a reformulated LiA102 matrix material in a reinforced matrix .207 The formulation has excellent electrolyte retention properties and shows little change in surface area with time. The excellent electrolyte retention properties of IMHEXTM hardware with the improved lithium aluminate,so7-sra together with improved larger-pore cathode structures allow better anode filling, so that the system is expected to contain sufficient electrolyte for at least 36,000 operating hours.207 The 20-cell IGT-6 1,000 cm2 stack with subscale IMHEX@ hardware was tested at atmospheric pressure on 75 : 25 H2/C02 at 38% utilization and reference oxidant at 30% utilization and 0.16 A/cm2. Testing started in February of 1992, and the stack reached 4,000 hours on August 6, 1992. Average performance was 0.747 V, with maxima and minima of 0.813 V and 0.661 V. There were 12 cells above 0.75 V. The average decay from 800 to 2,300 hours was 2 mV per 1,000 hours, and to 4,440 hours it was 7.1 mV per 1,000 hours. The cell with the lowest decay (Cell 9) actually improved by 3 mV per 1,000 hours to 4,440 h0urs.a’ The stack was tested to 7,163 hours with an average decay for all 20 cells equal to 18 mV per 1,OOflhours, and 4 mV per 1,000 hours based on the best 17 cells.‘” The PSI performance model was verified with Li/Na electrolyte as well as with Li/K on system gases at 3 atma.2” This electrolyte appeared to show about the same nickel dissolution when extrapolated to 40,000 operating hours as that in cells with stabilized cathodes (i.e., with additives) with Li/K electrolyte at 4,000 hours212 A 100 cm2 cell with dissolution-stabilized cathodes operated on system gases at 3 atma and 75% fuel, 40% oxidant utilization at 0.16 A/cm2. On start-up at 1 atma, it operated at about 0.715 V, which increased to 0.76 V at 3 atma. Up to 5,320 hours, performance decay was about 0.5% per 1,000 hours. At this time, a cathode over-pressure incident occurred. At the same time, wet-seal deterioration started to occur. Both resulted in increased polarization and decay. The IR drop at this current density seemed to be rather uniform at about 60 mV. After tear-down at 6,900 hours, the electrolyte inventory was normal and low cathode corrosion was observed.t9& The Li/Na electrolyte was also tested in a single 100 cm2 cell at 0.16 A/cm198b on atmospheric pressure reference gases at 75% fuel and 50% oxidant utilizations. The cell showed about 15 mV lower IR drop at 0.16 A/cm2, and gave excellent stability (4 mV per 1,000 hours) to 4,500 hours of operation.st2 The single-cell performance was about 0.8 V at 0.16 A/cm2 at atmospheric pressure on reference gases at 75% fuel and 50% oxidant utilization .19sb The cell was given a thermal cycle at 6,000 hours, when its IR drop and polarization both increased. By 9,000 hours, the IR drop approximated to the value at 3,0004,000 hours (about 50 mV), but the polarization (including the Nemst loss from the zero-conversion opencircuit value) was about 240 mV, compared with ca. 195 mV at 1,000 hours and ca. 205 mV just before the thermal cycle. The cell had reached 11,000 hours by mid-1995.198c The data-base on the use of proprietary cathode and electrolyte additives to reduce nickel oxide cathode dissolution, with the option of also using Li/Na eutectic, seems to be now sufficient to enable MC-Power and IGT to contend that no lifetime problem to 40,000 hours will exist with nickel oxide cathodes even at 3 atma pressure with system cathode gas compositions. This point is important, since it implies that nickel oxide cathode dissolution (and the requirement for an effective substitute) will not be an impediment to early commercialization of the MCFC. International Fuel Cells (South Windsor, CT): IFC was in a leading position in MCFC stack development in the early 1980s. but is no longer supported by DOE, EPRI or U.S. utilities. At present, IFc’s MCFC plans am to work with its licensees Ansaldo srl in Italy and Toshiba in Japan (see below). IFC has designed a 5 atma pressurized 1.8 MW system with advanced externally-manifolded thin, lightweight cross-flow cells with fewer and simpler components to reduce cost. The system incorporated an anode feedback loop containing a reformer, which operated on sensible heat from the cell stack (see below). The planned cells were 0.75 m2 (8 ft2) active area, and were developed between 1988 and 1992 and tested in a 25 kW, 20 cell stack. The components were manufactured using improved tape-casting slurries. The thin cells contained less weight of material of more economical grades (for lower cost), had more easily manufacturable parts, and had low-pressure-drop flow fields. After the 2,200 hour test period, the center cells of the stack were unchanged in electrolyte content, but the end cells showed changing inventory, in spite of the use of additional reservoir capacity. It was concluded that cells with improved manifolding were required. These showed acceptable electrolyte transfer for a 40,000 hour stack lifetime. Gas composition and utilizations were not specified, but performance (0.72 V at 0.16 A/cm2) may indicate the use of dilute cathode gas at atmospheric pressure and 75% utilization. The continuous tape-casting process for electrodes requires a heat treatment, which is conducted in the same long ovens used for the manufacture of PAFC components. One feature of the IFC factory-constructed design is an integrated stack unit incorporating a reformer in the anode feedback loop which reforms using sensible heat from the stack (the Integrated Stack Unit, ISU). The factory-built unit will contain the reformer at the bottom of the stack, within a common pressure vessel.2ts IFC researchers have reported on the effects of nickel oxide dissolution on MCFC lifetime.214

Fuel cell technology

587

Other MCFC-Related Work: Materials support work in the United States has included reviews of requirements,*rs**t6 dissolution of nickel oxide and other oxides,*17s2rs corrosion of current collectors and separators,*19 alternative cathode materials, including doped CeO2,**e yttrium aluminum garnet,**t structural and doped lithium cobaltite.222~223 ferrite,*ta~***~**3 and manganite.******4 Electrode and (in cooperative U.S.-Japanese work) optimization,*25 anode and cathode reaction mechanisms,*~ wetting behavior,227*228 have been discussed. Developmental issues, which mostly involve lifetime and cost, have been described,229s as have strategic planning considerations for commercialization,uO and permitting procedures.zst Updates on the commercialization efforts for this technology have been givena229b,229C

Ref. 205 is an audit of U.S. developer’s cost information for stacks (not BOP). Based on nonproprietary information, it makes a number of suggestions for the reduction of stack MCFC costs. The authors estimate that mature stack costs will have 70% materials, 10% labor, and 20% overhead contents. About 38% of the materials costs am in the active components, 41% in the bipolar plate, and 2 1% in the non-repeat stack parts. Even though the stack may be expected to cost only one-third of the total system cost (c.f., MC-Power), it has been noted that it may represent as much as two-thirds of the life-cyc.le cost, if it requires replacement every 40.000 hours. Thus, it may be important to determine ways of extending the stack lifetime. Ref. 205 contains interesting suggestions for removing some of the sheet metal a.ssociated with long gas channels. This might be done by the use of distributed internal manifolding, i.e., a.series of holes through the stack at intervals of, for example, 7 cm. This increases the total effective gasket length by n”.5, where n is the ratio of the number of holes required to that used in today’s designs. Distributed manifolding would increase the gasket area by up to an order of magnitude, which may result in a greater tendency for electrolyte migration. Modeling studies at Argonne National Laboratory have shown that such distributed manifolding with corner-to-comer cross-flow in each element would yield a more uniform temperature distribution and a higher mean stack voltage.

The Netherlands: The Netherlands restarted MCFC development in 198681 after dropping its pioneering MCFC program in 1970. Non-U.S. Government-sponsored technology was transferred from IGT starting in 1985-86 under a Gas Development Corporation (GDC) Agreement with the Netherlands Energy Organization, now NOVEM. The national program, which included IEA-Joule participation, started in 1987. Stack development work is conducted at ECN, Petten, one of the four European Nuclear Research Centers. ECN has 900 effectives, 24% in nuclear power, 16% in fossil, 19% in general engineering, and 5% in renewable energy. Total funding (41% Netherlands Government, remainder contract, of which 20% is EC under fund-matching arrangements) is $83 million per year. The Fuel Cell Program was 80 personyears per year, with 60 persons full time. Of this, 70% is devoted to the MCFC, 20% to the SIOFC, and 10% to the PEMFC, with a total of $8.5-11 million per year ($13.5 million in 1993). ECN had MCFC facilities 3-5 times larger than those of Ansaldo, and was aiming to become the European Testing ICenter for MCFC, SOFC and PEMFC systems up to 10 kW. 232 The country had spent approximately 30 million ECU on its MCFC R,D&D program up to the end of 1991. The EC supported a successful 1 kW internalreforming pilot stack at ECN, the Netherlands in 1992.81 Performance of laboratory scale cells under “standard’ conditions (i.e., at low anode utilization and with the standard 70 : 30 air/C& reference cathode gas mixture) was 0.90 V at 0.16 A/cm;! in 1991. Bench-scale cells operated under at 0.80 V at the same current density at reference fuel air and fuel utilizations at this current density .233 Performance on system gases would therefore appear to be comparable to that in Figure 5. A 1,000 cm2 ten-cell stack was operated from November 1990. Some details of design considerations for small stacks were published in 1990.u4 The proprietary FLEXSEP@ bipolar plate technology was first developed in 1,000 cm2 active area. Scale-up of components from 1,000 cm2 active area to 0.335 m2, then to 1.0 m2, was carried out between 1991 and 1994. Scale-up to 1 m2 was conducted by stretching the smaller plate by a factor of three (to 140 cm) along its width.*35 The dimensions of the 0.335 m2 plate were width (along the five-hole internal manifolding)“6 47 cm, length, 71 cm. A continuous tape-casting machine for these sizes was installed in 1992.233 The three-piece FLEXSEP“ plate superficially resembled the MC-Power IMHEX@ plate except for the shape of the manifolding. It initially used the internal manifolding in the counter-flow mode through the cells and a co-flow manifold supply (Ref. 6, p.450-451). us However, the same plate was later operated as a co-flow system with a better temperature distribution. 232 Built-in flexibility in the manifold area*36 and compliant soft metallic rail around the edges for sealing allowed for manufacturing tolerances and thermal expansion.u3m Without current collectors, the 1.0 m2 plate contained only 6 kg of a:+received materialszs2 Bipolar plates presently used by other developers were heavier (see MC-Power Corporation, above). For example, the experimental II-II bipolar plate weighed about 20 kg m2 in 1994, and t.he Hitachi bipolar plate was even heavier (see following). However, designs elsewhere were being improveld from the viewpoint of both simplicity and weight.194

588

A. J. Appleby

The material used for the FLEXSEP@ bipolar plate is Avesta stainless steel, with the composition 25 : 20 : 0 : 5 Ni/Cr/Mn/Mo, with some Cu, corresponding to specification DIN 1.4539.mJJs6 It showed It is nickel-coated on better corrosion resistance than AISI 310s (19-22 : 24-26 : 2 : 0 Ni/Cr/Mn/Mo).us the anode side and aluminized by high-temperature chemical vapor deposition around the edges for corrosion protection.23a~235 Electroplated nickel coatings 50 pm thick had proven to be successful on iron-based alloys such as the steel used for the bipolar plate, and less expensive copper coatings were being examined.235 ‘Ihe bipolar plate consisted of the corrugated central part and two gas distribution frame parts which were TIG-welded together. The current collectors were DIN 1.4404 stainless steel, nickel-plated on the anode side.236 The LiAl02 matrix tape contained fibrous aluminum oxide for reinforcement.*5 System analyses showed that pressurized stacks containing up to 125-130 large cells were possible.u3P6 Two proof of principle three-cell 1.0 kW stacks with large-scale (0.335 m2) components were tested in 1993 at pressures from 1 to 6 atma for 1,000 hours each. On reference anode and cathode gases at fuel and oxidant utilizations 75% and 50%. they operated at 0.15 A/m2 at 0.77 V at 1 atma, 0.82 V at 3 atma, and at 0.84 V at 6 atma. These stacks followed a 5,000 hour endurance test of a 20-cell 0.1 m2 (2 kW) atmospheric pressure stack in 1992. A 33-cell, 10 kW pressurized (4 bars) stack was operated for 2,090 hours (1,273 at 4 atma, the remainder at 1 atma) in 1994. The gases were as in the previous test, but with oxidant utilization at 14% to allow for cooling. At 0.15 A/cm2 at the end of testing, the best cell was at 0.815 V and the worst at 0.71 V. Excluding one cell which failed without affecting the remainder of the stack, the average performance was 0.805 V. 2~7 These tests were to have been followed by a 50 kW stack and two 250 kW MCFC units by 1995. One of these was to be operated on coal gas, the other on NG with CHP. The first (Coal Gas Energy Transformation in a MCFC, COGENT-MCFC) will probably be operated on gas from the 250 MW IGCC plant with the worlds largest entrained-bed Shell gasifier in Buggenum, the Netherlands.2ssJs8 Following the proof of concept demonstrations, a proof of producibility program was envisaged in 1991 with production of about 25 MW of 500 kW systems per year.233 The stack tests had demonstrated start-up and operational procedures for full-size stacks, and that a further test to the height of 125 cells would be necessary. However, following the 10 kW test, ECN still had major concerns about stack lifetime. The major problem was nickel oxide cathode dissolution at 1.2 atma CR partial pressure, giving a cathode lifetime of 4,000-6,000 hours. Electrolyte evaporation and inventory, and nickel spalling on the anode hardware were also life-limiting problems.237 To solve the problem of carbonate inventory, a means of carbonate replenishment was said to be required For example, at 1 atma and at an exit gas temperature of 700°C, ECN estimated lifetimes in hours as follows: NiO cathode, 25,000 (lithium cobaltite, 120,000); Ni-Cr, NCAl anodes, 40,000 and 80,000 respectively; electrolyte (evaporative loss) 6,000-10,000; bipolar plate >lO,OOO, 20,000, and 20,000 for anode side, cathode side, and wet seal respectively; lithium aluminate matrix >40,000. At 4 atma, the corresponding figures were: NiO cathode, 6,000 (LiCo@, 90,000); electrolyte (evaporative loss) 6,COO-10,000, Ni-Cr, Ni-Al anodes, lithium aluminate matrix, and bipolar plate, same as 1 atma. These figures were based on laboratory data taken on cells representing outlet gas temperature conditions at 7OO’C in real co-flow systems. The life limitation on the anode side of the nickel-clad bipolar plate was due to the effect of spalling of the coating due to water formation at the stainless steel oxide layer, which was said to be a random, medium-term effect.a2JJs Much of the above was stated (unreferenced) in Ref. 83b. These estimates differ from the predictions of U.S. developers (c.f., ERC and MC-Power, above). However, the evaporation data obtained in the United States were taken in small cells maintained at 650°C on reference gases with low water content, therefore with a low hydroxide vapor pressure in the evaporating stream. They also differ from data obtained by very long test runs on single cells and stacks operating on system gases at MELCO (see below). As has already been stated, ERC operates at a maximum temperature close to 675’C, and an average of 640°C, which will appreciably increase component lifetimes. ERC has operated a short stack for 10,000 hours with system gases without encountering problems. Co-flow stacks may have special problems because of their high exit temperature, and more particularly because of the large amount of cell ama exposed to high temperatures. In general, cross-flow stacks in thermal equilibrium with enthalpy production show a more extreme temperature distribution than co-flow stacks (Ref. 6, p. 550) if operating conditions with cooling by process air are identical. However, if IIR cooling plates are used, with their reactant flow distribution designed for optimum cooling, the temperature extremes under co-flow conditions can be appreciably reduced. This is readily illustrated by the measured temperature distribution in the cross-flow, IIR ERC stack described in Ref. 184b. The ECN co-flow stack had anode and cathode exit temperatures of 700°C. compared with 639OC and 664OC for the Ref. 184b stack. The cathode exit temperature difference alone can account for an almost two-fold change in saturated vapor pressure. However, the exit gas is unlikely to be saturated. The ERC stack had 30% of the overall cell ama at temperatures over 65O’C. 6% at over 670°C and 1.5% at over 68O’C. In contrast, modeling studies of a co-flow non-IIR stack operating under ECN conditions show 85% of the overall cell area at temperatures over 650°C, 60% at over 67O’C and 30% at over 68O”C.240 Assuming the same percentage of saturation of the cathode process and cooling stream in each case, it would not be surprising to see a ten-fold difference between the rates of evaporation of electrolyte in the two stacks into equal volumes of the cathode gas streams. The co-flow cell operated at 4 auna, and the cross-flow cell at 1 atma, but this reduction in volume is partly offset by the 90% increase in

Fuel cell technology

589

oxidant flow rate required for pressurized non-IIR operation because of the increased cooling flow. Hence, the evaporative loss of KOH and to a lesser extent of LiOH would be about 5 times higher under ECN conditions, compared with those at ERC. Using the ECN data, the ERC stack should therefore operate for at least 30,000-50,000 hours before evaporation effects become significant. We should remark that no problems have been seen in MC-Power (i.e., IGT) short stacks operating at a maximum (and exit) temperature of 700°C. However, the hot spot in counter-flow cells lies towards the oxidant outlet, which is cooled by incoming fuel. This may allow some condensation and recycling of electrolyte. The use of Li/Na melt may also reduce evaporative losses.2t2 In regard to NiO cathode dissolution, the position of the U.S. developments has already bexn noted. The ECN results were obtained with reference oxidant ,a9 and they indicate an effective life of 25,000 hours at a Co2 partial pressure of 0.3 atma. This is equivalent to 75,000 hours under ERC conditions (0.1 atma COz), and 25,000 hours under MC-Power conditions at 3 atma. With the various proprietary approaches MC-Power and IGT use to reduce dissolution, including substitution of Li/Na melt,212 at least 50,000 operating hours should be attainable. The final major question raised by ECN, the durability of the nickel coating on the anode side of the bipolar plate, has not been observed as a problem in the United States. The development of accelerated life-test experiments would increase confidence on MCFC stack lifetimes, and would avoid expensive operation of cells and stacks for 40,ooO hours. A further discussion of these endurance issues is given in Section 29, Conclusions. In the late 198Os, the Netherlands had selected the metal company Hoogovens as a potential MCFC manufacturer. However, this possibility ceased after the company was acquired by Kaiser Aluminum. In 1990, ECN founded Branstofcel Nederlands B. V. (BCN, The Hague) as a potential MCFC manufacturing arm, with 4% ownership by ECN, 24% by Stork ($2.2 billion/year, industrial machinery, including cogeneration); and 24% by Royal Schelde ($600 million/year, naval shipbuilding, cogeneration). BCN is co-financed by NOVEM (50%) Sep-Netherlands Electricity Board (program launcher, 16%), the EC (16%), Spain, and other, in a $51 million program . It was to use both licensed IGT (though not that financed by DOE) and indigenous technology, and would interact with MC-Power, Siemens, and Ansa.ldo. The objective was MCFC manufacture, demonstration, and production.u* The proposed 250 kW demonstratorn3 would use two 1.0 m2 FLEXSEP@ CSAs, and would be a result of a collaboration between ECN, BCN, Stork Product Engineering B.V. (Amsterdam), and Stork Alpha Engineering B.V. (Beverwijk). An ASPEN-PLUSm (Advanced System for Process ENgineering)* process simulation of the pressurized system indicates 53.9% gross dc (51.7% gross ac) LHV efficiency at 0.785 V (0.12 A/cm2) and 75% NG utilization, but only 43.7% net LHV efficiency due to the high compression work requirement (15.7% of ac output). This efficiency is not particularly attractive compared with that of the atmospheric-pressure ERC system (see above). The simulation used a 67% cathode recycle ratio. The corresponding Buggenum scrubbed coal gas plant was expected to operate at 0.15 A/cm2 and 0.698 V. It would occupy a 10 m x 20 m site, and would have
* Simulation Systems, Inc., Aurora, CO.

590

A. J. Appleby

MCFC stack should operate at 16 atma for this application, which will not be possible with present cathode materials.248 The Netherlands program continues to put a strong emphasis on fundamental research at ECN and at the Delft University of Technology. In parallel to investigating the mechanism of nickel oxide cathode dissolution,s7*249~~athe effects of additives on its lifetime have been examined. By measuring weight loss as a function of time, it was concluded that the lower limit in the nickel oxide cathode lifetime plot as a function of CO2 partial pressure in Ref. 6, p. 571 is approximately correct. The precipitation of nickel nodules in the melt has been shown to be complex, and may have a mechanism involving melt supersaturation with Ni2+.37 The addition of small amounts of alkaline earth metal oxides or carbonates increases melt basicity. This has been shown to give a 40% reduction in dissolution rate.““l New cathode materials have been examined, particularly lithium cobaltite2ss~25t~2s2 and lithium ferrite.233~252The latter shows essentially zero solubility, but poor performance, which is presumably due to inferior conductivity (Ref. 6, p. 572). These results follow work reported in 199O.ss Lithium cobaltite has about 10% of the solubility of nickel oxide, but its lower conductivity still gives it a performance about 50 mV lower than the latter.usfz2 Improvements in the structure and performance of nickel-chromium anodes have also taken place, those with 6% chromium representing an optimum structure from the viewpoint of long-term porosity retention. Nickel-aluminum anodes with enhanced creep performance are receiving attention. Other life-limiting issues have been reviewed.252 and the corrosion of nickel has been examined.2s4*2ss Particular emphasis has been placed on improving electrode performance models.233*as6*2s7 More recently, stack models have been developed. 2~~s7~2sa Ref. 257 used experimental data from the 20 kW ERC stack tested at the Destec gasification facility in Plaquemine, LA,t77 which was co-sponsored by KEMA in the Netherlands. The model developed will be used to predict the performance of a system using a Shell entrained-bed gasifier similar to that at Buggenum. 257 Results obtained on the 10 kW (nominal) stack (33 cells, 3,352 cm2) which produced 13.8 kW on standard fuel (75% utilization) and reference oxidant at 14% utilization (0.15 A/cmZ, 0.83 V)237 have been applied to a three-dimensional stack modelas Distribution of gas-flow in internally-reforming stacks of this type has been modeled.259 Studies are being conducted in the framework of the International Energy Agency (IEA) cooperative fuel cell program under the annexes MCFC Balance of Plant Analysis (3 years for phase 1, starting 1990; 5 participating countries; operating agent, Japan), and MCFC Materials and Electrochemistry (2 years for phase 1, starting 1993; 5 participating countries; operating agent, the Netherlands). Collaboration on a further annex Fuel Cell Systems Analysis (2 years for phase 1, starting 1994; 7 participating countries; operating agent Sweden) started in 1994. Phase 1 of the BOP analysis task involved application of the technology in the participating countries, comparison of system designs of 50 kW to 2 MW demonstrators, modeling of dispersed 10 MW to 100 MW coal-gasifier systems, and BOP Technology studies. Following this, a 2-year Phase 2 will be conducted. This will involve modeling and scale-up of large stacks for externally and internally reformed NG and coal-derived gas, BOP for fuel clean-up and processing, gas recycle, control systems, and optimization of LNG, coal-gas, biomass, and biogas plants. The materials and electrochemistry annex involves data collection, endurance issues, and standardization of comparative testing. Subtasks include corrosion of structural materials, electrode materials, and electrolyte behavior. The systems studies were being used for the cost-effective design of the proposed 250 kW demonstrators.260 Germany: A sum equal to 70 million ECUs (approximately $90 million, 1995) over nine years had been set aside for MCFC R,D&D in a program which started in 1988. In 1992, a 20 kW coal-gas pilot and a 250 kW unit based on ERC technology to be eventually manufactured by Messerschmitt Bolkow Blohm (MBB) GmbH (now part of Deutsche Aerospace Airbus, DASA, in the Daimler-Benz Group) was expected to be available in 1994.8t MBB was a minority (13%) owner of ERC, and planned to manufacture ERCdesigned CSAs and a 2 MW demonstrator using ERC CSAs.32 A manufacturing facility was planned to be operational in 1998.81 These projects have been delayed. MCFC components and production methods have been studied.261*262 Three different MCFC systems have been considered: a) external reforming, with C& scrubbers at the anode and cathode exits to recover and recycle 80% of CG2,50% assumed LHV efficiency; b) internal reforming with 02 separator, supplying stoichiomettic 02 and a (via a single scrubber), presumably in the ratio of 1 : 2 (not 1 : 1 as stated) to the cathode. It would operate at utilizations of 100% (oxidant with recycle) and 85% (fuel), with the 15% fuel enthalpy used to raise steam for use in a turbine. The assumed LHV efficiency is 58%; c) internal reforming with t& and C@ separation, allowing ca. 100% air and oxidant utilization, 63% assumed LHV efficiency. For systems with 20 x 5 MW stacks each, total plant investment costs would be the equivalent of $3,550, $2,460. and $2.090 per kW (dc) of stack output, and electricity costs would be 14, 10.5, and 9 +?/kWhrespectively. These were much too high. Some of the consequences of operating such impractical plants at high pC@ with standard cathodes were not considered. Stack costs were estimated by multiplying materials costs by a conservative factor of 5.7. It was considered that stack power densities should increase by a factor of three to result in economical plants. However, reduction of the cost multipliers by using advanced production methods should also be a feasible approach.263 Modeling has

Fuel cell technology

591

been conducted,mf” together with studies on materials, including modified nickel oxide with a reduced dissolution rate, novel carbide anodes.266 and [email protected] Italy-Spain MOLCARE Program: Italy started expressing interest in the MCFC technology in 1988, with Ansaldo Richerche srl (ARI) taking the lead as a potential manufacturer. In 1988, Spain also expressed interest,** and in July 1993. AR1 and Tecnologia y Gestion de la Innovation, formed in 1990 as the development organization of the INI/TENEO industrial group of Spain, signed a collaborative agreement. In March 1994, the partners signed a Collaborative R&D agreement with IFC to develop the MCFC. A 100 kW demonstrator is planned, which will be partly funded by the Joule II and THERMIE EC programs, with the participation of ENEA (the Italian Energy Development Agency) and the large Spanish utility IBERDROLA. The unit will contain the IFC technology stack in a self-contained “Compact Unit,” comprising the 150 cell, 4 atma, 0.74 m2 (0.668 m2 active) externally-manifolded cross-flow stack, the sensible heat reformer operating on anode gas recycle, the anode and cathode recycle blowers, and the catalytic exhaust burner. Performance was expected to be a rather modest 0.68 V at 0.146 Al’cm2, and demonstrator lifetime would be 8,000 hours. Cost and heat rates am not specified. Other project activity would focus on materials and manufacturing methods and tolerance for MCFC components, and a cost and design study for a 5 MW plant.26’ A Microsoft EXCELIM 4 spreadsheet model of the system and the current density and temperature map of the cell surface shows that the maximum temperature is 73O’C at the oxidant out, fuel out comer. Approximately 25% of the cell surface is over 680°C (c.f., comments concerning Refs. 184a, 184b, 239 and 240, above). 26s AR1 is also conducting developmental research with its partners for CISE in Milan (an Italian energy agency) and ENEL, the national electric utility. Work includes components and testing of parts for the 100 kW stack. Components first became available in subscale (700 cm2) size in 1993.269 after which a 15 cell, 1 kW (nominal at 0.7 V) stack was tested for 1,600 hours. It produced 622 W at 100 A (0.415 V average cell voltage), which was ascribed to cell damage during start-up.270 Vertical scale-up will be to 50 cells, which will be followed by horizontal scale-up to 0.74 cm2. Testing was expected in 1995. Characterization of components, system, :stack, and cell modeling were included in the program.269 Italy: Other work in Italy has been conducted on modeling of internal-reforming systems,27l cell lifetime,272 Ni/MgO direct reforming catalyst behavior,273 materials,274*s7s the feasibility of biomass gasifier plants,276 and on the testing of LiCa catalysts. 277 Ginatta Electrochemical Industries (Turin), a titanium manufacturer, was also reported to be interested in developing MCFC technology. Elsewhere: A general review of European work, including cooperative ventures, is given in Ref. 82. In 1991-92, ELKRAFT a Danish utility, tested a 7 kW ERC CSA, and proposed a 100 kW or 2 MW unit.32 Balance of plant studies have been conducted in Denmark, which included extemal27* and internal reforming.s79 Work is increasing in Sweden ,zsa*r with emphasis on materials,282 including LiCoO;! cathodes.28s System modeling using the ASPEN PLUSI’M process simulator.284 and the design feasibility of a 1 MW cogeneration plant have been conducted. 285 Reformer and BOP models for both 1 MW cogeneration and 250 kW cogeneration systems have been conducted with ECN and Vattenfal1.a An ASPEM PLUSrr” model of a proposed 4 atma 250 kW ECN demonstrator confirmed the 43.7% LHV efficiency reported in Ref. 238.287 The options for handling CO2 as a reactant in the MCFC have been considered.2s8

Introduction: Reviews of technology are given below, starting with internal reforming systems, followed by utility ventures, R&D results obtained by individual developers (in alphabetical order), and supporting work. Internal Refovning - Mitsubishi Electric Company (R&D Center and Works, Amagasaki,, Hyogo): At MELCO, both direct and indirect internal reforming (DIR and IIR) were being examined under NED0 contract.aafa’J The technology was based on that of ERC. By 1990, an atmospheric pressure direct internal reforming stack @IR50-1,5 cells, 0.5 m2,3 kW) had been operated for over 4,000 hours. It used low-CQ cathode gas (12% C@, 88% air). It showed about 0.10 V decay at the end of testing (to 0.7 V at 0.15 A/cm2), which was the same for methane and reformate, indicating that significant reforming decay did not occur. The decay was reflected in the open circuit voltage, perhaps indicating crossover. Work included the effect of increasing the steam-to-carbon ratio in the range 2.0 to 4.0, which caused a decrease in cell voltage of 7 mV. Operation could occur at initial steam-to-carbon ratios as low as 1.5.ass In contrast to the DIRSO-1 stack, a 5.0 kW 50-cell stack with 0.1 m2 cells (effective area 899 cm2) showed a wide scatter of performance between cells due to maldistribution of flow. This was attributed to thickness variations in the bipolar plates (9.2 to 9.6 mm). The initial steam-to-carbon ratio was 2.8 : 1. The initial performance (average 0.75 V per cell at 0.15 A/cmq was about 50 mV lower than that of the stack

592

A. J. Appleby

with larger cells. This was attributed to heat supply considerations, which might requite a redistribution of anode reforming catalyst in small cells. 291 Evaporative loss of electrolyte onto the reforming catalyst in DIR cells was studied using a scrubber, in which gas was passed through a column of electrolyte tile plus electrolyte, through an open atea separated by two porous nickel foils, to a chemical electrolyte scrubber. The amount of electrolyte collected was measured as a function of gas composition, flow rate, and pressure. This showed it to be lost as hydroxide. 292 The loss rate at 65O’C was 4.3 x lo-9 g/standard cm3 of 72/18/10 H2/C02/H20 at atmospheric pressure. z9*p292This corresponds to 0.82 mg/cm2 loss per 1,000 hours at this temperature at 75% hydrogen utilization and 0.16 A/cm2, for a gas composition with an initial H2O/CQ ratio of 0.56 (2.85 after equilibrium shifting) at 1 atma pressure. This important result will be reexamined in the Conclusions, Section 30. Another large-scale direct reforming stack @IR50-2, 10 cells, 0.5016 m2,5 kW) was constructed and tested, starting in January 1992. It took advantage of improvements to prevent evaporative contact between the catalyst and the electrolyte. On a 72 : 18 : 10 mixture of H2/C@/H2 as fuel, it developed 0.819 V, and 0.808 V on methane at a steam-to-carbon ratio of 2.5, both at 60% fuel utilization and 20% reference oxidant utilization at 0.15 A/cm2. In the DIR mode, it operated at 0.778 V at 80% fuel utilization at this current density. The stack underwent a thermal cycle at 525 hours, and had operated for over 4,500 hours at 99% methane conversion with a decay rate of only 4 mV per 1,000 hours.292 A summary of DIR work to late 1992 was available. 2s3 The cross-flow stack had the anode chamber divided into two compartments, so that fuel entered at the oxidant exit side, left the first compartment, and reentered in the other direction into the second compartment at right angles to the oxidant entry. As a result, only 12% of the stack area was at temperatures over 65O’C and about 1.5% over 67O’C. The average temperature was approximately 630°C. Stack DIR50-2 operated for 10,190 hours (11,500 hot hours, 41.7 MWh) until July 1993, maintaining the same decay rate. A 30 kW 57-1~11stack with the same area was started in June 1993, and continued to operate in August 1994. By then, its total operating time was 8,756 hours (9,845 hot hours, 255.5 MWh). Degradation was 5 mV per 1,000 hours. The cell voltage distribution was very uniform. The DIR catalyst activity degraded by ca. 20-25% over the first 5,000 hours, stabilizing thereafter. Degradation was quite strongly temperature-dependent, and was associated with nickel crystallite size rather than electrolyte accumulation on the DIR catalyst.294 An indirect internal reforming stack (IIRSO-1,3 cells, 0.5 m2, 3.6 kW, one reforming plate) operated for 2,185 hours in 1989 with a decay of only 5 mV per 1,000 hours. Initial performance in the IIR mode was 0.746 V at 0.15 A/cmz, 27 mV below that on reformed gas due to the 20-30°C lower stack temperature resulting from reforming. The IIR mode improves the temperature distribution from a range of 12O’C to 90°C.s9 After operation of the IIR50-1 3 kW class stack, a 10 kW class stack was operated at the Kansai Electric Power Company Technical Research Center in 1990 (IIR50-2). This was a 20-cell 0.5 m2 stack with three IIR plates, which operated for 2,052 hours at a maximum power of 11 kW.2” A 30 kW stack using 62 0.5 m2 cells (effective area 0.4864 m2) operated for 2,131 hours in 1991. It used an IIR plate every six cells. On direct methane feedstock. it developed 35.1 kW at about 0.58 V per cell and 0.20 A/cmZ. Performance was 0.71 V at 0.15 A/cm2 at 2,000 hours, with a decay of about 25 mV/l,OOOhr. The fuel feedstock was 20% methane, 80% water (60% utilization), and the cathode feedstock was “reference” 30% CO2, 70% air. A 100 kW stack operating on desulfurized town gas (NG) was then planned.2959296A report on the 100 kW IIR stack was available in 1993.297 The IIR50-4 unit had 192 cells in two stacks, each with 2 units, with a total of 32 IIR plates. It operated on LNG at a steam-to-carbon ratio of 4 for 2,308 hours from May to August of 1992. The degradation rate was 5 mV per 1,000 hours.* The average cell voltage was 0.728 V at 60% fuel and 30% oxidant utilization, with operation at 629°C average. One feature was the use of pressure-swing adsorption (PSA) to permit the use of rich cathode gas.298 The PSA unit had a specific energy consumption equal to half of that of one typically used in a steel plant. Its energy requirement was 0.26-0.35 kWh/Nm3 of CO2, giving a 16-22% parasitic power requirement. This should be reduced if the process is to be successful.297 A 256 cm2 MELCO cell was tested at 3 atma pressure under the support of the Central Research Institute of the Electric Power Industry (CRIEPI, Yokosuka-shi, Kanagawa) in 1991. With a fuel gas consisting of a 72 : 18 : 10 mixture of H7jCG7&0, its performance increased by about 45 mV from 1 atma to 3 atma (0.835 V to 0.88 V) at 0.15 A/cm2 and 40% fuel utilization with reference oxidant. The further gain on going to 7 atma was less than 10 mV. Methanation occurred in the anode as pressure was increased from 3 to 7 atma, when exit methane concentration was about 4%. When a dilute fuel gas containing nitrogen (22.5 : 18 : 10 : 49.5 mixture of H2/CG7jH2/N2) was used, the approximately linear part of the pressure response extended to 7 atma, with 0.746 V at 1 atma and 0.81 V at 7 atma at the same fuel utilization and curtent density. The methane concentration was low, even at 7 atma. Decay of performance under pressurized operation resulting from cathode dissolution was also studied.299 Most recent work has involved the advanced internal reforming (AIR) concept, which is similar to the technology used by MBLCG’s licenser, ERC. This uses an IIR reforming plate for every few cells, with NG steam entry into a manifold in the plate in cross-flow with the oxidant, at its entry side. The fuel gas * The New Sunshine Project goal is 1% or about 7.5 mV per 1,000 hours. In the United States, ERC has observed 2.5 mV per 1,000 hours.

Fuel cell technology

593

turns 90°C through the reforming catalyst, which it passes through in co-flow to the oxidant gas :in the cell. It then again turns 90” again, to reverse its direction compared with that of the entry steam, and exits into the cross-flow fuel inlet manifold. Any remaining NG is reformed at the DIR anode. The effect i;s to give a similar temperature distribution to that in ERCs IIR stack, Ref. 184b, in a more flexible arrangement than that of the “returned flow” &sign in the MELCG DIR stacks. A 10 kW 0.5 m2 atmospheric pressure stack based on this design (AIR50-2) started operation in March 1994. It gave an average of 0.78 V at 0.15 A/cm2 at a fuel and reference oxidant utilizations of 80% and 30%. The AIR concept was expected to be used in a 200 kW 1 m2 stack for the New Sunshine Project in 1997.294 MELCO researchers have also assessed lifetime issues for the MCFC. This includes work on improved Ni-Al and Ni-LiAlO;! anodes with lower creep, on NiO cathode dissolution and reprecipitation, and on oxide scale growth and associated Li+ loss on cathode stainless steel parts, all in standard oxidant as a function of time. A single cell was operated to 20,000 hours at 0.14 A/cm2 with 5 mV per 1,000 hours decay rate.sea The use of copper-based anodes has been described by the Mitsubishi Materials Company (Omiya-shi, Saitama).sst Internal Reforming - Sanyo Electric Company (New Materials Research Center, MoQuchi-shi, Osaka): Internal reforming of fuels other than methane or NG in the MCFC has also been the subject of work in Japan. The Petroleum Energy Center, which was established as a MITI subsidiary in May 1986, is interested in the possibility of both external and internal reforming of, e.g., hydrodesulfurized naphtha and kerosene, with partial cracking of the latter. After demonstrating external reforming in a system using a 10 kW Sanyo Electric Company MCFC stack in 199O?as a program was started in 1990 in collaboration with two petroleum companies, one electric company, and one engineering organization, with demonstration of a 10 kW class stack expected in 1993-94. ls8 The Sanyo Electric Company (Sanyo Denki) has continued to work with other developers, for example, Tonen Corporation (Ohi-Machi, Iruma-gun, Saitama) and Toyo Engineering Corporation (Mobara-shi, Chiba), on the development of external reforming concepts.303 Like MELCG, Sanyo’s technology is also based on that of ERC under a licensing agreement. Sanyo’s 21cell 5 kW IIR stack had cells with an area of 0.24 m2, with 4 reformer plates. It operated at 0.15 A/cm2 on methane at an unspecified steam-to-carbon ratio at a mean cell potential of about 0.774 V. As in the case of MELCG stacks, it operated at a temperature about 30°C below the value attained on reformate fue1.304 Further details of the 5 kW and a later 10 kW test have been ma& available, which indicated that a steam-tocarbon ratio of 3.8 was used, and that certain cells in the stacks did not function well at high fuel utilization, although good results were obtained at 72%. This effect was attributed to poor reactant distribution. The IIR catalyst was Ni/Mg0.305 Work on DIR with conventional catalysts did not prove very successful at MCFC‘ operating temperatures, so the Sanyo-Tonen-Toyo consortium developed a more active proprietary catalyst, ruthenium or rhodium on zirconia support. It was determined that catalysts degraded by two mechanisms, via electrolyte absorption from the liquid and from the vapor phase. The Ru/ZrG:! catalyst was te:sted in a 25 cm2 single cell with a steam-to-carbon ratio of 2.0 (or 2.5, see below) at 650°C and 0.15 A/cmZ. It absorbed only 0.5 wt % of electrolyte over 3,CKlOoperating hours and maintained excellent activity.306 A 1 kW-class test was run in 1992 (10 cells, 777 cm2 active area) using reference oxidant and propane at a steam-to-carbon ratio of 2.5. At 60% fuel utilization and 40% oxidant utilization, individual cell performance was good (about 0.75 V at 0.15 A/cmZ), but some cells suffered from poor fuel distribution, especially at small anode recycle ratios. A recycle ratio of 0.6 was the design point. Performance of the proprietary ZQ-supported Ru reforming catalyst was excellent, with negligible degradation over 4,500 hours. A 30 kW LPG-fueled system was planned in 1993, with CO2 recycle via a catalytic combustor.307 This system was described in 1994.30afos The 25 cm2 cell was operated to 10,000 hours with no further carbonate accumulation on the DIR catalyst and no loss in activity. A 10 kW 27-cell DIR pragane crossflow atmospheric pressure stack (0.45 m2) was operated for 3,000 hours at 0.15 A/cm2 at 70% fuel utilization and 27% oxygen utilization at 0.67 V on dilute system gases with excellent performance stability. However, it suffered from excessive temperature gradients along the plane of the cells (over 250°C differential, with measured maxima of 78O“C and minima of 525“C), resulting from very rapid reforming at the fuel inlet. This was corrected by adjusting the reforming catalyst distribution in the anode in the next 66 cell 30 kW stack with the same surface area. It was verified that redistribution of the catalyst gave a cell temperature range with maxima of 7OOOCand minima of 6OO’C. The atmospheric pressure system contained a desulfurizer for commercial grade LPG, anode and cathode feed-back loops, and a catalytic combustor for the anode feed-back exit gas and the exit oxidant from the cathode feed-back loop.sO* The system was a relatively compact, prepackaged skid-mounted design with a footprint of 0.5 m’&W. This may be compared with 0.8 m2/kW for the MC-Power 250 kW Miimar unit (and 0.08 m2/kW for the IFC PC25C). With 90% system fuel utilization and 80% utilization in the fuel cell, 56% anode recycle ratio, and 60% system oxygen utilization, the LHV electrical efficiency was expected to be 50%.MCFC Research Association: The MCFC Research Association (MCFCRA) was founded on January 21, 1988, as a NEDG contractor. Its laboratory facilities are at the Akagi Research Laboratory, Gunma (Akagi Stack and System Square, Akagi 3S), about 100 km from Tokyo. The laboratory opened in

594

A. J. Appleby

November 1990. Its objective was to serve as the test facility for stacks and BOP for NEDG’s two major MCFC contractors, Hitachi Ltd. and IHI. Activities up to FY 1993 (starting April 1993) included the design of an LNG-fueled 1,000 kW pilot plant, and development of plant components for preprototype demonstrations. The IHI pilot plant for a 100 kW unit, containing a dummy stack, was operated at Akagi 3S from April 1991 to July 1992 as a system and control test.3*0D311The 100 kW stack test was conducted in FY 1993, with Hitachi and IHI stack designs (see below). The same design was scaled up to 1,000 kW. The fuel processor, heat recovery and stack peripheral subsystems for this unit were progressively tested during FY 1993 (starting April, 1993). By the end of 1994, prototype BOP hardware tested at Akagi 3s had generally performed to specifications. Two types of reformer, heat-exchange (Chiyoda Corporation, Yokohama), and catalytic combustor (Hitachi, Ltd.), were studied.312 Both met the plant goals at a steam-to-carbon ratio of 3 : 1. The Hitachi reformer has been selected for the 1,000 kW pilot plant. It had shown 96% conversion (>95% specified), 26% load change per minute (>25%), and 1 ppmv of N@ (~10 ppmv), and had operated for 1,000 continuous hours. The Ebara 500 kW magneticbearing blowers for the high-temperature cathode feedback loop (one per 500 kW subunit) had shown 79% efficiency (>75%) and had operated for 1,500 continuous hours. The single Kobe Steel turbocompressor for the plant had shown 65% efficiency (~65%; compressor 80%, expander 81%), and the 1,000 kW Toshiba steam generator had shown a 81% heat recovery rate (>80%). The targeted cell performance was 0.8 V at 0.15 A/cm2 (pressurized), with an endurance of 5,000 hours.313 However, the best of the two 100 kW stacks tested (see below) had shown less than the 0.8 V specified, and a decay of 1.5% per 1,000 hours (1% specified) over 5,000 hot hours. 3rd Other specifications for the pilot plant were start-up (electrolyte molten, BOP cold): 2 hours (attained, 4.3 hours); start-up (cold): 4 hours (attained, 5.1 hours); differential stack pressure: 400 mm Hg (800 mm emergency, both attained). The parasitic power was measured at 139 kW, which would give 49.5% gross efficiency (44% net, LHV). This 1,000 kW pilot will certainly not represent an optimized system, but it is rather a large-scale breadboard which will serve as an aid to learning and training. The 1 MW pilot plant is to be constructed at the Kawagoe Thermal Power Plant of the Chubu Electric Power Company (CHEPCO). The unit will have four 250 kW stacks,313and was originally planned to start in FY 1995 and be complete by FY1997.3rrJt3915 BOP equipment was being fabricated for the facility in 1995, with a PAC test expected in the last half of 1996, with stack installation at the end of that year, and operation and evaluation during 1997 and 1998.st4 In addition to the information given below, officials from supporting organizations (NEDO-AISTMIT13159316 and CRIEPIs17) as well as from the MCFC Research Associationsts~st2~s*s have described early stack testing. Many conceptual MCFC plant designs have been studied by CRIEPI. Cost projections for a commercial MCFC are approximately Y3OO,OOO/kW ($3,OOO/kWand $2,OOO/kW,1995, at the trading and PPP rates). The stack was expected to cost Y7O,OOO/kW ($7OO/kWand $47O/kW, same bases). Hitachi, Ltd. (R&D Center and Works, Hitachi-shi, Ibaraki): Hitachi developed a 25 kW class stack in Japanese FY1989 (starting in April, 1989) for the Moonlight Project, consisting of 22 cells with an electrode area of 1.21 m2. At 0.15 A/cm2, this generated 28.3 kW at 60% fuel utilization, and operated for 1,612 hours. The major characteristic of this design was the use of internal manifolding in a window-like configuration. The square window-frame was manifolded all around, and the cross structure in the center was also manifolded, so that each large frame contained four separate cells. Each had an area of 3,025 cm2, and was inherited from older technology. This arrangement was called the multiple (cell) large capacity (MLC) stack. The multiple-manifolding arrangement reduced pressure drop and improved reactant distribution, at the expense of complexity. The nickel cladding on the bipolar plate was made by vacuum-sintering a nickel foil at 1,OOO”C to stainless steel (25% Cr, containing Al and Y in small amounts). Anode creep resistance had been improved by the addition of Al and/or Mg.318 Durability issues associated with pressurized operation were described. A 5,600 hour, 3 atma test of a 64 cm2 cell was conducted in 1989-90. The cell used Ni-Mg anodes, Ag-impregnated cathodes (a feature of all previous Hitachi work) and tape-cast matrices. The hardware consisted of AISI 310s stainless steel, aluminized around the rim. Post-test analysis indicated increased nickel dissolution under pressured conditions, as anticipated.319 A 5,600 hour, 3 atma test of a subscale 64 cm2 system with improved components was also conducted. During FY 1990, a second 25 kW-class stack was operated 5,700 hours at atmospheric pressure and at pressures up to 6 atma. It was given two thermal cycles at 630 and 2,300 hours. Components included anodes made from Ni-Al alloy powders, and 0.4 mm thickness matrix sheets which are tape-cast in 1.6 m width. The separator plate was 25C!r-30Ni-Al-Y. The Ni-Mg anodes had been replaced by N&Al for increased creep resistance. A 100 kW Cmodule stack for the second phase of the Moonlight program was planned at the end of 1992.s20 The 88-cell 100 kW stack was assembled and tested. As with the full-scale stacks at ERC and MCPower in the United States, it used a compression bellows system to achieve the required constant pressure on stack components. It developed 110.4 kW in July, 1993 at the Hitachi works at 6 atma operating pressure on 61 : 15 : 24 H2/C02/H20 fuel at 60% utilization and on reference oxidant at 20% utilization. It was operated at up to 7 atma at the Akagi 3S test facility by CRIEPI.321 At Akagi 3S, it was checked for quality contml, and operated at up to 7 atma from August 1993 to June 1994. It was not grid-connected,

Fuel cell technology

595

but used an air-cooled resistance as a heat sink for the electricity generated. In initial testing (after 855 hours operation) at 3 atma at 60% utilization on NG reformate (steam-to-carbon ratio 3.5). and reference oxidant (30% utilization), the average cell voltage was 0.689 V, with a standard deviation of 19.6 mV.sz2 It delivered 0.71 V at 0.15 A/cm2 on reference fuel and oxidant at 60% fuel utilization and 40% oxidant utilization. Its maximum power was 113 kW. At 6 atma, it showed about 100 mV degradation between 1,200 and 1,703 hot hours.321 The latter represented 1,109 operating hours (81.6 MWh). A very large vertical distribution of temperature was noted in the stack, with the lower cells at 67O’C and the upper cells at 72O’C. The minimum voltage decay rate (for the cooler cells) was 2% per 1.000 hours, whereas that for the hotter cells was 23% per 1,000 hours. Lower temperature operation to improve the degradation rate was required in future stacks, and nickel oxide cathode dissolution on pressurized low-CO2 system gases required verification.322 One 50 kW twin module from the stack was brought back to Hitachi after testing at Akagi 3S, where it was operated to 5,260 hours after a change of operating conditions. Using this experience, a new full-size 22-cell25 kW (nominal) MLC stack with improved components was assembled in 1994. This attained 0.79 V at 0.15 A/cm2 at 6 atma using the above reactants and utilizations (31.4 kW). Thus, it approached the New Sunshine Project requirements of 0.8 V at 0.15 A/cm2 under these conditions. Under the same conditions, the previous 100 kW stack showed an approximate average 0.2 V difference in cell voltage at 0.1 A/cm2 and 0.15 Alcm2 (0.82 vs. 0.62 V). The improved 25 kW stack showed 0.83 V on system oxidant (10% CO2, at 11% oxidant utilization) at 5 atma and 0.1 A/cm2, and 0.76 V on reference oxidant (30% CO2, at 11% oxidant utilization) at 0.15 A/cm2 at the same pressure. Its performance degradation between 500 and 1.500 operating hours was negligible.321 Hitachi proposed to use two modular 250 kW stacks for the planned 1 MW NED0 - MCFC Research Association pilot plant. Each of these was to consist of eight vertical modules stacked within a common pressure vessel, using a compression bellows to maintain uniform component contact. The remaining two 250 kW stacks will be supplied by Ishikawajima-Harima Heavy Industries Co. Ltd. (IHI, see below).314 The Hitachi reformer for this pilot plant followed a 100 kW demonstration in 1991. The scaled-up 1,000 kW version is supplied with the majority of the anode exit gas and air to the first stage catalytic burner at the top. The second stage catalytic burner is about one-third of the way down the multiple double-walled reforming tubes, which are supplied with the remaining exit gas, NG and steam (steam-to-carbon ration 3.0) at the bottom. The exhaust gas is used for the MCFC cathode. Start-up time from cold was 3.4 hours, and NOz was 2 ppmv.323 Other specifications are given in Ref. 314. Hitachi researchers have reported the preparation and properties of Al-containing stabilized anodes,3z4 an interesting study of changes in electrolyte distribution as a function of time in large calls,a2s and improvements to anode structures based on the use of INCO 255, 300X, 310X, and 123 nickel powders sintered with pore-formers.326 Ishikawajima-Harima

Heavy Industries Co. Ltd. (Product Development

Center, Koto-ku, Tokyo):

IHI started work on the MCFC in 1983, and obtained some early stack technology from the Gas Development Corporation in Chicago at that time. IHI is now a part-owner of MC-Power, but the two companies do not share technology. Large stacks developed at IHI are all internally-manifolded (see Ref. 6, p. 451). and like ECN, they use co-flow geometry. Starting in Japanese FY 1987, scale-up to cells with areas of 1 m2 or greater took place. A g-cell, 1 m2 stack operated for 2,250 hours at atmospheric pressure in FY1988. II confirmed negligible carbonate loss by migration in the internally-manifolded system. Using a simulated reformate (66 : 17 : 17 Hz/CQ$I-I20), and 80 : 20 air/CO2 as oxidant, average performance was 0.67 V at 0.15 A/cm2 and 80% fuel utilization and 13% 02, 21% Ca utilizations. A pressurized lo-cell 1 m2 stack was tested at CRIEPI in FY1989 at the test facility built in 1984. It showed a 50 mV improvement in performance on going to 7 atma operation, half the gain being at 3 atma. A rectangular 2-cell short stack with 1.4 m2 ceils (0.8 m x 1.8 m) was tested for 2,100 hours in FYl989, 327 and an l&cell stack with 0.312 n$ area was tested at CRIEPI for 310 hours at 1 atma, 870 hours at 3 atma, and 1,250 hours at 7 atma.3:Ls The fuel composition used was the same as that in the previous g-cell stack, but the oxidant composition was 70 : 30 air/C&. Performance was about 0.75 V at 0.15 A/cm2 at 80% fuel utilization at atmospheric pressure. It was considered that the most appropriate size for scale-up was approximately 1 m2 because of limitations in the available manufacturing techniques. One objective of this test was to increase the anode recycle ratio as a means of increasing overall fuel utilization. At 7 atma, and 0.15 Alcm2, with an oxidant utilization in the 20-45% range, the use of 80% recycle allowed 90% overall fuel utilization a one-pass utilization of 70%, effectively raising the stack efficiency from about 46% (with no recycle) to 53% (with recycle). The exit gas from the anode recycle loop was burned in a catalytic combustor in the cathode recycle loop, which allowed good control of stack temperature. It also simplified the cathode gas supply by allowing the use of 100% air feedstcck as makeup reactant in the cathode recycle loop. On lean C& system gas in the cathode loop at 7 atma, an average of 0.75 V at 70% fuel utilization at 30% oxygen utilization was obtained. The corresponding value: at 80% fuel utilization and 30% oxygen utilization was about 0.72 V. These correspond to 45.5% and :jO.O% gross

5%

A. J. Appleby

HHV efficiency respectively (50% and 55% LHV) if waste sensible heat could have been recovered for methane reforming.328 Further details of the performance of a 10 kW pressurized I m2 stack (active area, 0.98 m2) tested at CRIEPI in FY1990 were provided in 1992 and 1993.329~30The stack was operated between 1 atma and 7 atma, and the effect of pressure, fuel utilization, and percentage of anode recycle on performance was examined. The system was similar to that used in the previous 18-cell stack. The performance at 5 atma at 80% fuel utilization, and 30% oxygen utilization with a cathode recycle ratio in the 19-358 range was close to 0.8 V at 0.15 A/cm2 at zero anode recycle, and 0.78 V at 48% anode recycle ratio, better than the values obtained in the 18-&l stack. One advantage of anode recycle was the fact that it reduced the voltage dispersion between cells. For example, a spread from 0.73 V to 0.82 V (with zero recycle) was reduced to 0.748 V to 0.795 V at 48% anode recycle ratio, both at 5 atma operating pressure. The stack was stable for 2,000 hours at 5 atma and at rated power, but started to decline thereafter. The test was terminated at 4,000 hours. Decline was thought to be a result of corrosion, carbon deposition, and increase in resistance due to electrolyte transfer in the cells. s*9 Further post-test analysis showed that mismatching of pore size characteristics between the anode and the matrix resulted in a low filling of the anode with electrolyte.jjO IHI reported testing a 2 kW atmospheric pressure plant331with a 1,000 cm2, 20-cell stack in 1990. This used the B-E external, flat-plate reformer with a catalytic combustor,r9 which has been licensed by MC-Power for use in future systems. 199 In the system, pressure control over the anode and cathode gas streams at their exits was eliminated by mixing the streams in the reformer combustor (c.f., Ref. 199). The pressure difference never exceeded 200 mm of water, which was insufficient to cause cross-leaking. A water condenser was used after the combustor, and part of the resulting stream was recycled to the cathode to raise the CR partial pressure. The condensate had a pH of 4-4.5, and contained Li3+, K+, and Fe3+ ions in amounts not exceeding 0.5 ppm. The same concentrations were found at the anode exhaust, indicating negligible electrolyte loss by evaporation. Exhaust N& levels were below detection limits, and about 10-45 ppmv CG and 150 ppmv of methane were measured. The plant was operated for 3,000 hours, and partial-load and transient characteristics were examined. 331 The reformer consists of an intemallymanifolded sheet-metal stack, each element of which consists of an empty dispersion chamber, in which the fuel supplying the enthalpy of reforming passes through a perforated plate into a planar catalytic burner, which is supplied with air in a co-flow configuration. The NG-steam mixture is in the third reforming chamber, and is also supplied in a co-flow configuration.332 As a preliminary to further scale-up to a 50 kW, 50-cell, 1 m2 stack, a tall stack (50 cells, 0.3 m2, 15 kW) was operated at atmospheric pressure for 1,400 hot hours over a total period of 4,300 hours, which included 7 thermal cycles. Nitrogen crossover tests were performed after thermal cycling. At 0.15 A/cm2 and at 75% fuel utilization, the average cell performance was 0.656 V. The rather low performance was attributed to higher than expected IR and the use of lean gas mixtures resulting from the use of cathode gas recycle, however, the individual cell performances were rather uniform.s33 The next scale-up was a 50 cell, 50 kW atmospheric pressure stack with 1 m2 cells, again with a cathode gas feedback loop operating on lean gases.334 This operated for 2,500 hours, and its initial performance at 70% fuel utilization (on simulated reformate with a steam-to-carbon ratio of 3) and 28% oxygen utilization at 0.15 A/cm2 was 0.723 V. At 80% fuel utilization, the corresponding cell voltage was 0.709 V. Again assuming sensible heat reforming of methane, these voltages and utilizations would correspond to gross HHV efficiencies of 43.9% and 49.1% respectively (48.3% and 54% LHV), showing the effect of higher fuel utilization in raising efficiency, if the system permits this. An analysis of its performance showed little decay in the most stable cells, but an overall decay of 46 mV per 1,000 hours was observed, twice that in the previous 10 kW short stack.335 Two 50 kW 1 m2 stacks were constructed and tested to verify tall stacking of full-scale components (50 cells in a single stack) and operation of two 25-cell sub-stacks connected via a central divider. After operation, the latter stack was cooled down, transported, and operated again to simulate delivery to Akagi 3s. Following this, a 102-cell, 1.015 m2 (active area, 0.56 m x 1.8 m) pressurized 100 kW stack with cathode gas cooling was constructed. It consisted of two 51-cell substacks with a central divider, and like all previous IHI stacks it used a tie-bar compression system (four tie-bars on the two long sides). Because importance of flatness and uniformity of component thickness, special efforts at quality control were required Laser inspection of tape-cast components cast on semi-transparent plastic films checked absence of pinholes and defects and allowed thickness measurement. It proved possible to produce tape-cast component sheets 0.75 mm thick, 1 meter wide and 400 meters long with a thickness variation of 2% (&15 pm). A furnace capable of simultaneously sintering four green 1 m x 2.5 m tapes was installed. Sheet metal bipolar plates with aluminized edges are seam-welded in water by electrical resistance heating to avoid mechanical distortion. Each anode, bipolar plate, and cathode could be mechanically stacked with electrolyte tapes. The stack was tested at 0.07 A/cm2 and 44% fuel utilization at IHI (185 hot hours, 110 hours of power generation), since 62 kW was the upper limit of the in-house equipment. After being transported over the 300 km to Akagi 3S using a vibration-isolation suspension system, it was operated for 5,118 hot hours which included 3,935 generating hours (318.5 MWh) between August 1993 and June 1994. It delivered 129.2 kW (0.836 V average) at 0.15 A/cm2 at 60% fuel utilization on NG reformate (steam-to-carbon ratio, 3.5) on reference oxidant at 5 atma in August 1993, and 124 kW (0.80 V

Fuel cell technology

597

average) under the same conditions at the required standard 80% fuel utilization.336 However, in continuous operation, the C@ partial pressure was limited to 1.0 atma to reduce cathode dissolution. After 464 operating hours, the stack had an average cell voltage of 0.805 V under the standard conditions, with a standard deviation of f12 mV. However, between about 500-600 operating hours, the average voltage increased reaching a maximum of 0.825 V at 70% fuel utilization. After this it decayed to about 0.725 V at 1,200 hours. The standard deviation then approached f40 mV. After periods of oscillation, some recovery and stabilization to approximately 0.77 V (standard deviation, f15 mV>occurred by 3,000 operating hours. The changes were associated with measured voltage differences between the inlet and outlet sides of the bipolar plates, suggesting circulating or short-circuit currents which may have been initiated by a rapid gas purge with redistribution of electrolyte during a facility outage. Short-circuit currents were estimated from gas analysis data to be negligible up to 2,000 hours, rising thereafter 10 mA/cm2 (6.7%) at 3,500 hours, with a maximum of 40 mA/cmZ (26.7%) at 4,500 hours. These were attributed to cathode dissolution and nickel precipitation, but when the stack was disassembled, little corrosion was apparent. These problems required clarification in future work, and the lowest steam-to-carbon ratio consistent with no carbon deposition was to be identified to further improve performance. 322 IHI planned to use four 70-cell modules for each of its two 250 kW stackss36 for the CHEPCO Kawagoe 1 MW pilot plant with installation expected after the PAC test in late 1996.314 Stacks using different types of hardware had been tested since the program started at II-II, and those using ‘Hard Holder” and “Sheet Metal Type B” technology showed much lower performance decay (5 mV per 1,000 hours) than those using “Sheet Metal Type A.” The “Hard Holder” technology consisted of aluminized AISI 310s stainless steel. The major difference between the two sheet metal technologies was that “A” had seven sheets of corrugated plates, whereas “B” used five sheets with a bimetal bipolar plate. The loss of electrolyte in the stack examined in Ref. 319 was 21 mg/cm2 per 1,000 hours, with more lithium loss than potassium. About 80% of the electrolyte in the electrodes showed creep to the cell hardware, but only 5% was lost from the matrix. If the decay rate was to be below 2 mV per 1,000 hours, a loss rate of 1.4 mg/cm2 per 1,000 h was requited. Electrolyte loss resulted from evaporation, reaction of alkali metal cations with oxide scale, and by the reduction of capillary forces in the matrix and electrodes as a function of time. Examination of the corroded cathode 310s current collector estimated loss by corrosion to be 10 mg/cm2 of Li2CO3 and 3 mg/cm2 of K2CO3 over 40,000 hours, representing average depths of scale of 35 pm (maximum 70 pm) at the front of the collector, and half of this at the back. Scale depths were proportional to the square root of operating time. Although it seemed clear that the presence of multiple metal surfaces in the cell will increase corrosion and dissolution of chromium as potassium chromate, especially from high-chromium steels such as SS310, it was still difficult to explain the high carbonate loss with the hardware in question. 335 An advanced bipolar plate had been developed, which had been scaled up to a 0.25 m2 proof-of-concept size by 1992. It consisted of only three parts, a corrugated metal sheet with a masking frame on each side. All components were appropriately internally manifolded. The sheet and frames were laser-welded to avoid deformation. This bipolar plate required anode and cathode current collectors of pierced sheet-metal.32 Like MELCG, II-II has reported the development of a C@ (and H20) separator, this time using liquid absorption, which required a negligible heat input ?s7 The low-temperature process was claimed to require 0.78 MJ/kWh of low-temperature heat to serve a plant with 50% HHV efficiency, which may be 36% of available waste heat (assuming 80% total thermal efficiency for the fuel cell system). The advantages would be high cell voltage, higher fuel utilization, even at low reforming conversion, e.g., 65%. This may increase system efficiency by 7 or more percentage points, and eliminate a high-temperature cathode recycle blower.3s7 II-IIhas described its component development, and has shown the changes which occurred in a 10,100 hour, 0.25 m2 4-cell stack test.38 The specific surface area of LiAlR decreased from 90 m2/g to 50 m2/g. This could be reduced by 50% by operation at 630’~640°C, rather than 65O’C. Additives, including other types of LiAlOZ,powders with rod structures, Zr@, TiOz, and other materials, were being examined to improve the creep strength and microstructure of the matrix. Chromium at 10 wt % loading used as a sintering inhibitor in the nickel anode became lithiated during the 10,100 hour test, consuming carbonate. This resulted in examination of a chromium loading of 8%, and the use of Ni-Al. The latter was made by mixing Ni powders with Cr-Al intermetallic. At 2 wt % loading, its creep resistance was equivalent to that of a standard Ni-Cr anode. At the cathode, an oxide-dispersed nickel sinter was being examined, which shows less deformation on oxidation, and a much smaller nickel solubility (50-6796 less than that of conventional cathodes).33* Dissolution of nickel oxide has been examined. The amount of nickel in the electrolyte was shown to increase with C@ partial pressure,339confirming other work (Refs. 6, p. 571, 37,214,249,250,340). As in Ref. 37, the II-II workers noted a non-linear dependence with time, which approximates to a square root relationship.340 II-II and the Tokyo and Toyo Gas Companies examined a 0.5-l MWe cogeneration system in 1991. Transportation considerations dictated a packaged design, each unit having maximum dimensions of 6.0 m x 3.2 m height and width. The power footprint of the fully automatic, remote-dispatch unit was to be 0.1 m2ikW. Four different systems were examined, a basic external nforming system using the flat-plate heatexchange reformer, one using two stacks with anode and cathode gas flows in series to ensure improved

598

A. J. Appleby

gas utilization, a third system with both stacks and reformers in series, and a basic system with anode recycle. The fuel utilizations of each under atmospheric pressure conditions were 80% 908,908, and 86% respectively. Their LHV electric power generation efficiencies were respectively 43%,47% 49%, and 45%, with overall thermal efficiencies of 78%. 784,842, and 85%, and heat-to-power ratios of 0.81, 0.66, 0.70, and 0.67. Under pressurized conditions and excluding the anode recycle case, the corresponding figures were 47%. 5296, and 54%; 91% 91%, and 92%; and 0.91,0.91, and 0.92.341 Toshiba Coporation (R&D Center and Works, Kawasaki): Toshiba has an exchange of information agreement with IFC on the MCFC.zrsJ@ Little information was available, beyond the fact that the company was examining endurance issues and stack designs with mechanically-sealed manifold gaskets, and had the capability of tape-casting 1.2 m wide components. 342 Recently, an advanced experimental bipolar plate has been developed with partial support from the MITI-NEDG New Sunshine Program.ja It consists of thin (0.3 mm) sheet metal and it has five major sheet metal parts (two current collectors, a separator sheet, and two edge sheets). It is illustrated as an internally-manifolded co-flow system which differs from early subscale versions of MC-Power/IGT bipolar plates in not using the electrolyte matrix in the manifold atea as a seal. In this respect, it appears to resemble the proposed General Electric bipolar plate of the early 198Os.41However, the electrolyte matrix layer extends to the edges of the plate which are parallel to the reactant flow, where a series of four flat springs within the sheet metal plate maintains pressure. The manifolds in successive plates are insulated via magnesia dielectric seals. The latter are nickel-brazed to sheet metal (ferritic stainless steel) stress relaxation rings. Spring relaxation and creep over a 40.000 hour lifetime has been examined, and found satisfactory. Manifold creep was being examined, and no manifold leakage was detected. In late 1994, the demonstration of a three-cell 1,200 cm2 short stack with four bipolar plates was planned. s4s Toshiba personnel have examined matrix degradation in MCFC,ja and conducted modeling studies,sGa including nickel oxide cathode dissolution models. The model used is essentially that described in Ref. 214. Cells were constructed with a stable, electronically conducting “trapping layer” in contact with the cathode. Tape-cast LiFea was used for this component. To further retard dissolution, Li/Na carbonate electrolyte was used (cf., Ref. 212 and discussion under MC-Power, above). Results with in situ and ex situ oxidized cathodes were compared. The amounts dissolved with either ex situ oxidized cathodes without the LiFeo;! layer, or in situ oxidized cathodes with the LiFea layer, were about equal, and were one-third of those from an in situ oxidized cathode without the barrier layer, A cell with ex situ oxidized cathodes, LiFe@ barrier layers, and Li/Na eutectic could be operated without shorting for 2,000 hours at 3 atma C&, and showed only 20% of the dissolution of that for a cell with in situ oxidized cathodes, no barrier layer, and Li/K eutectic. The ex situ cathode was prepared in Li/Na eutectic by heating in standard oxidant at 7OO’Cfor 50 hours. These interesting results suggest new ways of stabilizing cathodes, including preheating of stacks to a uniform temperature of 7OO’C for 50 hours before operation at normal temperatures.s‘tsb MCFC Components: Components and other items for the MCFC have been developed by other Japanese companies. These include a 30/40/1.0/0.05/28.5 Cr/Ni/Al/Y/Fe alloy for bipolar plates at NKK Steel, which may be useful without nickel cladding on the anode side.s46 In more recent work, the Cu composition is increased to up to 35 wt %, and it is reported that the addition of 1 wt % Al and 0.04 wt % Y reduces the electrochemical corrosion rate to 5% of that of AISI 310s in the anode environment.j4’ A nickel-plated stainless steel has been given a highly corrosion-resistant nickel aluminide (A13Ni2)layer at Nisshin Steel (Ichikawa, Chiba, and Shin Nanyo-shi, Yamaguchi).34* The A13Ni2 produced by heattreating Al-plated Ni (on AISI310S) at 75O’C in argon for one hour changed in composition to an equally resistant AlNi layer (because of LiA102 formation) after 4,000 hours exposure to the MCFC anode environment.~7~349 Aluminum is plated on nickel using a 60°C molten salt bath.s49 The Mitsubishi Materials Corporation (Omiya-shi, Saitama) has extended its earlier work on Cu-based alloy anodes,3o1 showing that the polarization performance of 45/50/5 Cu/Ni/Al is identical to that of Ni-8Cr. Negligible creep was seen in the anode environment over 2,000 hours.347 The joint studies reported in Ref. 347 am now supported by the Japan Research and Development Center for Metals (Minato-ku, Tokyo). Matsushita Electric Industrial Company (Moriguchi, Osaka) has reported in-cell sintering of green anode tapes, even those containing Ni/Al alloys. Sintering appears to be favored by the presence of carbonate.sss The same company has examined lithium nickel oxide (LixNil_xO, O.l
Fuelcell technology

599

the elecrrolyte,3s4_3s’their effect on nickel oxide solubility,3s8 and bipolar plate corrosion studies (at Osaka National Research Institute, AIST, until October 1, 1993 the Government Institute of Research at Osaka, GIRIO).js9 Other work includes bipolar plate corrosion, 360the stabilities of metal oxides and metals,361 modeling of cathode kinetics,362 corrosion studies on Fe-Ni and Fe-Cr alloys,363*364 corrosion of bipolar plates and carbonate loss, 365 high temperature corrosion of chromium,366 and impurity effects of gas electrode reactions.%’

Republic of Korea: The Korea Electric Power Corporation, Taejon; the Institute of Science and Technology, Seoul; and the Electrotechnology Research Institute, Changwon are developing a strong interest in MCFC technologies. After studies starting in 1989, the development program started in 1993 with $9 million funding from government and electric utility sources. The first objective is a 2 kW 0.1 m* MCFC stack which will use standard components. It is planned for operation in 1996, and will be followed by a scaled-up 100 kW system. A 2,000 hour endurance test on a 100 cm* single cell and testing of a 20cell, 100 cm* stack have been conducted under low utilization conditions on simulated NG reformate and reference oxidant.sas Hydrogen separation from anode exit gas using inorganic membranes has been studied for system recycle.369 Materials studies have included the use of perovskites as MCFC cathodes (e.g., lanthanum. strontium cobaltate, whose stability is in any case suspect),370 and a study of pack aluminization for preparation of Ni-Al anodes.s71 Generalized analyses of the way in which generic fuel cells would perform when connected to the grid have been performed,372 c.f., work at Japanese Gas Companies.373*374

27. SOFC PROGRESS

Overview of Programs: An overview of world SOFC activity to late 1993 was available:.375In the United States, Westinghouse continued to be the major developer of SOFC technology. This technology remains of tubular type, which was devised in 1980 to solve the connection and fabrication problems of previous concepts. At the same time, there were several developers of planar SOFC technology in the United States. An overview of SOFC development in the United States up to early 19933’6indicated that the Westinghouse tubular cell had been scaled up from 36 cm to 100 cm length in preparation far a 100 kW unit, which was planned in 1994. A 20 kW generator had operated for about 3,000 hours on hydrogen, NG, and naphtha. Two 25 kW generators, one with dc output, and the other ac, had been tested by customers for more than 1,400 hours each. Individual cells and multi-cells had operated up to 32,000 hours. The monolithic planar system (MSOFC) had been tested at AlliedSignal in single laboratory cells of 2.5 cm x 2.5 cm area, and a mock-up non-functional 100 W stack had been made to determine process feasibility. Both of the above DOE contractors were being funded to develop generators. The Advanced Research and Technology Development Program (AR&ID) was being pursued at Argonne National Laboratory (ANL, Argonne, IL). Pacific Northwest Laboratories (PNL, Richland, WA), and at the Westinghouse Science and Technology Center (Pittsburgh, PA), with work on seals and alternative electrolytes, alternative materials, and contaminants, respectively. The University of Missouri, Rolla (UMR), ANL, and PNL were being funded to address fundamental issues. Other work was being funded under the Small Business Innovative Research (SBIR) program and under GRI and EPRI activities. The program goals were to $l,OOO/kWfor mature installed NG units, and $1,2OO/kWfor corresponding coalfired units, with an operating cell life of 40,000 hours. For the Westinghouse tubular technology, excellent performance to 25,000 hours had been seen. Goals were 0.70 A/cm* at 0.5 V to 0.25 A/cm* at 0.7 V. These values may be obtained by the use of an electronically-conducting support tube consisting of air electrode (c.f., Figure 5, corrected cathodically by about 35 mV for operation on reformate). Which set of conditions would be used wodd depend on the trade-off between capital cost and efficiency in a given application. Cell length was expected to grow further to up to 2 m. For the MSOFC, the init& goal was 0.15-0.25 A/cm* at 0.5 V, to be obtained in 100 W stacks with 15 x 15 cm electrodes. Commercial systems were expected to operate at 0.5 V and 0.50 A/cm*.“6 Stack Costs: A 1992 GRI overview377 stated that whereas materials costs for stacks may be only $8.5O/kW-$18ikW (1995), stacks were projected to cost as much as $850/kW.J7s This resulted from the costs of fabrication of ceramics, which were considered necessary for all parts exposed to an operating temperature of l,OOO°C.A reduction of operating temperature to allow the use of metals, e.g.., for bipolar or other inter-cell connectors and in heat exchanger parts, was desirable. Predicted costs for ceramic heat exchangers were from $450-$1 ,lOO/kW (1995).a’9 Many of today’s ceramic components were not ideal from the viewpoint of electrical conductivity, and improvements in manufacturing techniques were also required. Largely because of their mixed conduction, lanthanum strontium ferrite and cobdtite were an improvement over lanthanum strontium manganite (LSM) as cathodes, but their thermal expansion

600

A. J. Appleby

mismatch with YSZ made then unsuitable for use. A model had been developed at UMRsa to predict expansion coefficient, and as a result, mixed ferrite-cobaltite compositions had been identified with the desired properties. In general p-type materials may be used at the cathode, and n-type at the anode. Zirconia doped with terbia (p-type) and n-type titama-doped zirconia were being developed as possible cathode and anode materials at the University of Pennsylvania. Work at UMR and at the Lawrence Berkeley Laboratory (LBL) was examining new methods of fabrication of very thin (0.1-2.0 pm) components on suitable substrates by plasma-enhanced chemical vapor deposition and by the sol-gel application technique, respectively. The conductivity of these thin films will not limit cell performance, even at 3OOOC.New electrode materials are another possibility, c.f.. work at Eltron Research. These are reviewed below. A second GRI overviedsl stressed the use of planar cells, which would allow less costly processing techniques, such as tape-casting, calendering, screen printing, spin-casting, and sputtering. The competition for the SOFC would be small reciprocating-engine cogeneration plants with 27-35% electrical efficiencies, which cost $3,75O/lcWto $1,6OO/kW(1995) in 10 to 50 kW units’,decreasing to $8OO/kWat 500 kW size. With an SOFC of electrical efficiency in the 40%-58% range depending on power density and with gas costs of $2-$3 per MMBTU, the allowable stack cost would be approximately $215-$65O/kW (1995, installed), with total system costs two to three times higher. In multi-MW sizes, the competition would be gas turbines, and SOFC system costs must then be $425/lcW to $585/kW (1995). An SOFC, whether planar or tubular, will most probably use small cells or at least small cell elements, with a maximum area of about 500 cm2 (22.5 x 22.5 cm plates or 1 m x 1.9 cm tubes), which must be arranged to minimize ducting and manifolding. Ref. 38 1 examined some materials costs based on then-current prices. They are used again here to reexamine comparative materials costs of different cell structures. Tubular cells on 40% porous stabilized zirconia or cathode material support tubes with the dimensions used by Westinghouse would weigh 10.3 kg/m* of active area. The materials cost of the support tube dominates the total materials cost, which would be $677/m* for YSZ at $66/kg, or less for calcia-stabilized zirconia. If we assume 40% porous electrodes each 100 pm thick, and a 10 pm YSZ electrolyte, the specific weight of the electrochemical element itself would be 0.33 kg/m* for LSM (at $25O/kg), 0.22 kg/m* for YSZ, and 0.25 kg/m* for nickel (at $lO/kg), a total of 0.8 kg/m*, with a materials cost of $100/m*, 83% of which is the LSM cathode. The cost of a narrow 100 l.trnthick lanthanum magnesium chromite interconnect at $25O/kg would add $14/m*, giving a total of about $790/m* (support tube 86%, cathode 10%). For LSM air-electrode-support (AES) tubes (8.8 kg/m*) with applied LSM cathodes, the total cost would be $2,314/m*, 99% of which would be the AES tube and cathode. For planar cells, a doped lanthanum chromite interconnect (again at $25O/kg) with a 0.5 mm web and 0.5 mm ribs would weigh 5.5 kg/m* and would have a materials cost of $1,375/m*. If ultra-thin electrolyte layers are not technically feasible from the fabrication viewpoint (but c.f., AlliedSignal, below), increasing the YSM electrolyte thickness from 10 pm to 50 pm would add $14/m* to the total materials cost. A realistic power density of 0.2 W/cm* (2 kW/m*) for tubular AES or planar systems indicates a materials cost of only $50-$6O/kWfor the appropriate electrochemical packages, and $688/kW or $ 1, lOO/kW for the AES tube or planar interconnect, whichever applies. The above costs approximate to 1995 dollars. These costs may be expected to decrease in the future as production rises, perhaps by a factor of 5 or more. However, it seems clear that technologies based on thick ribbed interconnects or thick conducting support tubes will always be at a disadvantage compared with those conceptual systems using metal bipolar plates or monolithic co-tired structures with thin interconnects. This will be true from the viewpoint of materials cost, since the thick structures require more weight of more expensive material. New simplified approaches to tubular cell production or the further development of flat SOFC systems are required to reduce cost. These are still in the laboratory stage in the United States, Japan, and Europe. Bessel has examined the effect of geometry (i.e., lR drop) on power density at a given cell voltage.ss2 He points out that thick ribbed interconnect technologies will also be at a disadvantage compared with those with thin-layer (particularly metallic) separators, because of the lower IR drop and greater performance potential of the latter. Apart from the issue of contact resistances and any requirement for protective conducting oxide layers, the metal bipolar plate should have a substantially lower resistance than a thick ribbed ceramic interconnect, which should allow lower temperature operation. A monolithic design using anode and cathode material for gas channels should have a resistance which is almost as low as that of a metal. Monolithic designs would be superior to those with built-up stack components. Systems with ribbed metal bipolar plates would be superior to those with ribbed ceramic bipolar plates, and would certainly be better than tubular &signs of Westinghouse type, due to their long peripheral current pathway. The differences become more marked at lower operating temperatures. e.g., 9OOOC. We can illustrate some relative materials costs for different advanced designs as follows. A thin-layer cross-flow design (c.f., AlliedSignal, below) may be ‘constructed with two corrugated 50 pm layers consisting of 60% porous anode and cathode material to provide gas channels, each with twice the area of the electrochemical package. Together, these would weigh 0.49 kg/m* (Ni, 0.18; YSZ, 0.11, LSM, 0.2). These gas channel structures would be completed by a thin flat 100 pm bipolar interconnect weighing 0.59

Fuel cell technology

601

kg/m2. This gives a total rib and interconnect weight of 1.08 kg/m2, and a materials cost of $20’7/m2 for this assembly. With the above anode-electrolyte-cathode package (materials cost, !§lOO/m2), the total cost would be about $300/m2, or $lSO/kW or less. A system with a metal bipolar plate may require thicker anodes (0.5 mm) for support during fabrication and handling, which would add 1 kg/m2 of nickel ($lO/mz), and 0.66 kg/m2 of YSZ ($44/m2). A 0.375 mm (15 mil) alloy plate with pressed (e.g., counter-flow) gas channels whose area is twice that of the electrochemical package would weigh 6.5 kg/m2, and would have a materials cost of $13O/m2 at $2O/kg. Thus, a pseudo-monolithic structure with co-fired components might have a materials cost of $300/m2. The corresponding figure for a stacked planar structure with a metal bipolar plate may be $285/m2, Both of these may be able to operate at a higher current density and at a lower temperature than a system containing planar ribbed ceramic interconnects with a materials cost of about $1,500@, or a tubular system with LSM support tubes (about $2,3OO/m2). It must be stressed that these costs are only comparative, and should reduce with time, perhaps to the point where materials costs become insignificant alongside fa’brication costs. This is further discussed in the Section 29, Conclusions. Intermediate Temperature SOFCs: Ref. 381 reiterated the advantages of using thin component layers to allow lower temperature operation, which may require diffusion barriers to prevent inter-diffusion of different components during sintering. For example, UMR had shown that inter-diffusion between LaSrCoFe and YSZ up to sintering temperatures of 1,200’C could by prevented by a thin layer of (samarium-doped) Ce02.3sa UMR was also examining spin-coating of an ethylene glycol solution of the relevant cation nitrates or carbonates onto a substrate to prepare uniform films. The University of ‘Utah was examining ceria-based electrolytes clad on the cathode side with YSZ to prevent development of mixed conductivity. Magnetron sputtering was being used at Northwestern University to develop thin. Ni-YSZ anodes and YSZ electrolyte structures with Ag-YSZ cathodes. Yttria-stabilized Bi203 was being used on the cathode side of YSZ films, with yttria-doped ceria on the anode side, to reduce resistance in low temperature operation. An update of work up to late 1992 by AlliedSignal and by the University of Pennsylvania was also given.s8* A cost-performance study based on Boss& model s8* for SOFCs operating at reduced temperatures has been conducted at GRI.3w The baseline cross-flow cell with standard components was assumed to have a 70 pm thick cathode, a 200 pm electtolyte, a 50 l.trn anode, and a 5 mm thick ribbed interconnect (1 mm wide and 1.8 mm deep ribs, 5 mm spacing). The other assumptions were a polarization resistance of 0.5 R-cm2 at 800°C and an activation energy of 105 Id/mole. The power density at l,OOO°C was taken to be 3.0 kWlm2 (rather than 2.0 kW/m2, above). The total materials cost was $3OO/kW ($900/m.2), rather than $1,14O/kW ($2,850/m2> in the above example. The main reason is the much lower costing of the interconnect and cathode materials (both $75kg, compared with $25O/kg and $265/kg in F:ef. 381). Performance would be much worse, and cost higher at 800°C unless the cell resistance, particularly that of the electrolyte, was reduced by using thinner layers and/or new materials. An improved much lighter interconnect design was also required to reduce its proportion of the total cost. Ideally, its weight and cost should be reduced by 67%. i.e., a plate with 0.5 mm deep ribs and 0.5 mm web, which should b’e feasible for small cells with a cross-flow configuration. Westinghouse Electric Corporation Science and Technology Center (Pittsburgh, PA): Work up to 1991 has been reviewed in Section 20 (above) and in Refs. 59 and 63. Westinghouse was supported by DOE-Morgantown Energy Technology Center, and support for evaluation came from two Japanese consortia. The first was a gas industry group (via GRI) for cogeneration applications consisting of NEDO, the Tokyo, Osaka, and Toho Gas Companies. The second was a similar electric utility consortium (via EPRI), consisting of NEDO, the Tohuko, Chubu, Chugoku, and Kyushu Electric Power Companies, and the Electric Power Development Corporation. sg A 1988 cell was taken off test after 20,000 hours in 1991 having shown a 1.4% per 1,000 hours performance loss, 25% of previous values. Cells from the: 2,600 m2 Pm-Pilot Manufacturing Plant (PPMP) were showing excellent stable performance, e.g., in the 3.10kW GRI system and in the 20 kW module.384 The wall thickness of the porous CSZ support tube had been reduced from 2 mm in early cells to 1.2 mm. It was to be replaced by a tube of air-electrode material in 1993. While 100 cm cells would be sufficient for many commercial applications, longer cells (to 2.0 m) might be required in certain future generatorssss The 20 kW module contained 576 cells (50 cm length), arranged in 3 parallel strings of 192 cells each. The integral fuel reformer was heated by exhaust gas, and like the 3.0 kW GRI unit, it operated on desulfurized pipeline gas, required no make-up water, and used partial recirculation of depleted fuel. Testing started on November 7, 1990, and after 1,850 hours on NG, 725 hours on naphtha, and 425 hours on hydrogen, testing was terminated on September 5,199l. The unit received four thermal cycles during this time.386 In 1991, Westinghouse entered into a Cooperative Agreement with DOE-Morgantown, which would last through 1995. This would focus on the continued development of SOFC systems for NG and coal-derived fuels. By 1992, cell tests had shown 30,000 hours of operation with degradation in the 0.5%-1.5% per 1000 hours range.385

602

A. J. Appleby

Schematics of the two self-contained 25 kW units delivered to the Kansai Electric Power Company, Osaka Gas, Tokyo Gas, and the U.S. DOE, for power generation on Rokko Island, near Osaka, and to Osaka Gas and Tokyo Gas, respectively, have been given. 384 In 1992, the plants were successfully delivered by truck and air-freight.387 The 25 kW nominal (40 kW peak) unit for Osaka Gas, Tokyo Gas, and the Kansai Electric Power Company (the UTILITIES) at Rokko Island was showing NO2 emissions of 0.3 ppmv (at 15% oxygen. dry basis).= Tests of two 18-cell bundles of 50 cm PPMP cells manufactured in 1989 had shown excellent performance over 6,840 hours.as4265 Updates on the 25 kW systems were given in 1992 (including a schematic drawing of the layout)63 and in 1993.ss Operating experience is summarized under Japanese SOFC work, below. Important achievements of the DOE-Morgantown-Westinghouse 1991-1995 development program in 1994 were the operation of two 1989 cells for 50,000 hours, which then showed the same cell voltage performance as those of 1986-87 cells at 5,000 hours and those of 1988 cells at 20,000 hours. More recent cells were showing 0.5% decay per 1,000 operating hours. The objective was a useful tube life of 50,000 to 100,000 hours. Cells with 100 cm and 168 cm active length and increased diameter (2.2 cm with 2.2 mm wall thickness, compared with 1.9 cm and 1.9 mm for 50 cm tubes) had been constructed and tested. Fuel flexibility was demonstrated in a 20 kW module which had operated on hydrogen and NG. as well as on naphtha for 750 hours. Westinghouse built a 20 kW 576-cell system for Southern California Edison (SCE) in 1993-1994. This was installed at the Highgrove Generating Station at Grand Terrace (between Riverside and San Bernardino, CA) in May 1994, the site of SCE’s proposed National Fuel Cell Research Center (cf., the MC-Power 1 MW MCFC demonstrator). This 20 kW unit had operated for 2,000 hours by the third quarter of 1994. It had been shown to be thermally self-sustaining at electrical loads over 18 kW, and had a start-up time of 8 hours. Its automatic shut-off capability in the event of incident was considered to be excellent.389 By March 1995, it had accumulated 5,300 operating hours.9sC A $7.3 million, 30 kW logistic-fuel (JP-8) balance-of-plant funded by the $11 million FY 1994 ARPA (through NASA) defense fuel cell power plant initiative (c.f., ERC, Ref. 191) was under construction in 1994 for delivery to Highgrove.95bf90 A 100 kW cogeneration system for Southern California Gas was planned in 1993-94, and was in the design stage in 1994-95. It was to incorporate AES tubes with 2.0 m length and about 1,000 cm2 active area.390 Another 100 kW unit was to be delivered to the Netherlands in a program sponsored by a group of Dutch, Danish, and Spanish utilities (ELSAM, PGEM, and IBERDROLA) for operation in 1997.9sb*CDesigns of cogeneration systems in the 1 MW class and the use of high-temperature SOFC as a turbine combustor topping cycle were being evaluated. ss” In 1994. Westinghouse was reportedly also conducting work on planar structures in-house for special applications. Costs of Westinghouse units were still a problem for economic commercial applications. The 25 kW as1 The weight of the active tubes system was sold in 1992-1993 for $3 million, more than $lOO,OOO/kW. in the 25 kW system was about 100 kg (220 lb.), yet the core of the 25 kW system weighed S,OOO-6,000 lb.. There is surely some opportunity to reduce BOP weight, therefore cost. In situ doping occurs with EVD, so that it requires only pure single-element oxides. Unlike doped mixed oxides, these are readily available, and are comparatively inexpensive. The LSM air electrode material, which accounts for most of the total weight (about 400 g per 100 cm tube, producing 100 W), presently costs $4O/kg.s92Its cost may eventually be expected to go down to the price of a similar material produced in large quantities, barium titanate ($3O/kg).393 Thus, the AES tube materials cost may then be $12O/kW, with a total cell materials cost of less than $15O/kW, assuming pure oxide starting materials for EVD components. As Section 20 points out, the EVD steps make an excellent product with a low materials cost, but their fabrication cost is still very high. By increasing AES tube size and power density, Westinghouse has significantly reduced fabrication costs. Some further improvement in cost might be achieved by further scale-up of cell size beyond 2.0 m length, but there is a limit to this approach. Westinghouse is making efforts to reduce the number of steps to the minimum necessary. One approach is to co-sinter the support tube and the interconnect, which can now be carried out by substituting calcium-doped lanthanum chromite (LCC, $5O/kg),for LMC, which is not entirely satisfactory from the conductivity viewpoint (the strontiumdoped compound, LSC, is preferred, but the vapor pressure of strontium chloride is too low to allow fabrication by EVD). Westinghouse is examining a further reduction in the EVD steps by co-depositing YSZ for the electrolyte and for the nickel anode cermet. Some hidden materials problems still remain, although system stability has improved greatly with time. The first is long-term stability of the O= ion conduction in 8% YSZ, which has necessitated an increase in dopant level to 10 wt %. The second is the inter-diffusion of manganese ion from the air electrode into the YSZ electrolyte, which reduces conductivity with time. This may either require a different material (which must have appropriate conductivity, activity, and thermal expansion coefficient), or cell operation must be reduced to 9OO’Cto combat diffusion. This will reduce performance. A further problem will occur if the LSM AES tube and the LCC interconnect are co-sintered in air. Sintering of LCC only occurs because a calcium chromate fugitive flux forms. This should disappear on cooling, but its presence may affect the dopant properties of the components during sintering.392 AlliedSignal (Torrance, CA): The three-roller tape-calendering scheme to make the three electrochemical cell components of the proposed monolithic co-fired SOFC has been described.394 The

Fuel cell technology

603

cells design exists in two forms, co-flow with a flat interconnect and a conugated electrochemical assembly (see Ref. 6, p. 608), and counter-flow, with a flat electrochemical assembly in which the gas channels are corrugated, using anode material and cathode material respectively for the corrugations or gas channels. In 1990, it had not proved possible to co-sinter this system from calendered components, mainly beCaUSe Of different shrinkages in components with different chemistry and porosities. Accordingly, AlliedSignal had shown performance which appears to be good in single cells, and in 1990 was proposing to assemble these into stacks which are su rficiaIly monolithic. The system then used a flat magnesium-doped lanthanum chromite interconnect.3 &e Further details of the cross-flow system, which is certainly easier to manifold, have been given in Ref. 395. Single circular cells (5 cm2) had been tested on 97%/3% H2/H20 by the end of 1992. Typical through-plane resistances were 0.6 to 0.8 W cm 2. At low utilization, two-cell stacks gave 0.6 V per cell at 0.20 A/cm2. The major technical challenge was co-firing the new Ca-doped La003 interconnect at temperatures below 1,400’C in air in contact with electrode material, although it would densify to 90+% of the theoretical value when fired alone under these conditions. Liquid phases (calcium oxychromite, Ref. 396) wicked into the anode pores during the firing operation. Anode and cathode layers less than 15 pm thick may solve this problem. 3g5 Further details were provided in later reports, which show improved single-cell performance at l.OOO°C under same conditions as those previously.?@‘Jg* In 1994 technology, the cathode was applied after firing the YSZ electrolyte-anode bilayer. Anodes and cathodes were 120 pm thick, and electrolytes had been made down to 1 pm thickness (see comments under Ceramatec and Domier, below) in a versatile process which could be used, e.g., to fabricate composite multi-layer electrolytes. A small two-cell stack had been tested over 500 hours, and a single cells with unspecified components had been operated for over 1,000 hours without performance degradation. Component bilayers (YSZ plus anode) may be scaled to about 21 cm x 21 cm (about 500 cm2) using threepass tape-calendering. On 85 cm2 cells, AlliedSignal had obtained 0.3 A/cm2 at 0.7 V at 800°C about 0.4 A/cm2 at 850°C, and about 1.0 A/cm2 at l,OOO’C, all at unspecified (but low) utilization. Other data for hydrogen and air (same conditions, with open circuit potentials in the 1.0-1.1 V range) showed 0.3 A/cm2 at 0.7 V at 700°C. 0.3 A/cm2 at 0.9 V at 800°C, and 0.4 A/cm2 at 0.9 V at 900-l,OOO°C. Stack development was pending in 1994.3g8 Ceramafec, Inc.: This Salt Lake City, UT, company is now owned by Elkem (Norway), and is perhaps farthest advanced in the development of planar SOFC stacks in the United States. Accounts of the earlier development of planar SOFCs for GRI were published in 1990. Tape-cast YSZ electrolyte disks were screen-printed with electrode slurries (NiO-YSZ, Lal_xSrXMn@ and La1.,S,CcO3) and sintered in the 1,150’- 1,350’C temperature range. Electrode performance was evaluated by impedance analysis.39 The inter-diffusion region between the above electrolyte and cathode materials was examined after 24 hours at 1,500”C and 1,650”C by microprobe analysis. The formation of lanthanum zirconate appeared to result in high electrochemical losses. Little diffusion of Ni into YSZ was observed under similar conditions.400 Work performed by Ceramatec up to 1992 included: 70 W demonstrated in a 100 W (nominal) stack for ABB); operation of a 40-cell 10 cm2 stack (0.55 V at 0.15 A/cmZ, 97%/3% HZ/HZO, utilization not given); and demonstration of a degradation rate of less than 0.5% per 1,000 hours in single cells. Scale-up studies for Sulzer-Innotec (Switzerland) and the Norcell consortium (Norway - see below) included the demonstration of 0.5 V at 0.30 Alcm2 in a 5 cell stack, and 0.5 V at 0.20 A/cm2 in a 40 cell stack.4Ol Doping of lanthanum chromite interconnect material with Ca and Co was examined using microprobe analysis. It was concluded that it may result in catastrophic failure in the fuel environment (c.f., work in Denmark, below).402 In 1993, Ceramatec was scaling up to 10 cm x 10 cm cells, and planned ii future 1 kW module test, a 3-5 kW prototype system test, and a 50 kW system test in 1996. All Ceramatec stack designs have been based on the use of a LSC or LCC ribbed bipolar plate in a cross-flow arrangement. The maximum cell size is limited to about 20 cm x 20 cm because OFceramic strength, flatness, and fabrication constraints. Ceramatec had tested several 10 cm x 10 cm (81 cm2 active area) stacks with up to 50 cells. The latter were rated at 600 W, and have operated on internally-reformed natural gas at an average temperature of 9OOOCat 0.25-0.3 A/cm2 at 0.7 V at 80% fuel utilization. Cooling was via process air flow at 10 stoichs. The air inlet temperature was 800°C, and the temperature gradient across the stack was typically about 14O’C. A 1.4 kW (nominal) system with four 50-cell stacks operated for 1,800 hours with 4% decay per 1,000 hours, but these results were not yet reproducible. Stacks had withstood 29 thermal cycles from l,OOO”C to room temperature with no performance decay. Cycling was with oxidized anodes, since nitrogen was substituted for fuel gas at 600°C (c.f., Domier, Germany, below). Ceramatec planned to use successive stacks operating at the same current density but at different voltages via a series fuel supply to increase utilization (c.f., Siemens, and the “Train Cell” at the National Chemical Laboratory for Industry, Tsukuba, Japan, see below). A number of stacks (e.g., five) were to be arranged around a central air exit manifold (cf., Siemens, below). The tape-cast YSZ electrolyte was typically 150-160 pm thickness, with a goal of attaining 25-50 Km. Electrolytes had been made in thicknesses down to 20 pm, but none less than 110 pm thick had proven satisfactory under real operating conditions due to thermal stress effects resulting from the temperature gradient across real stacks (c.f., AlliedSignal, Domier). Ceramatec had equipment available to cast 2,500

604

A. J. Appleby

meters (30 cm wide, shrinking to 20 cm after firing) per hour. Based on Kyocera’s cost for processing fine alumina (about $155/m2), fabrication costs of about $SO/kW were expected. Ceramatec had a materials cost target of $17/kW (1994), excluding the interconnect. The cost of LSC was $3OO/kg, and the 1994 stack design required 6 kg/kW, 70% of which was lost in machining. ‘lhus, materials costs must be drastically reduced. A lower cost limit for component materials was the price of barium titanate ($3O/kg in industrial quantity). Vendors (e.g., Rhone-Poulenc) may be expected to sell LSC at $5O/kg in 20 MW quantities. While SOFC developers who do not use the Westinghouse EVD method to create the electrolyte - anode cermet interface had often encountered high anode polarization, the anode fabrication technique used by Ceramatec produced an interface showing excellent electrode performance. Like AlliedSignal, the company emphasized the necessity of demonstrating the ability to operate effectively at 8OO’C (the present stack inlet temperature), and preferably at temperatures below this to allow greater flexibility from the viewpoint of materials and BOP.393 Ztek, Inc. (Waltham, MA): The engineering of a 10 cm diameter circular stack was described in 1990. The system consisted of intemallyIts performance was 0.7 V at 0.3 Alcm2, at unstated utilization. manifolded bipolar plates and electrochemically-active layers with internal seals. It could be fitted with internal reforming plates. The cells were 1.6 mm thick. A lo-cell stack was tested to 1,000 hours.403 The claimed weight per unit area was 2.1 kg/m 2,4Oswhich was sufficiently light for space applications,404 and sufficiently robust for use as a range extender for electric vehicles. 40s A more complete description of the stack was given in 1992. The corrosion-resistant and conducting bipolar plates could seal by being springloaded in tension against the electrochemically-active layers, which were held in radial compression. The modular system was proposed for use in sizes up to 100 MW (for repowering of existing power plants), and down to 1 MW (for cogeneration applications). Heat transfer to a steam or gas turbine bottoming cycle would be via radiation in the proposed Radiant Thermal Integration system, or via conventional heat exchangers from gas streams. The stand-alone fuel cell was estimated as having 50-55% LHV efficiency, or 67-70% LHV with a bottoming cycle. 406 Other technology updates were available in 1994.407efb By late 1994, Ztek had operated a 15 cm diameter, IO-cell stack which delivered 0.1 kW, and had been thermally cycled 10 times. A 114-cell stack with the same diameter (1 kW at 0.65 V and approximately 0.1 A/cm2 on simulated NG reformate with a simulated steam-to-carbon ratio of 2 : 1 at 70% fuel utilization) had operated for 3,000 hours with unstated performance decay. A 25 kW “building block” module was planned. Work with Foster Wheeler Development Corporation, Livingston, NJ had shown that 63-68% LHV efficiency might be obtained in 50 MW steam turbine hybrid systems, and 73-76% in 200 MW systems. In a gas turbine hybrid system up to 50 MW in size, an LHV efficiency of 70% may be possible.407b Babcock and Wilcox (Lynchburg, VA): This company initiated a planar SOFC program in April, 1992. The objective was to demonstrate a 5 cm x 5 cm 3-5 cell stack operating at 0.6 V and 0.50 A/cm2.m No further details were available at the time of writing, beyond the fact that the company had licensed technology from Norcell (Norway, see below) in June 1994. This included Ceramatec-Elkem technology. Technology Management Inc. (TM, Cleveland, OH): The Interscience Radial Flow (IRF) SOFC is reportedly somewhat similar to the Ztek system, with internal manifolding via holes, and outward radial coflow of reactant gases in each cell. It used metal bipolar plates. The system was developed at Sohio-BP during the 198Os, and was then acquired by TMI. A unique feature of the system is the use of particulate, rather than sintered, air electrodes, which are claimed to remove the need for a matched thermal expansion coefficient. How they perform is unknown. The claim that they can operate three-dimensionally by having mixed ionic and electronic conductivity is difficult to understand if the particles are simply in contact, since O= ion conduction between particles will not be possible. Argonne National Laboratory (Argonne, IL): ANL invented the monolithic SOFC concept in 1985. As has been indicated, this technology was transferred to AlliedSignal Corporation. Emphasis is now on the horizontal and vertical scale-up of the SOFC, and on SOFC operation at 8OO’C. The use of dip-coating to prepare very thin component films has enabled excellent performance to be obtained at 800°C, for example, 1.3 A/cm2 at 0.9 V at low utilization. Materials studies include zinc-doped Lal-xBi,AlOg, Bi2A140g LaSr(Al,Zn)xOex, all of which showed good conductivities at 800°C, close to or exceeding the target of 10-t R-l cm-1.409 ANL has developed new glass ceramic seals, together with a new Ni-Fe alloy for bipolar plates which has a coefficient of expansion matched to that of YSZ. A solid-state FC operating at 500°C is considered by ANL to be a good candidate for an internal-reforming methanol system. The properties of new borate glass-ceramic seals developed to avoid the interaction of silicates with SOFC components have been reported.410 Pacific Northwest Laboratories (Richland, WA):: PNL has studied the effects of sintering conditions on lanthanum chromite interconnect material, particularly when calcium-doped. The material was prepated by the glycine-nitrate method. The authors concluded that sintering will require careful attention to green

Fuel cell technology

605

density, because of shrinkage. Material also containing cobalt did not densify until 1,400°C.41t Rapid shrinkage was also identified with Y(Ca)Cr@ (YCC) material. 412 Calcium zirconate and nickel chromate were observed to form in reactions between interconnects and anode materials. With Y(Ca)CrGj and Y(Ca)MnOg, a CaCt-04 layer was obtained. 413 Oxygen reduction has been studied on Y(Ca)MnOg and La(Sr)MnOs using impedance methods. 414 The thermal expansion coefficients of LSC, LCC, and YCC (dopant 0.3) have been studied as a function of oxygen partial pressure.4ts University of Missouri, Rolla: At UMR, addition of Ca (lo-30%) a.nd Co (up to 30%) was studied to improve the sinterability of the family of #+-doped lanthanum and yttrium chromites at 1,400”C in air during co-firing with other cell components. When doped with Mg2+ or Sr2+, they are normally only sinterable at 1,775OC and at 10-g to 10-12 atm a. Compositions were identified which would air-sinter below 1,500”C to 95% of theoretical density. 416 The LSM-YSZ interface was studied after firing at 1,300V for extended periods, and the growth of a lanthanum zirconate layer was identified (c.f., Ref. 400). The same paper illustrates the use of the spin-coating technique (cf., Ref. 381) to make a thin, dense layer of YSZ on LSM at low temperatures. The asdeposited film is amorphous, and starts to become crystalline at 600°C. with subsequent grain growth. In addition, low-temperature operation of an SOFC using thin films and better materials still does not solve the problem of slower oxygen electrode kinetics between 600°C and 800°C. The best properties were exhibited by La&$r().4Cot).2Fe().gG (LSCF, c.f., Refs. 377 and 380). The CeSmn.202.3 (CSO) buffer coating between LSCF and YSZ (c.f. Refs. 380, 381), which eliminates high-temperature interactions during sintering. was described.4*7 More recent details on the spin-coating products have been given.418 and the interface has been examined by XRD and impedance spectroscopy.419 The conductivities and thermal expansion coefficients of LSCF (Lal_,Srx,Col_,FeyG3, with 0.2cxy>l) were determined. Increasing both x and y increased electronic conductivity, and increasing x stabilized the high-temperature phase. Increasing y from 0 to 0.8 for x = 0.2 decreased the thermal expansion coefficient from 20 x 10-6pC to 12 x 10-6/°C.420 The solubility of Ca in La.003 as a function of temperature, and liquid phase behavior (c.f., Ref. 396) was also determined. The maximum solubility occurred for the most homogeneous distribution, and was about 30% at l,OOO°C, and 20% at 900°C, which set the limits for optimum liquid phase sintering and solid solution stability at SOFC operating temperatures.421 Other researchers at UMR were collaborating with Penn State University on the development of a new cathode material, Y l_,Ca,FeO3 (YCF). 422 More recent work has examined cells in which one component serves as the substrate. This component may be a 100 pm LSCF cathode:, c.f., Ref. 416, a 60 l.trn YSZ electrolyte, or a 100 urn porous (graded porosity) Ni-YSZ anode.

Each of the above

carry 1 l.trn layers of the other two active components. The object (under GRI support) is an operating temperature in the 600-8OO’C range. Other new cathodes include YCF. Results suggest that OS-O.75 W/cm2 can be attained at low operating temperatures.423 Eltron Research, Inc. (Aurora, IL): The range of alternative perovskite electrolytes which have been examined for the intermediate temperature SOFC for GRI included XYu.gGd&, with XY = CaCe, SrCe, BaCe, and EuTh; XYo.gCa03-u, with XY = LaSm and LaEr; SrZru.gScO3_o; LaGdcgCdO3_o; and BaTbc.gIn03_o.424 Other SOFC-Related Work: Rare-earth titanate pyrochlotes (R2Ti207, with R = Sm, Gd, Y) have been studied as alternative electrolytes at the Massachusetts Institute of Technology.4ss The properties of ceria doped with a rare earth carrying thin films of YSZ as an intermediate temperature electrolyte (University of Utah),426 as well as those of thin-film tetragonal YSZ (partially stabilized zirconia, PSZ, l-3 mole % Y) prepared by radio-frequency sputtering (University of Hawaii at Manoa),427 have been studied. This material shows a higher oxide ion conductivity below 6OOOCthan cubic YSZ, in spite of having a lower concentration of oxygen vacancies .427 Other materials work included experimental porosity characterization of Ni-YSZ anodes via an Archimedean displacement method (MIT),4ss oxygea diffusion studies in LSCF (Stanford University), 429 and interfacial resistance studies on intermediate temperature SOFCs with thin YSZ electrolytes (Northwestern University) .a0 The cells used Ag-YSZ cathodes and NiYSZ anodes, in some cases with yttria-doped ceria and bismuth oxide layers with YSZ on the anode and cathode sides, respectively.430 The SOFC has been studied as a chemical reactor for the partial oxidation of methane to produce H$O over an iron electrode in a SOFC at 950°C (Tufts University) .@t Modeling work has included temperature and current density in a tubular cell (Georgia Institute of Technology),4s2W internal refonnin$s4 and the risk of anodic carbon deposition (both at the Illinois Institute of Technology)4s5 and study for NASA on monolithic solid oxide electrolytic cells operating as water electrolyzers (Cleveland State University).“‘j

606

A. J. Appleby

Overview: Work in Europe is of rapidly increasing importance, but existing programs are quite recent. In the late 198Os,a number of European countries started to show interest in SOFC technology. As was indicated in Sections 24-26, regulations requiring future cogeneration, therefore decentralized power generation, provided the driving force. Both the MCFC and SOFC potentially offered exceptional efficiency in both stand-alone and combined-cycle plants. Stand-alone plants could furnish high-quality waste heat without degrading the thermal efficiency of electricity production. Because of the lack of management problems with liquid electrolytes, corrosion in the SOFC was considered to be a minor problem compared with that in the MCFC.437 and work at Brown-Boveri and Co. (BBC) had shown extensive lifetimes on small SOFCs in the 1970s.58s437However, the opening of a potential market for small tubular bell and spigot cells (see, e.g., Ref. 6, p. 590-591) seemed improbable in 1978, and development was terminated at that time. After the increase in OPEC oil prices following the 1973 Yom Kippur War, the CEC instituted a hydrogen program for the storage of nuclear electricity (or heat) in a useful form. This led to the development of a 2 kW tubular solid oxide electrolyzer (“Hot-Elly”) at Domier in Friedrichshafen, Germany by 1987, which assured continuity in expertise. By the late 1980s. many European research institutions’considered that they were much more capable of developing SOFC materials than those for other utility fuel cells, where they felt that catching up with developed technology in time to reach the marketplace was improbable. The SOFC had design challenges, which they felt confident could be overcome. Ceramic materials appeared to be part of the design future of many devices (e.g., small gas turbines, high-efficiency diesels) whose development would otherwise be difficult, if not impossible. The SOFC fitted in with this trend. With one exception, the SOFC designs which had developed into small practical units in the 1980s were all tubular. Individually, these could only be scaled up in one dimension. As a result (though with two exceptions, a joint Italian-Russian project and a project in the United Kingdom), work in Europe was on planar technology using thin components which could have high performance per unit area. The objective was to reduce weight and cost, with the further advantage of allowing operation at lower temperatures with no substantial changes in the present family of materials. The challenge was to design flat cells which could be scaled in two dimensions, even though the properties of ceramics might restrict the cell size to a linear dimension of 0.1-0.2 m. An overview of European work on the SOFC up to 1993 is given in Ref. 437. European Commission Programs: In 1987, the Commission of the European Communities (CEC, now the European Commission, EC) started an exploratory SOFC R&D program using small teams from different countries, who would investigate new cell structures which could be manufactured by inexpensive techniques, such as tape-casting. Four structures were aimed at: two types of tape-cast multi-channel honeycombs, structurally related to the monolithic SOFC, and two planar systems with metal or conducting ceramic bipolar plates. Each was tested in units producing lo-20 W. Only the last two concepts were retained for further development after 1989. After other studies, the most probable early market was identified as industrial cogeneration in units of 200 kWe. The plan was to develop two 1 kW units of different technologies by 1993, a single 20 kW unit by 1995, and a 200 kW unit by 1997. The 1 kW units were to be developed by teams respectively consisting of; first, Siemens (Germany), Eniricerche (Italy), Imperial College and GEC Alsthom Engineering Research Center (U.K.) in the JOULE program; and second, British Gas, the Rise National Laboratory (Denmark), and TN0 (Netherlands) in the program known as BRITE/EURAM. The first project was to use a metallic bipolar plate, and was demonstrated at the 1 kW stack level at the end of 1993. The second intended a hybrid tubular-planar structure. When its objectives were not reached for technical reasons, work was continued to determine feasibility. A further project, with ceramic bipolar plates, was being conducted by Dormer (Germany) and Cookson (Warrington, U.K., a company specializing in silicates, zeolites and ceramics, then a Unilever subsidiary). These were developing a 1 kW stack with ceramic bipolar plates. Domier (now part of Daimler-Benz, A. G.) and Siemens had internal programs, partially supported by German Government funding. The total CEC program costs were initially about $18 million over three years, 50% of which was funded by the CEC, the remainder by private sources and/or national programs, e.g., in Germany (about $5 million per year), and in the Netherlands. In 1994, the ECN SOFC program had other European institutions as collaborators (Eniricherche; Siemens; GEC-Alsthom; Imperial College; Holec, Ridderkerk, Loughborough University; the University of Aveiro, Portugal; Rhone-Poulenc; TNO, NOVEM), and was working with the JOULE, BRITE/EURAM, and IEA programs. Materials (electrolyte components and cells up to 400 cm2) and testing were the major activities. Spending in this area was about $2.9 million in 1993, with about $0.6 million from the EC. The total current EC JOULE program under DirectorateGeneral XII (Science R&D) was 23 million ECUs over three years, without the contractors’ 50% contribution ($9.7 million per year at the ECU trading rate of $1.27 in November 1995). The three-year BRITE-EURAM manufacturing project (5 projects) and THERMIE fuel cell demonstrations (3 projects) were 7 million and 2 million ECUs respectively. The latter was a very small part of the total THERMIE program under Directorate-General XVII (Energy), whose budget was 250 million ECUs over 3 years. THERMIE was intended to demonstrate clean coal, rational energy use in buildings, and alternative fuels for urban transportation, with a mandate to improve the environment, increase competitiveness, and secure sources of energy.

Fuel cell technology

607

In 1~4, the Siemens program was about $7.5 million per year, of the German Government and EC JOULE Rogram contributions were $2.5 million. and $1.1 million respectively. The Dormer program was $4 million per year (20-25 people) in 1994, including a 30% contribution from the EC. The national program in Denmark ($7 million for 1990-1992) aimed to develop planar systems with conventional materials operating at up to 1.0 A/c&. Smaller activities were in Italy and in the U.K. In 1994-95, the EC was establishing a ten-year strategy for fuel cells. At least 1 billion ECUs, and

possibly up to 2 billion, was needed for fuel cell (MCFC, SOFC, and PEMFC) development and commercialization, of which the EC could supply 3% (possibly 10%). Future funding might be available out of the THERMIE allocation, as “THERMIE-bis.” Other Programs: Outside the European Union,, Switzerland ($1.3 million in public funds) was developing the Heat-Exchanger Integrated Stack (I-IEXISTM)at Sulzer Innotek with ceramic components from Ceramatic, Inc., Salt Lake City, UT. Its objective was a 1 kW stack in 1993. Norway had two projects in 1994. The first was at Statoil ($3 million per year), aiming for a planar 5-10 kW unit in 1995. The second involved the Norcell consortium, consisting of SI, Norsk Hydro, Elkem (the owner of Ceramatec, Inc.), Saga, and Sintef. This had a three-year, $7 million program (since abandoned, below) to develop a 3-4 kW unit in 1994. 437 Recent European work is reviewed here.

see

The Netherlands: Initial work by ECN, Petten (with the Universities of Delft and Twente) for the late 1980s national program,4s8 was aimed at reducing cell IR drop via the use of a planar tape-c:ast43g air electrode (Lat_,Sr,MnOg, x = 0.15,0.3,0.5) as the cell supporting element, with a thin electrochemical vapor deposition layer of YSZ electrolyte applied by the University of Twente.440 This method was examined because 50-l 50 pm tape-cast YSZ films were considered to be too resistive. Satisfactory EVD layers of YSZ 2.5 pm thick were made after supports were film-coated with YSZ powder to prevent deep penetration of the YSZ EVD layer into the pores. 440 ECN was developing other cell components, including anodes and stacks with metal bipolar plates for Siemens for the CEC JOULE program.43* In 1992, typical tape-cast component thicknesses were 130 pm (electrolyte), 25 pm (anode and cathode), and 3,000 pm Q-doped LaCrGg interconnect, when applicable). Sintered electrolytes up to 10 cm x 10 cm with electrodes up to 8 cm x 8 cm had been fabricated. Electrodes were co-fired on the sintered electrolyte in a simplified procedure441 compared that given in Ref. 439. Cells offered 0.67 V at 0.30 A/cm% and 80% fuel utilization, and used metal foils and glasses as seals. Metal bipolar plates were to be based on the internally-manifolded MCFC design.42 Further improvements in electrode particle size and optimized preparation and fabrication techniques (air-sintering at 1,lOO’C on 130 pm electrolytes) were reported recently which allowed larger structures (electrodes 20 cm x 20 cm, active areas 14 cm x 14 cm). The performance of a 5 cm x 5 cm cell with improved components showed 0.67 V at 0.50 AJcm2, at unspecified utilization on hydrogen-air.43 Manufacturing techniques had been developed for cells up to 20 cm x 20 cm, which were to be used in the Siemens “multiple-array” stack with metallic bipolar plates. In addition, circular components of 20 cm diameter were being produced for use in the Sulzer-Innotec HEXISTM stack, also with metal separator plates. Both of these are described below. Metal internally-manifolded separator plate designs have been developed in 15 cm2 and 100 cm2 sizes for use with internally-manifolded electrolytes. The plate (of unspecified composition) has an applied (or possibly free-standing) layer of proprietary conducting oxide to prevent degradation of the metal oxide layer on the cathode side. Degradation was known to involve evaporative loss of CrG3. Under ideal operating conditions (low utilization), the internal resistance of 10 cm x 10 cm cells with standard components was 0.3 Q-cm2 at 93O’C. A 4 cm2 cell showed 0.75 V at 0.2 A/cm2 and at 40% hydrogen utilization under these temperature conditions with little discernable degradation over 1,800 hours, although periods of degradation were followed by periods of 50 mV increase in performance. This improvement was in part related to thermal cycling. A 10 cm2 cell with a 60 pm partially stabilized zirconia electrolyte (PSZ, 3% Y, cf., Ref. 427) showed a 0.3 V loss in performance at

0.4 A/cm2 and low hydrogen and (pure) oxygen utilization (0.92-0.62 V) as a function of temperature (94073O’C). The performance of a 10 cm2 cell with a standard anode, a 115 pm 20 mole % Gd-doped CeO2 electrolyte, and a L~.6Sro.4Feo.gCoo.203 cathode showed about 0.5 V at the same current density and utilization at 715’C, but its open-circuit voltage was about 0.1 V less than theoretical.‘@4 Other Netherlands researchers have described their work on the alkaline earth cerates (SrCe03 and BaCeO3) and the corresponding zirconates (SrZrG3 and BaZtG3) as solid (proton-conducting) electrolytes in solid oxide fuel cells operating at intermediate temperatures. The problem is the possibility of reaction with C@ in the fuel gas stream to give the corresponding alkaline earth carbonates. They have determined

that SrCeO:, and BaCeOg react below 1,190°c and 1,185’C respectively at 1 atma CG2, whereas the corresponding zirconates only should react below 600°C and 550°C, respectively. Howeve.r, they are probably kinetically stable at higher temperaturesus

EW 21:7/8-a

608

A. J. Appleby

Germany, ABB (Heidelberg): The successor to Brown-Boveri after its merger with ASEA of Sweden, ABB, reported work on planar SOFC concepts in 1990, which were made in 4.4 cm x 4.4 cm size by tape-casting of the 220 pm electrolyte, which was completed by sintering and plasma-spraying of the 80 pm cathode and 50 pm anode made from standard compounds. Edge collection was used in laboratory experiments, and was proposed in individual arrays. About 0.3 W/cm2 was expected on hydrogen-air in cells with optimized current-collection at l,OOO°C. 446 Work on the SOFC (like that on the MCFC) was abandoned by ABB in 1991 as part of a business decision not to manufacture small generation equipment,

Germany, Siemens (Erlangen): Seimens has examined HTFCs since 1987. It considered that the complex gas management of the MCFC made it less attractive in 1- 10 MW sizes than the SOFC, where 5560% efficiencies could be expected in combined cycle systems with cogeneration capability. Work is supported by the Federal Ministry of Research and Technology (BMFT), Badenwerk AG, Daimler Benz AG, and the EC. GEC-Alsthom is a partner for seal developmentl~ Research on a “multiple-array” stack with the ECN-designed internally-manifolded bipolar plate and “metallic window foil” seals on either side was started in 1988 and described in 1990. The foils are in effect window-frames with a central cross, which seals the joint between four adjoining square electrode-electrolyte elements which are arranged in another frame with internal manifolding. Alloys which were considered suitable were FeNiCr, NiCrW, NiCrAl, and FeCrAl. The Al-containing alloys would require modified compositions to prevent the formation of resistive films.447 Impedance measurement work on electrode optimization has been described.44s In 1992, it was reported that suitable alloys with appropriate expansion coefficients had been identified. These included the cobalt-based Haynes 230 and the ODS &Alloy developed in-house. Each ‘window” of electrolyte and electrodes would be in manufacturable sizes from 10 cm x 10 cm to 20 cm x 20 cm. The metallic hardware was being developed with Metallwerk Plansee Gmbh, of Austria. Four and lo-cell stacks were then operating at 0.74 to 0.82 V at 0.20 A/cm2, presumably on hydrogen-air at an unspecified fuel utilization. The stack is shown as counter-flow.49 In 1993, the resistance of Haynes 230 was reported to be 250 ma-cm2, and that of ODS Cr-Alloy was 300-400 ma-cm2. In flat stacks of Siemens structure, current collection is a problem because of undulations of components substantially increases contact resistance. When thin coatings of air electrode material were applied of the cathode side, these resistance values fell to 50 m&cm2 and 100 ma-cm* respectively, allowing much better stack performance. GO The effect of Co as a replacement for 50% of the Mn in the cathode material was studied. A change in sinteting temperature from 1,300’C to 1,150‘C then caused a fall in overpotential from 0.25 V to 0.05 V at 0.10 A/cm2 and 95O’C operating temperature. This did not occur in Co-free cathodes.ar In 1994 work, single cells had attained >l A/cm2 at 0.7 V on hydrogen and oxygen. A 370 W stack produced 0.9 A/cm2 under the same conditions. A I kW stack attained a maximum power of 1.8 kW at 0.6 W/cm2 at an average operating temperature of 950°C. All results were a factor of two lower on air. The 1993 13-cell, 1 kW test stack had an initial performance of 0.8 V at 0.35 A/cm2 on hydrogen and air at 23% and 50% fuel and oxidant utilizations. It had 5 cm x 5 cm sub-cells (arranged 4 x 4) in each bipolar plate. It was operated for 300 hours, when performance had fallen by a factor of two. This was attributed to the effect of chromium oxide evaporation from the oxide film on the bipolar plate. A “functional layer” of CrFegY203 material was applied by wet powder spraying to improve contact resistance. A reduction of average operating temperature by 1OO’Creduced the power density by approximately 3O%.l= The standard 150 pm 8% YSZ electrolyte was calendered, sintered for one hour at 1,5OO”C,and “ironed” under pressure at 1,450’C for flattening. Some samples were rejected because of a yellow coloration, perhaps due to molybdenum from the furnace heating elements. Thin anodes (YSZ-60% NiO) and cathodes were then applied by silk-screening after calendering a mix of each component. They were cosintered at 1,350’C. A LaCoO3 layer was then applied to the air electrode. Seals were A15Z25 (Si@/Alfl@aO) for the compliant phase, and MgA1203 for the rigid phase. Cell degradation rates were 100 mV per 1,000 hours at 950°C, with a goal of 1% per 1,000 hours.‘22 Because 5 cm x 5 cm electrolytes are easily handled, and allowed flexibility of gas flow, the 4 x 4 subcell arrangement in the “window” was preferred. The fuel side could be operated in a long-pathway cross- to counter- to cross-flow arrangement, to facilitate heat-transfer for better temperature distribution and/or internal reforming, and to increase fuel utilization (c.f., Ceramatec, and the National Chemical Laboratory for Industry, Tsukuba, Japan). The aim was to obtain good performance at an average temperature of 850°C, because cathode recycle is needed for high system efficiency, but it results in a 2OO’C temperature gradient across the stack. Siemens’plans in 1995 were to operate a 20 kW stack during the first half of 1996. A 100 kW system was anticipated for 1998. It was use six 20 kW stacks (400 cm2 per cell, with sixteen 5 cm x 5 cm subcells, arranged cross- counter- cross-flow) arranged in a circle with a center air exit manifold (c.f., Ceramatec).lz2 A system design offering 67.7% efficiency at 16 bars pressure had been studied. It would use hydrogen recycle and separation, in a scheme to be developed in collaboration with Linde. The stack must cost less than DM 5OO/kW,in a system costing less DM 1,500-2,OC@kW(about $1,080-

Fuel cell technology

Reportedly, 1995).‘22 costly 50 kW unit by early 1999.

$1,44O/kW,

609

plans were scaled back in late 1995, and the next goal Was a less

Germany, Dornier: R&D activity was supported by BMFI and the EC at Freidrichshafen, whereas systems studies were conducted at Ulm. The company’s planar cells consisted of flat electrolytes supporting the flat anode and cathode. The ceramic bipolar plate (interconnect) elements are ribbed, which poses a number of problems of current distribution, e.g., where oxygen cannot penetrate into the contact zone. If 1 mm (1,000 pm) ribs were used, the air electrode must be at least 225 pm thick to avoid diffusion problems in the contact zone. The ribs were produced by lamination of green tapes, i.e., by cutting strips, which were applied to the flat interconnect web and sintered. Electrodes and electrolytes were prepared by a combination of tape-casting and screen printing, with successive sintering. The resistance of 5 cm x 5 cm cells were tested on a routine basis was typically 1.0 0 cmz, and their performance was 0.6 V at 0.30 A/cm2 under representative utilization conditions .452 The cross-flow &sign required a fine-tuning of materials and component flatness. Scale-up to 10 cm x 10 cm took place in 1992. At a hydrogen utilization of slightly more than 50%. 0.6 V was obtained at 0.35 A/cm 2. A 5-cell stack had performed satisfactorily over 3.000 hours with a degradation of less than 20 mV per 1,000 hours. System work had been conducted which indicated an LHV efficiency on NG of 52% with no bottoming cycle in small systems (under 1 MW), 70% in a 10 MW system incorporating a 1.6atma gas turbine cycle, and 74% in a lOO+MW system incorporating a gas turbine with a steam bottoming cycle.G3 No details were available concerning sealing in 1992, but “soft glass seals” to take up slight thermal expansion differences between components after stacking at room temperature are mentioned in another 1992 report.454 The electrolyte was produced by tape-casting and was sintered at 1,600°C to give 98% of theoretical density. A Weibull failure analysis of stressed components had been performed, which gave satisfactory results.4s4 External box manifolds were described, consisting of YSZ end-plates at the top and bottom of the stack, cemented via glass seals to a three-sided YSZ box-shaped structure extending through the height and width of the stack. The edges of the unit were attached to the stack via glass seals. Metal conduit piping was attached to the manifold endplates (which overlapped over the top and bottom of the stack) via metal-glass seals. YSZ gives a perfect thermal match to stack components, but the less expensive calcia-stabilized material was being examined. The glasses were silica-based, with a glass transition temperature below the operating temperature of the stack.4S5 The first 10 cm x 10 cm stack test was conducted in 1993. and gas-tight stacks with up to 20 cells were operated. These included a 1 kW system with twelve lo-cell stacks, which operated at an average of 0.7 V at 0.15 A/cm2 at 50% hydrogen utilization (33 : 67 Hfl20 exit concentration) at an unspecified air flow. The stacking and manifolding arrangement has been illustrated. One 25 cm2 planar cell had operated at l,OQO°Con hydrogen/air for almost 17,000 hours at 0.26 A/cm2, initially at 0.7 V, falling to about 0.65 V at 3,000 hours (17 mV per 1,000 hours. After a discontinuity between 3,000 and 4,500 hours, its performance was 0.6 V, which fell to 0.57 V at 18,000 hours (about 2.2 mV per 1,000 hour:s).*s6~*s7A second cell showed similar long-term decay (between 6,000 to 17,000 hours), but it decayed mom rapidly initially, and settled out at 0.51 V at 6,000 hours. Post-test analysis of both cells showed an increase in grain size, and some interdiffusion of Zr and La, but no La2Zr207 formation, as had been reported by others, at least at temperatures approaching 1,400’C. The Weibull modulus of ceramic components with improved strength has also been examined.457 The interconnect was 1.2 mm thick, with a 250 pm thick electrolyte (supplied by Bosch) ;and 150 pm electrodes. The Bosch electrolyte, with 9 wt % Y2O3, 4 wt % Al2O3, had been tested to 25;,000 hours. The anodes (as prepared) were mixed NiO/Cem, to give a mixed conductor. The cathodes were 50% Ca-La MnO3, an old Dornier development. The electrodes were screen-printed onto the electrolyte, and fired at about 1,250°C.r~**s7 Domier considered that the thickness of the electrolyte could not be reduced to below 100 pm, since this would result in interdiffusion problems. The doped LaCr03 for the interconnect was prepared by flame-spraying an aqueous salt (chloride or nitrate) mixture, followed by milling to break up agglomerates and calcining at l,lOO°C. After tape-casting, cutting, laminating, and applying the flow channels using glue, it was air-sintered to 98% density at 1,600°C. Its composition was such that no liquid-phase sintering occurred. It was said to be a compromise between thermal expansion and conductivity considerations (10 and 1.0 S cm-t under oxidizing and reducing conditions, respectively). For example, a high-Co material would have a high conductivity, but also high thermal expansion coefficient. The flame-spray reactor could produce 1 kg (0.5 kW) per hour. The processing costs were estimated at $lO-2O/Icg.The calcining furnace was capable of treating 50 kg per day. Thickness deviation on components did not exceed 100-150 pm. The electrode yield was 75%, and that on the interconnect was 80-85% overall, and 95% based on thickness alone. In pilot production, overall yields increased.1~ 50-cell stacks (5 cm x 5 cm, 100 W, 0.08 W/cmz) had been tested for up to 1,200 hours (without a thermal cycle). These had single YSZ manifolds. For 10 cm x 10 cm stacks the upper limit .for manifold height was 40 cells in 1994. Single manifold heights corresponding to perhaps 50, or even 100 cells might be eventually obtainable. A IO-cell, 100 cm2 stack had shown stable operation for 1,000 hours. In 1994, one thermal cycle has been attained by oxidizing the nickel cermet anode back to the original form before

610

A. J. Appleby

cooling to relieve stress. Further scale-up to 20 cm x 20 cm was considered difficult, because of gassealing problems with glass. While single cells showed satisfactory &cay rates, &cay in stacks was still a problem in 1994. The best stack performance obtained with 2 : 1 H2/I-I20 fuel was then 0.7 V at 0.2 A/cm2 (at 50% utilization) and 0.6 V at 0.3 A/cm2 (at 75% utilization), in a constant-flow system with 6 times stoichiometric, airflow for cooling.*2j As at Ceramatec and other developers, a large temperature gradient existed from the entry to the exit of the stack, whereas small cells were isothermal. A stack with the superalloy Haynes 214 for the current take-off has been recently described, with chromium containing 1% Y2G3 (CrlY chromium-yttrium alloy) as the current collector plate (i.e., the stack endplate). The Haynes alloy was spot-welded to the CrlY plate.458 Germany, Other: Apart from that on SOFC stacks and systems, other work in Germany has been on materials development, for example on the crystalline suucture and bulk properties of LaJ,SrxCoG3,4s9 including ‘varieties made by wet powder spraying,46e*ar some electrochemical studies on these materials.461 on fabricating precursor materials by the nitrate pyrolysis process,462 and on modeling studies of the planar SOFC.‘t6s Switzerland, Sulzer-Iruwtec: This company is a subsidiary of Sulzer Brothers Limited, Winterthur. It has described the geometry of the HEXISTM stack, which is intended for small cogeneration systems.464*465 Research is supported by the Swiss Federal Office of Energy and the Swiss National Energy Research Fund. Studies were initiated in 1988, and the stack design dates from 1991. The repeat element in the stack is circular, and it combined the functions of bipolar plate and air preheater. The unit consists of a circular, flat metal sheet, dished in the center, with a central hole. A ceramic “hub,”itself with a central hole, grips the central hole in the metal plate. The ceramic hub serves as the fuel manifold, and it contains radial holes to allow fuel to flow from the center to the upper surface of the metal plate. Cold air enters peripherally on the outer lower side of the metal plate, and moves radially towards the middle. The bottom part of the hub fits tightly into another circular plate, which is pierced with holes close to the hub, so that the heat-exchanged air can flow radially outwards on its lower side through appropriate channels. The system is completed by the electrochemical cell components (from the top, cathode, electrolyte, and anode) in the form of a circular disk fitted to the bottom of the lowest part of the hub. The ceramic parts are technology from Ceramatec, Inc. As described above, the disks in the bipolar plate are independent, and the gap across the bipolar structure must be bridged by vertical, electronically conducting current collector elements, which must be flexible and bonded to the lower plate. The lower plate could be ceramic (lanthanum manganite cathode materia14a) or metal, and at least the flat metal heat exchange sheet is designed to expand freely. This would not be true of a metal lower plate in contact with the electrochemical elements. The system is thus radial counter-flow from the viewpoint of air heat exchange, and outward radial c&low as an electrochemical reactor. The heat-exchanger prevents temperature differences across the reaction zone from exceeding 50°C, compared with 200°C in a conventional cross-flow planar non-heatexchange arrangement. The preliminary performance was 0.6 V at 0.25 A/cm2 of hydrogen at 60% utilization with 10 stoichs of air,464in a 2.5 cm2 cell.465 As described,464the system requires metal-to-ceramic bonding of current collectors. Alloys examined included NiCrW, NiCr, CoCrNi, and FeCr. At 0.015 kg&m2 pressure, contact resistances for metalceramic-metal sandwiches air at l,OOO°Cafter 200 hours were reduced by the use of oxide coating (c.f., Siemens). NiCr and NiCrW were reduced from 350 and 80 mf2-cm2 to ca. 10 mQ-cm2. CoCrNi was reduced to ca. 5 mQ-cm2, whereas FeCr was reduced from very high values to 150 mQ-cm2. Short stacks with diameters of 7 to 20 cm were planned in early 1992,M4with a 5-cell 12 cm diameter testMs Only data at low utilizations had been given to date in a 2-cell7 cm diameter stack with an active atea of 31.4 cm2. The 1993 goal was 0.5 V at 0.20 A/cmZ, with a thermally self-sustaining 1 kW stack. Switzerland, Other: Other Swiss work has included the development of plasma spraying,& the use of m-doped In203 as a mixed-conducting cathode material, 47 and the effect of surface roughness on cathode reaction rate.- The analysis of the performance of SOFCs with different geometries given by Bossel (formally of ABB) has already been discussed. 382 He has recently &scribed a new SOFC design (the “UBOCELL”), of unique construction. It has hollow separator plates which incorporate a fuel manifold communicating with one side of a flat interior sheet-metal component containing reforming catalyst. Reformed fuel exits through a series of holes on the opposite side, which contains channels and serves as the anode-side bipolar current collector. The cathode-side current collector is also sheet-metal, and is peripherally sealed around the edges of the reforming container. A conventional flat anode-electrolytecathode unit completes the system. Air is supplied in cross-flow to the cathode side. All sealing is associated with the fuel gas circulation, and is built into the welded- or crimped-edge bipolar separator/reformer/current-collector plate.469 Denmark: The national Danish SOFC program (DK-SOFC), which runs in parallel to the activity funded jointly by the EC, started in 1990. The project is managed by the Rissi National Laboratory and

Fuel

cell technology

611

includes Innovision A/S, Gdense University Institute of Chemistry, institutes at the Technical University of Denmark at Lyngby, and Haldor Tops@ A/S (Lyngby). The Y SZ electrolyte powder was ptepared by tapecasting and was sintered at 1,3ooOC. The cathode material was being made in 10 kg batches, and it and the anode mixtute were spray-painted onto it and sintered at 13OO’C.The interconnect plates wete also sintered at 1.300°C, in air. A number of batches of 4.5 cm x 4.5 cm cells had been made, which had a typical resistance of 250 mQ cm2. Four-probe test results (not representative of real data with total IR) showed about 0.65 V at more than 1 A/cm2 at high fuel utilization. This seems to indicate that good performance should be obtained in real cells. Stacking studies were under way in 1992.“O Other work at Risa has been on the optimization of tape-casting of YSZ electrolytes and Ni-YSZ cermet precursors. Considerable details concerning the dispersing agents, binders and plasticizers has been given. Tosoh TZ8Y YSZ Powder (8 mole % yttria, 18 m2/g) was used.471 Work has included promising results on the diit oxidation of methane on a catalytic (gadolinium-doped) cerium oxide anode (c.f., Ref. 5), instead of Ni-Y SZ cermet, which is poisoned by carbon deposition, since nickel is a cracking catalyst.472 A joint project between Rise and the Center for Materials Research at the University of Oslo, Norway, was examining Ti-doped neodymium chromite as an alternative anode material for methane oxidation.473 Hydrogen oxidation kinetics on Ni-YSZ cermets have been measured.474 and an analysis of fuel cell performance by ac and dc electrochemical techniques has been conducted.475 The oxygen stoichiomeuy in gadolinia-doped ceria.4’6 and the synthesis and stability of lanthanum calcium chromites substituted with Co (0.05),477 and CoNiFe (0.05,0.05,0.05) 478 have been studied. In contrast to the Co-substituted chromite, which shows phase changes giving limited stability under reducing conditions, the latter may be a promising ceramic interconnect material. Updates on the program are available.4rs@e During 1990-1992, the total DK-SOFC budget was 43.5 million DKr (then about $7 million), which was shared by the Government program for energy promotion, the utilities ELSAM and ELKRAFT. and the six participants. The program resulted in a chosen design similar to that of Domier, with standard electrochemical components, but with an LCC bipolar interconnect plate to allow a lower sintering temperature than that of LX. The standard cell size was 4.5 cm x 4.5 cm x 160 mm, but cells up to 8 cm x 8 cm had been constructed. Construction methods remained those described in Ref. 470. Cells had a resistance of 0.25-0.4 Q-cm2. Their electrochemical characterization was conducted bv standard techniques, e.g.. ac impedance. The performance on dilute (9%) hydrogen at low utilization indicated a total polarization of about 25 mV at the cell center at 0.2 A/cm2, and about 100 mV at the cell edge. A threecell stack had been operated for 408 hours. The use of ceria-based anodes to oxidize hydroc,arbonss*472 was contemplated, provided that their sintering temperatures could be reduced from 1,600°C to I ,300”C.479 The 1993-96 DK-SOFC budget was about 90 million DKr ($16 million, 1995). In addition (in million DICr), 13, 2, 15, 10, and 2 were available for modeling (1992-95), for metal bipolar plate development (1994), for JOULE II materials and technology (1993-95), for JOULE II composite plate technology (199394), and for the Statoil-Rise program. The JOULE II efforts involved many international partners. The objective of the materials and technology program was the development of a system offering 0.5 Q-cm2 at 850°C and 2.0 G-cm2 at 600°C. The latter would be used for oxidizing NG to useful chemical products. The composite plate effort was intended to develop the stack described in Ref. 481 (see under U.K., below). The objective of the Statoil program was an improved cathode with a resistance lower than 0.12 Rcm2 in air at 1,000°C.480 Norway: The Norcell and Statoil teams had both planned to construct a 20 kW unit by 1995, and a 200 kW unit in 1997.4s7 The Norcell team was to use Ceramatec components. However, in June 1994, the Norcell program was abandoned when Babcock and Wilcox in the United States received a technology license (see above). Achievements of the Statoil (Trondheim) program were given in 1994. A 14-cell stack (37 cm2 active area) gave 0.71 V at 0.2 A/cm2 at 995’C at 55% hydrogen utilization. A 350 W laboratory stack (seven of the above stacks in a common furnace) was constructed and tested together in December 1992. Stacks had been tested for up to 650 hours. A 10 kW stack, which would use Rise’s improved cathode (see above) was to be tested in a gas terminal by the end of 1995. A total resistance of less than 0.5 G-cm2 was anticipated.‘@2 In academic work, the influence of the dimensions of the three-phase boundary on the polarization resistance was studied by impedance spectroscopy. 483 Modeling of the effect of in-plane reactant diffusion in planar SOFCs was being conducted (c.f. Domier),4” as was the effect of flow distribution on temperature gradients,485 and internal reforming in cross-flow planar stacks4a6 Studies on Fe-doped calcium titanate were being conducted using the ac Van der Pauw method.&7 A joint project between the Urals Gorky State University, Ekaterinburg, Russia, and the University of Oslo was studying the crystal structure and electrical properties of lanthanum strontium cobaltate.* Sweden: While Sweden has opted for the MCFC as a national goal, some work was being conducted on solid electrolytes. Interesting results were being obtained on proton-conducting ceramics, based on lithium sulfate, potassium phosphate and rubidium nitrate (? nitrite after heat-treatment) in mixtures with hydrous alumina sintered at 800°-900°C.‘ta9

A. J. Appleby

612

United Kingdom: Work at Imperial College, London, concerns new materials developments. Examples are stabilized zimonia which is doped with ceria (0.02), as well as ytuia (0.03) and magnesia (0.1). lanthanum chromite which is air-sinterable at 15OO“C,4~and nickel-substituted (0.1) lanthanum calcium chromite.491 Like the Co substituted material ,4n this undergoes changes (involving regeneration of liquids) in reducing atmospheres at l,OOO”C,perhaps due to the presence of residual calcium oxychromites.491 Novel oxides for the direct oxidation of methane have been reported.492 These have WWo.o~Ti1.9~0s SwTi1.Wo.107. CrTizOs and included n-type Tio.wNb.oso21 Wo.3Nb.1Th&, p-type Smz03 and La&a&rG3. The latter showed rather low conductivity, and would require a metal matrix. The also showed carbon deposition on active sites. The n-type materials showed good conversion above 800°C.4m At the Third Grove Symposium, Steele presented an overview of oxide-ion conducting ceramics, including many new materials, especially those intended for use at intermediate temperatures.493 Work at ICI, Runcom has included improved ceramic structures with agglomerates broken down by high shear forces,4w which show vastly improved Weibull bend strength statistics.495 Work has included a cell &sign consisting of a “composite ceramic foil,” which uses flat repeat elements with edge-collection, in a flat version of the original tubular bell and spigot system. 495 Resistance limitations will limit the length of the number of cells connected in series. This work has been continued at the University of Keele.481 Italy: Eniricherche (San Donato Milanese) has examined the influence of the preparative techniques and physical properties of the YSZ-Ni anode cermet on methane steam-reforming,496 together with the physicochemistry of reduction of YSZ-NiO using temperature-programmed reduction,497and has modeled the effects of fuel and geometry on performance. 498 The effects of reactant flow geometry on current density and temperature distribution for a monolithic planar SOFC have also been modeled at the University of Genoa.499 Like Norway, Italy has a joint project with a Russian Institute, the Institute of Electrochemistry at the Urals Academy of Science, Ekaterinburg. A 150 W stack of 16 tubular monocells, each 21 cm long with 63 cm2 active area, had been assembled in CNR-TAE, Messina. Each cell (fabricated in Ekaterinburg) consisted of a closed tube of yttria-scandia stabilized zirconia (0.12, 0.08 respectively), which served as both electrolyte and support. The anode is on the outside, and the cathode inside, applied by slurry painting. Both consisted of “oxide-supported metals.” The power density was 0.15 W/cm2, and the power density of the electrochemical part of the system was 75 W/kg. No details of interconnections are given. The system has been shown to be suitable for intemal-reforming.5as France: Work in E.N.S.E.E.G.-I.N.P.G., Grenoble, France has included a study of the oxygen reduction reaction on La&ro.5Mn03 by impedance spectroscopy. The work concludes that reduction takes place at the three-phase boundary at low current density and is progressively transferred to the whole exposed surface of the mixed-conduction electrode as current density increases.sO’ The preparation and properties of new compounds in.the system Z~O~-Y~O~-RUO~ have also been studied.5” Iberia: h $X3in, dense tW0 nanOCOmp0Site.S COrkSting Of i?k&-Y$&&03 have been pupated and characterized.503 In a joint project with Portugal, Ti-doped YSZ has been evaluated as an anode material.5a4 Work at the same Portuguese institute is studying a range of ceramic anode materials, including those based of ceria and other rare earth oxides.as

Greece: In Greece, studies have been performed on steam reforming kinetics on Ni-YSZ cermet,sM and on the use of SOFC reactors with modified metal-ceramic interfacial properties for chemical catalytic processes.so7 Work F-here

(O&r

‘III-

Australia: An overview of recent work and plans in Australia has been given.sss While an SOFC program existed in the 1960s at the Aeronautical Research Laboratory, Melbourne, with another R&D program at Broken Hill Proprietary (BHP) in the 1970s. these were abandoned. A consortium was established in July 1992 to fund an SOFC program based on the zirconia expertise acquired as the Commonwealth Scientific and Industrial Organization (CSIRO). The consortium consists of Pacific Power, BHP, CSIRO, the Strategic Research Foundation (SRF), the Energy Research and Development Corporation (ERDC), and the State Energy Commission of Victoria. Negotiations with other possible gas and electric utility members were in progress. The consortium established a company, Ceramic Fuel Cells Ltd., to manage a $31 million (Aus), J-year program, whose progress was to be reviewed in three years.sos

New Zealand: The properties of the Lal_xSrxMnl_yCry03 (LSMCr) system as an alternative cathode have been examined at the University of Waikato, Hamilton. so9 Plans included the construction of a 100 W stack in 1996.

Fuel cell technology

613

CAM&: Pmparation and characterization of LX prepared by the glycinanitrate processsra and the properties of strontium-doped bismuth oxide (Bi203)o.8([email protected] as an intermediate temperature electrolytesr* have been studied. India: The use of bismuth oxide as an effective sintering aid for LSM cathode material has been examined.512

Overview: As in the MCFC area, SOFC activity in Japan has now become very extensive. With one exception (one project at Mitsubishi Heavy Industries, Ltd., MI-II,using traditional tubular cells), Japanese work is either on tubes of Westinghouse type (five developers), or on planar designs (thirteen developers). At least four Japanese developers are studying metal bipolar plates, two (like Siemens in Germany) exclusively. At least two Japanese developers are working on similar stack constructional concepts to those at Siemens. A useful review of activity up to late 1992 has been given by Tagawa.sr3 This was further updated by a worldwide overview presented by Hashimoto at the Thii Grove Symposium.514 The SOFC R&D effort by Japanese developers dates only from 1989, following research on tubular cells in the Electrotechnical Laboratory (Tsukuba, Ibaraki) starting in the 197Os, and on planar systems at the National Chemical Laboratory for Industry (Osaka), from 1986. NED0 started a three-year R&D program in 1989. The budget (million u) was 72 in 1989; 124 in 1990, and 261 in 1991. The objective was the development of planar systems using co-firing technology and plasma-spray methods, with ceramic and metal bipolar plates, developing seals, and analyzing SOFC systems. The target performance of early single cells was 0.21 W/cm2 (0.30 A/cm2 at 0.7 V), whereas the final stack power output was to be 0.50 W/cmz. A sixyear development program was initiated in FY1992 (April 1992) by NEDO, with a budget of Y274 million. The objectives were the development of: A - Stacks - (i) planar 1-3 kW modules with an initial performance of 0.18 W/cmz, at unspecified voltage, and at 70% fuel utilization by 1995; (ii) lo-30 kW modules operating on steam-reformed NG at 0.20 W/cm2 and 70% fuel utilization with less than 1% per 1,000 hours performance decay by 1997; B - Components - (i) manufacturing technology for high performance, durable cathodes and internal steamreforming anodes; (ii) co-fling technology and gas seals; C - Systems - (i) engineering studies on multi-MW systems using NG and coal gas; (ii) issues necessary for commercialization; (iii) balance-of-plant, including 1,ooo”C valves, heat-exchangers, and blowers. Three consortia, representing ten companies, were formed. Group I, consisting of Fuji Electric Corporation R&D Ltd. and Sanyo Electric Company, was for the development of planar modules. Group II (Mitsui Shipbuilding Company, the Japan Fine Ceramics Center, Fujikura Corporation, Mitsubishi Heavy Industries Company, and Murata Manufacturing Company) was to develop materials and fabrication techniques. Finally, Group III (CRIEPI, the Electric Power Development Company, with Mitsubishi Heavy Indusnies, and the Metal Materials Research Center) would develop systems engineering. A further five-year project with Idemitsu Kosan Company, Nippon Oil Company, and Tonen Corporation as partners was initiated by the Petroleum Energy Center to use light petroleum fuel:s (naphtha and kerosene) in high-power-density fuel cells, eventually using internal reforming.sts Several consortia of gas and electric companies have been formed with both Japanese SOFC developers and with Westinghouse Electric Corporation. These and other research activities are reviewed below, starting with gas utility and electric utility consortia, followed by individual developers in alphabetical order and supporting work. Tests of Westinghouse Technology: In 1990, the Osaka Gas and Tokyo Gas Companies indicated that system simplicity, 50% electrical efficiency, and the availability of relatively high pressure steam (over 10 kg/cm2 gauge, 11 atma) were the major design requirements for a cogeneration system. The 25 kW (nominal) Westinghouse unit was specified to provide 30 kW of ac electrical power, and would consist of two modules fed with reactants (NG and preheated air) in parallel. Each module contained 576 50 cm cells arranged in 3 parallel strings of 192 cells. A module would be attached to a prereformer, which was to be heated by the exhaust gas burner. The exhaust from the prereformers would be passed successively through a high-temperature air preheater, a steam generator, and a low temperature air preheater. The expected electrical efficiency (LHV) between 25 kW and 30 kW (ac) would be 40%, falling to 36% at 35 kW ac. Heat recovery would be 13% at 25 kW (ac), rising to 20% at 30 kW (ac), and 38% at 40 kW (ac), i.e., total LHV efficiencies of 53%, 60%. and 74% respectively .srs The dc output of the module indicated 58% LHV efficiency at 20 kW net ac output, 52% at 30 kW, and 41% at 35 kW. A sensitivity study showed that by reducing parasitic power and heat losses, net ac LHV efficiencies of 50% could he obtained in 30 kW (nominal) systems, rising to 52% in 100 kW (nominal) systems.srs The cogeneration unit was to be delivered to the Osaka test site in early 1992, and was then expected to &liver 33 kW ac (maximum), and deliver steam at 8 kg/cm2 gauge (9 atma). The performance of the tubes on reformate at 85% utilixation was 0.52 V at 0.40 A/cm2 (about 0.56 V on hydrogen), about mid-way between the performance curves for September 1988 and March 1991 in Figure 5. Even so, this was

614

A. J. Appleby

considerably better than that of the previous 3 kW unit, which delivered 0.30 A/cm2 at 0.5 V, about equivalent to the curve for 1986 technology in Figure 5.516 However, Westinghouse announced that starting in 1993, the tubes used would be of air-electrode supported (AES) type,“14 which should be capable off about 0.65 V at 0.40 A/cm2 on reformate (Figure 5). A larger advanced system would not only have higher power density, but also much smaller parasitic losses, and would be capable of an ac efftciency of 50% &I-IV). Testing of Module A of the first, non-cogeneration unit in Pittsburgh started on November 29, 1991, and that of Module B on December 19,199 1. Each module contained four prerefomrers. The dc generator of the module consisted of 576 cells of 50 cm active length. Each module weighed 3,720 kg, of which the electrochemical tubes represented about 2.5%. Product water was used to raise steam for reforming in the sensible-heat reforming unit (the prereformer), so that no external water supply was required. The control system allowed completely automatic operation at a preset power level. The system had a footprint of 5.8 m2.517 Its specific weight and footprint were therefore 206 kg/kW and 0.16 m@W. The corresponding figures for the IFC PC25C am 91 kg/kW and 0.08 mz/kW, but a direct comparison is unfair, since early IFC 40 kW PClSs had a footprint of about 0.2 mz/kW. The system was air-freighted to the UTILITIES site (the Kansai Electric Power Rokko Test Center for Advanced Energy Systems, near Kobe) after this test. It should be noted that seismic sensors incorporated in Westinghouse units were triggered during transit to operational sites, but the modules survived undamaged.asc Installation and system checks took only three weeks, and were completed in the last week of February, 1992. The fuel was desulfurized NG, delivered at 20 cm of water pressure, and then was compressed to 3 atma to permit recirculation of anode exit gas to the prcrefomier.sis Each module of the 25 kW system could be operated independently. 514 Instead of supplying an inverter connected to the grid, the dc output was chopped and sent to dissipative resistors. The unit was designed to operate unattended, e.g., at night, on weekends, and on holidays. Module and system status could be monitored using a personal computer. Start-up required 8 hours from cold. The fuel flow was purged with nitrogen, and the modules were heated. After 3.5 hours, the generator center temperature had reached 500°C, and hydrogen flow was started. Measurable current started at 6OO’C after 4.5 hours. After 6.5 hours, the core temperature reached 850°C. and during the next hour, NG was gradually substituted for hydrogen. Full power was achieved at a core temperature of 1,OOO’Cafter 8 hours. At the end of February 1992, a stable output of 36 kW dc was registered at 85% fuel utilization.*is An endurance test was started on Module B on April 29,1992, and on Module A on July 12,1992. By the end of June, 1993, Module A had operated for 2,595 hours at an average load of 16.8 kW (dc). It had received 4 start-up/cool-down cycles and 9 partial thermal cycles. Major problems encountered were air heater burn-out and a low string voltage.s14 The second unit, intended for cogeneration, and equipped to deliver ac power, was tested without the inverter in a continuous run of 332 hours at Westinghouse in July 1992. It was then shut down to correct certain problems, and was restarted and operated continuously for 357 hours. It was then air-freighted to the Osaka Gas Iwasaki Test Center in Osaka City, and installed at the end of September, 1992. The verification test started on October 21, 1992, and it had operated for 817 hours with 4 start-up/cool-down cycles and 8 partial thermal cycles by early in 1993.5r4*5r9At the thermal balance point, where no extra fuel is required by reforming or preheating, the output was 25 kW, with 33 kW maximum power output, at which 27 kW was available as 9 atma steam. The respective dc and ac LHV efficiencies were 53% and 35% at 25 kW, and 41% and 30% at 33 kW. Fuel utilization was 85%, and the air flow was 6.3 stoichs. determined by the cooling requirement. 519 The average ac electrical power output during the 817 hour test period was 30.6 kWA. The major problems encountered were module flow imbalance, and a hot spot in Module A, with a low string voltage. The air flow balance to the two modules was adjusted, and some cells showed leaks. In the summer of 1993, studies were being conducted on how to repair defects in the modules.sl4 Module A of the Rokko Island non-cogeneration unit operated for a total of 2,601 hours at an average output of 16.6 kW (dc). It was shut down in the summer of 1993 due to current stability problems in the power dissipating resistance. It had experienced a total of 4 thermal cycles to ambient temperature and 9 partial cycles to about 85O’C. Module B operated for 1,579 hours, and was shut down during maximum output testing at 20 kW (dc). It had achieved its design dc efficiency of 45% (HHV), 49.5% (LHV), and had undergone 2 thermal cycles to ambient temperature and 3 partial cycles. After shut-down, it was apparent that some cells in both modules were damaged. In the case of Module B, this was because of excessive fuel utilization (>91%) during peak power testing. Both modules were returned to Pittsburgh for inspection. Module B was rebuilt with new cells as B2, and start-up at Rokko Island was on March 31, 1993. It operated for 1,862 hours at an average load of 17 kW (dc) by the end of June, 1993, with one start-up/cool-down cycle and one partial thermal cycle. A major problem then encountered was an air blower bearing failure, resulting from an over-tight drive belt.si4bi7 It was restarted on August 5, 1993, and operated continuously until November 10, 1993, where it was given a licensing inspection for MIT1 certification. It operated for 7,000 hours until March 7, 1994, with some degradation of a number of cells, which reduced its maximum power output from 17.9 kW (dc) to 12.4 kW (dc). Final testing occurred on March 9 and 10, 1994, to determine its maximum power (14.8 kW at 172 A at l,OSO’C). Inspection determined that 20% of the tubes had cracked near the open end during the June 1993 air blower shutdown. Cracking was because LSM air electrode material had reacted with hydrogen and expanded. The ability of

Fuelcell technology

615

the module to continue operation for 5,000 hours after this damage was considered a testimony to the robustness of the tubular Westinghouse technology.517 Osaka Gas (Research Center, Shimogyo-ku, Kyoto): Independent studies at Osaka Gas carried out during 1990-91 involved the in-house development of tubular cells similar to those of Westinghouse, although the interconnector was not yet then installed in single-cell tests. The support tube was LSM cathode material, carrying a thin YSZ electrolyte layer produced by EVD. The anode was a highperformance ruthenium-YSZ cermet, produced by slurry-coating and EVD (as at Westinghouse). Cells were intended for use in a system in which the cathode gas is oxygen-enriched air, and the anode gas is essentially hydrogen (i.e., reformate with water and Ca, removed), with anode recycle. The performance (at constant flow) was about 3.0 A/cm2 at 0.515 V, which is about 5 times the current density at the same voltage as that shown for the Westinghouse AES cell in Figure 5.520 More details about the cell were available later in 1992, which showed that the electrolyte layer was 15 pm thick.sztssU A new method of making a strontium-doped lanthanum chromite interconnect was described. While a thin, dense, pinhole-free magnesium-doped interconnect can be reliably made by the Westinghouse EVD method, this cannot be used for a strontium-doped film with higher conductivity because of the lower vapor pressure of &Cl> Even so, it requires a high deposition temperature and a complex masking process. A sufficiently high density is difficult to achieve by plasma-spraying (see, e.g., the Fuji Electric Company). High-quality plasma-sprayed deposits require the use of A-site excess La(Sr)Cr@, which has questionable stability, and results in products whose composition tends to be variable. The new method used laser ablation with a KrF laser (248 nm, 0.9 J/pulse at 150 Hz). The shadowmasked substrate is the LSM cathode, which was maintained at 700°C. The target was dense sintered La,Srt_xCrO3, with O
616

A. J. Appleby

70% fuel and air utilization. About 1 kW could be obtained at 75% fuel utilization. At 20% and 10% hydrogen and air utilization at 0.3 A/cm* at l,OOO°C,a performance degradation from about 0.7 V to 0.6 V unit cell voltage was observed over almost 5,000 hours, corresponding to 29 mV (4%) per 1,000 hours.s3t) Other work included the examination of ionic leakage currents in I.&Q-based interconnect materials,~r and an examination of electrical and thermal conduction in NCYSZ cennetssaz Saibu Gas (Research and Development Institute, Higarhi-ku, Fukuokia): The Saibu Gas Company has collaborated with the Department of Materials Science and Technology at Kyushu University on the development of tubular stacks using a wet-processing technique involving slurry-coating of YSZ onto either green, partially sintered, or fully sintered LSM (Sro.3) or Ni-YSZ tubes to give cells of Westinghouse or inside-out Westinghouse type. The aqueous slurries contained the active powder and additives (binders). Experiments were conducted to find the most appropriate sintering conditions. If a fully sintered tube was used, the YSZ sintering temperature was 1,400°C. If green or partially heat-treated tubes were used, it was 1,300’C. A sintered LSM support tube could not be used to sinter YSZ at 1,400°C. since reaction between the two occurred. On Ni-YSZ support tubes, two sintering stages wem required to eliminate microcracks in the YSZ electrolyte layer. The linear Lao.$&&ru.g503 interconnect was deposited on the Ni-YSZ support by either plasma spraying or slurry coating, before application of the YSZ electrolyte layer. Sintering conditions for the interconnect and any proposed method of inter-cell connection on the oxidant side were not discussed. Co-firing did allow the use of a green or partially sintered LSM support tube. In the first process, the Ni-YSZ cermet was applied to the sintered tube, which was again fired at 1,300’C for one hour. In the second process, the complete green structure was fired, apparently with satisfactory results, since the components had similar shrinkage curves. In 1992, fuel cells using LSM support tubes made by the first and second processes showed 0.60 and 0.45 A/cm* at 0.6 V at low fuel utilization respectively.s3s More fabrication details were provided in a 1993 account. If a Ni-YSZ anode support tube was used to give a cell of inverted Westinghouse type, it was prepared by slip-casting and sintemd at 1,300”C for one hour, coated with YSZ, dried, and sintered twice (at 13OO’Cfor one hour, and at 1,550’C for 5 hours). The YSZ layer was masked, and a lanthanum calcium chromite layer was applied, followed by two sintering stages (1,400’C for one hour, followed by re-coating with interconnect material, drying, and sintering at 1,550’C for 5 hours). The interconnect was then masked, and the LSM slurry applied, which was followed by drying and sintering at 1,350’C for one hour. The tubes of Westinghouse type used slip-cast LSM support tubes dried at room temperature, and preheated to l,OOO°Cfor one hour. Tubes were dipped in YSZ slurry, and dried. Process I tubes were then sintered at 1,300’C for 6 hours, dipped in NiYSZ slurry, dried, and sintered at 1,300°C for one hour. Process II tubes given a second preheating at 1,OOO’Cfor one hour, dipped in Ni-YSZ slurry, dried, and co-sintered at 1,300’C for 6 hours. No interconnects were &posited on fuel cells with LSM support tubes. Tubes of inverted Westinghouse configuration showed about 0.50 A/cm* and 0.70 A/cm* with and without an interconnect on hydrogen-air at low utilization, and results for Process I and Process II tubes of Westinghouse configuration were the same as those reported in 1992.5s4 Materials work at Kyushu University has included studies of Ni cermets other than those with YSZ, e.g., with samaria-doped ceria, erbia-doped bismuth oxide, and pure ceria and praseodymia. The latter in particular yielded substantial reductions in overpotential because of its mixed conductivity (c.f., work at MHI, Ref. 546, below). s35 The kinetics of fuel electrode reactions on platinum and nickel have also been investigated?36 MHI (Chiyoda-ku, Tokyo) and The Tokyo Electric Power Company: Development of both tubular cells of traditional construction (c.f., Ref. 6, p. 590) and planar cells has been carried out. TEPCO initiated the development of a tubular cell with MHI (Tokyo) in 1988.53’ The tubular technology had been developed for the Electrotechnical Laboratory in Tsukuba by MI-II,starting in 1984. A thermally self-sustaining 500 W module with a reformer fired by the exhaust gas was tested in 1986 in the Kobe Shipyard and Machinery Works. s3* Apart from the support tube, all MHI-TEPCO tubular cell components were made by flame- or plasma-spraying, the latter at low pressure to achieve an electrolyte layer of maximum density. Tubular “stacks” with 15 cells in series (5 cm* apparent area) were tested for 5,000 hours. Performance recorded was 0.78 V at 0.20 A/cm* and at 70% fuel utilization (35 W per stack). A 1 kW unit was assembled with 12 strings each with four stacks in parallel. Rated voltage was 120 V (0.67 V per cell). The system produced a maximum power of 1.3 kW at about 87 V (0.56 V per cell) and 15 A total current at a fuel utilization of 57%. In 1990, a 10 kW stack test was expected during the next year.ssr Further details on the 1 kW stack were made available in 1992.sss The cells appeamd to be 1.9 cm in length, and 2.1 cm in diameter (active area 12.5 cm*, i.e., 10 A current corresponded to about 0.20 A/cm*). After initial testing in March 1990, the system was removed to Wakamatsu Operations General Management Office and given a 1,000 hour test from October 6.1991 to November 20,199l. The system was operated at 900°C and at 10 A and 41% fuel utilization (without anode recycle). The initial voltage was 118 v, which stabilized at about 110 v, and showed a small decay (about 3%) over 1,000 hours. The effect of anode recycle was investigated. An anode inlet composition of 46% hydrogen allowed 58% fuel utilization at 57.8% fuel recycle rate. Anode recycle was possible due to the development of a hightemperature seal so that the anode and cathode exhaust gases were not mixed.539 Other information indicated that the stack received three thermal cycles and confirmed 3% voltage degradation per 1,009

Fuel cell technology

617

hours.sa A spray-coated 1 kW tubular module was tested at the Wakamatsu Power Station of the Electric Power Development Company, Inc. (Ginza, Chofushi, Tokyo), in 1993. This had 5 sets of tubular cell stacks, each set containing 15 cells over a total length of 50 cm. The system used 80-100 pm thick Ni-YSZ anodes, 100-150 pm thick YSZ electrolyte, 150-200 pm LaCoGg cathodes, and 100-150 pm thick NiAl/A1203 interconnects on a 2.1 cm diameter CSZ support tube. The dense electrolyte layer was lowpressure plasma-sprayed, whereas other components were produced by atmospheric-pressure spraying. The module gave a voltage performance about 15% higher than that of the 1991 system at the same current, and the degradation (over 3,000 hours) was 2% per 1,000 hours. The goal was a 10 kW mcodule in 1995.541 Work on the MI-II-TEPCO planar cell technology was started in 1987. It was made by tape-casting each component and integrally sintering at 13OO’C. A single-cell performance of 0.85 V and 0.20 A/cm2 was initially reported, presumably at low utilization. 537 The system examined used Y(8Q)SZ. an LSM cathode containing 10% YSZ, and an Ni cermet anode containing 40% YSZ. Three types of cell were reported, 2.5 cm diameter (active area 4.9 cmz), 3.9 cm diameter (12 cm2), and 10 cm x 10 cm. The smallest cells operated at 0.6 V at 0.40 A/cm2 and 60% fuel utilization. Stacks were constructed with an applied Ni felt conductor on the anode side and porous LSM on the fuel side, in contact with flat interconnectors of unspecified composition, but with low IR drop. Data were given for a 3 cell 12 cm2 stack and 5-cell 100 cm2 stack. The first showed 0.6 V at 0.30 A/cm2, and the second the same voltage at 0.06 A/cm2, both at unstated fuel utilizations .sd2 An account later in 1992 described the optimization of shrinkage required in co-tiring of the cell components, and indicates that 170 cm2 cells had been developed with cathodes apparently not containing YSZ. A lo-cell stack of 100 cm2 cells operated at 0.6 V and 0.20 A/cm2, again at unstated fuel utilization. 540 The change in the YSZ electrolyte resistance with time was measured by the MIX-TEPCO researchers.s42 MHI (Kobe Shipyard and Machinery Works) with the Chubu Electric Power Company: In an independent program, MHI (Kobe Works) was developing another SOFC concept, the MOLBrM (mono block, layer built) cell with the Chubu Electric Power Company (CEPCG). Work on the concept began in 1986 at MI-II in collaboration with Professor. H. Iwahara of Nagoya University, and testing started in 1978. CEPCG started evaluation testing in 1989, and a joint program was initiated in 1990. The 1991 goal was a 1 kW stack test, with a further aim towards a 10 kW stack. Like the AlliedSignal cross-flow structure,394the MOLB stack consisted of a flat interconnect (magnesium-doped lanthanum chrornite) with corrugated anode and cathode material on each side in a cross-flow arrangement. The cell, like the interconnect, was flat. The flow-fields have been optimized by computer-modeling. Two types of sealing arrangements were used, one with flat bars of YSZ, and another with “packing.” Data obtained in 1989 on 2.3 cm x 2.3 cm single cells showed 0.6 V at 1.0 A/cm2 at the equivalent of 50% fuel utilization. Under the same conditions, 2-cell 6 cm x 6 cm stacks showed about 0.25 A/cmZ, and 9- and lo-cell 6 cm x 6 cm stacks showed about 0.15 A/cm2. A 650 hour test of the 2-cell, 6 cm x 6 cm stack had been performed by July 1990. Systems studies had been conducted from 10 kW to 300 MW.ss* By 1991, the system had been scaled up to 7.5 cm x 7.5 cm, and a 2-cell stack operated at 10.6V and 0.30 A/cm2 (utilization unspecified). A test over 2,000 hours showed an initial current density of 0.20 A/cm2 at 0.7 V, which fell to 0.10 A/cm2 after 1,ooOhours, after which it stabilized.543 A 15 cm x 15 cm single cell was shown to achieve about 0.50 A/cm2 at 0.6 V on hydrogen-air at low utilization. A 2-cell7.5 cm x 7.5 cm stack showed a starting current density of 0.25 A/cm2 at 0.7 V, which fell to 0.15 A/cm2 after 1,200 hours. No explanation for this decay was offered. 544 A 15 cm x 15 cm 40-cell :stack was constructed,s44 which was tested at CEPCO in 1992. The stack generated 538 W at 0.7 V per cell at approximately 50% hydrogen utilization, and operated for 1,000 hours until a fuel gas interruption occurred. Three stacks together generated 1.33 kW at 0.65 V and 1.2 kW at 0.7 V.54 A 2-cell7.5 cm x 7.5 cm stack operated for almost 9,000 hours from February 1993 to February 1994 at 0.7 V, initially at 0.33 A/cm2. It gave steady performance to 4,000 hours, with about 2.5% per 1,000 hours current density decay thereafter. A 15 cm x 15 cm IO-cell stack operating from July 1993 to November 1993 showed a substantially higher decay (about 20% per 1,000 hours). A 5 kW MOLB stack was proposed for 1996.541 Materials work at MHI has included improvements in anode performance by surface coating YSZ with a material with mixed ionic-electronic conductivity. Modifiers examined have been Ce and Pr oxides, and Lt~25Ceo.75 Sm0.2(&).8, which were applied as nitrate solutions to YSZ, followed by firing at 1300°C for 10-24 hours (c.f., Ref. 535). Some reduction in polarization was observed.s46 In a joint program with the Kansai Electric Power Company and the Japan Fine Ceramics Center, improved anodes made from nickel acetate containing 20% magnesium acetate and 8YSZ sol (Nissan Chemical Industries, Ltd.) were examined. The finished material was made via a drip-pyrolysis process in a quartz tube. It gave a substantially lower polarization than conventional anodes547 Fuji Electric Company (R&D Laboratories, Yokosuka-shi, Kanagawa): Planar cells were being developed by the Fuji Electric Company. Two &signs, both called “ceramic flat plate” (CFP) were envisaged, one using a conventional flat, thin cell with a cross-flow ribbed ceramic interconnect, and other

618

A. J. Appleby

was a “self-supported structure” using a ribbed anode as the foundation, with a flat interconnect. The cathode structure was also ribbed, and could be used as the self-supporting element if it proved to have sufficient mechanical strength. In 1990, it was stated that this should permit 40 cm x 40 cm cell size. Initial cells using the flat plate design were based on commercial 300 pm YSZ electrolytes, with NiO-YSZ anodes and LSM cathodes applied by slurry coating, followed by sintering under unspecified conditions. Single cells of this type with 10 cm* and 60 cm* areas were tested. Performances were 0.48 V at 1.0 A/cm* and 0.5 V at 0.6 A/cm* on hydrogen at low utilization. A three cell stack with 40 cm* cells gave lower performance. In tests to establish the performance of the substrate structure system, a NiO-YSZ ceramic disk was cold-pressed, sintered, and machined to produce gas channels. The YSZ electrolyte layer was plasma-sprayed, and a LSM cathode layer was applied by slurry coating. A stack used ribbed LSM structums with metal bipolar plates instead of calcium-doped lanthanum chromite interconnects. At 0.6 V. 50 cm* cells with a substrate structure produced 0.25 A/cm*, and those with 10 cm* electrodes produced about 0.45 A/cm* Cells with a “self-supported structure” with 60 cm* area produced 0.60 A/cm*, and those with 10 cm* area 0.80 A/cm* under the same voltage conditions, at low fuel utilization.54 In early 1992, the Fuji Electric Company announced that 50 cm x 50 cm cells 3-5 mm thick should be possible with selfsupported anode structun~. The 200 pm thick YSZ electrolyte layer was deposited by plasma spraying on a cold-pressed NiO-YSZ cermet, and the LSM cathode was in turn slurry coated on the electrolyte layer. Another approach used a composite ceramic separator, with a thick ribbed LSM substrate and a thin dense magnesium-doped lanthanum chromite interconnect, which was plasma-sprayed to a thickness of 170 pm. Five-cell stacks with an electrode area of 200 cm* were internally manifolded in the center, and gave 0.6 V at about 0.30 A/cm*, presumably at low fuel utilization. A 200 kW stack design, consisting of a central heat exchanger with eight surrounding 25 kW circular stacks was described.549 In 1992, Fuji Electric Company reported the performance of a 10 cell 200 cm* stack which operated for 2,000 hours. This report shows the internally-manifolded geometry of the Fuji Electric circular substratetype system. which has holes for fuel and air entry near the center and a series of concentric circular gas channels in the anode substrate. These channels had cut-outs to allow gas distribution, with exit cut-outs on the periphery. The system is leaky, with sealing only at the manifold holes. The cathode is ribbed similarly to the anode.sss Its gas supply resembled that in the Ztek stack4ss-‘ts7in many respects. The perimeter appeared not to be restrained, to allow for thermal expansion. The circular ribbed supports were produced by cold-pressing and sintering, and the YSZ electrolyte and strontium-doped lanthanum chromite are applied by plasma-spraying and unspecified heat-treatment. The lo-cell stack has a reported performance of 0.6 V at 0.30 A/cm*, presumably at low utilization. 55s Later (1993) information stated that the anode substrate was 3 mm thick and 20 cm in diameter. The YSZ electrolyte and La&g&.15MnC3 cathode layers were 200 pm and 50 pm thick, respectively. This time, the interconnect layer was stated to be calcium-doped LaCQ, not strontium-doped material. The interconnect was 170 pm thick, and was plasma-sprayed onto the ribbed LSM support, which was 3 mm thick. It was given an unspecified heat-treatment, and showed a very low nitrogen permeability (10-s cm4 g1 s-l). The IO-cell stack was operated for 2,000 hours on hydrogen containing 3% water and air at 1,OCO’Cand 0.2 A/cm2. It was then disassembled for inspection. After 100 hours, the average cell voltage at 0.3 A/cm* was 0.624 (fi.05) V. The average resistance was 0.97 R cm*, indicating poor inter-cell contacts. Degradation between 400-1,000 hours was an average of 5.8% per 1,000 hours, that of cells 4, 5, and 6 being in the 6.7%-l 1.7% per l,ooO hours range, whereas that of the other cells was about 1.7%-5% per 1,000 hours. The voltage degradation was attributed to nickel sintering in the anode, which was identified by pre- and post-test porosimetric analysis. Work at Fuji Electric was supported by NED0.551 Fujikura, Ltd. (Koto-ku, Tokyo): Tubular cells of Westinghouse type were being examined at Fujikura, Ltd. under NED0 funding. The fabrication process included extrusion of a support tube, sintering, and application of the air electrode. The latter was either La(Sr)MnOJ or La(Sr)CoOg, which were applied by dc-arc atmospheric pressure plasma spraying (APS) and acetylene flame spraying (AFS), respectively. This was followed by masking, application of the La(Ca)C@ interconnect by APS, then masking, and application of the YSZ electrolyte by &-arc low-pressure plasma spraying (LPS). This was followed by masking, application of the NiO-YSZ anode precursor by FS, and sealing of one end of the tube. Whether AES-type support tubes were examined was not specified. The process techniques were previous worked out on small cells, to determine best performance. A real-scale tubular cell showed 0.25 A/cm* at 0.6 V, with no utilization given. A stack in the sub-kW class was planned.ss2 Optimization of the plasma and flame-spray conditions, which could also be used in cells of planar geometry, has also been described.sss Idemitsu-Kosan Company (Sodegaura, Chiba): This company was reported to be developing tubular SOFCs using plasma spraying,5t4 but no details were available. It has reported the characterization of NiO-YSZ anode precursor materials by temperature-programmed reduction, Work is partly supported by the Petroleum Research Center, which is subsidized by MITI.ss4

Fuel cell technology

619

Mitsui Engineering and Shipbuilding Co., Ltd. (Okayama): The company has developed a planar SOFC with a unique bipolar structure. The electmchemical components are standard, with commercial YSZ (Sr 8%). They are dispersed in tolueneethanol with binders. The green YSZ sheet is prepared by tapecasting, and the electrode slurries am cast in molds containing a sheet of carbon or plastic fiber to create gas channels. The separate components are sintered, and are bonded at “high temperature and pressure.” The bipolar structure consists of a sheet of non-conducting MgAl204, containing disks of electrically-conducting LaCaCQ. The area and distribution of the disks has been optimized using a computer model to minimize ohmic losses. Green sheets of each of these ceramics are made by tape-casting, followed by sintering. The MgA1204 sheet has appropriate holes cut in it, and the LaCaCrQ disks are bonded into it by thermal processing. Between the end of 1990 and early 1992, cell performance at 0.6 V was increased five-fold to 0.60 A/cm2 under unspecified conditions at 1,000”C, in spite of a scale-up to 10 cm x 10 cm cells. An endurance test of a 10 cm x 10 cm cell showed 15% performance degradation over 1,000 hours. .An &cell externally-manifolded 100 cm2 stack showed 0.70 A/cm2 at 30% fuel utilization at an average voltage of 0.6 V. A new stack design containing four cell windows (c.f., Refs. 318,449, and Murata Manufacturing Company, below), internally manifolded around the periphery, has been described. Each adjoining quadrant of the four-cell plate units contains an anode, a cathode, an anode, and a cathode on one face, manifolded appropriately. Each of the four separate sub-stacks can be connected in series with straps like the cells of a lead-acid battery, and several stacks each with four sub-stacks can be connected in the same way to obtain any desired voltage and power level.sss

Murata Manufacturing Company (Nagaokakyo-shi, Kyoto): A co-fired (monolithic) SGFC was developed at the Murata Manufacturing Company, Ltd., but the process could not be scaled up beyond an area of 12 cm2, because of the different shrinkages in the individual dense and porous components. Accordingly, the system was assembled from co-fired anode-electrolyte-cathode elements and separately fined interconnects. The effective area of single cells was then 100 cm 2. The cross-flow system used a flat anode and cathode, and flat electrolytes and interconnects each 100 pm thick. Ribs of Ni-YSZ and cathode material were respectively placed on the anode and cathode. The total cell thickness was 5 mm. The standard materials were formed by doctor-blading, and combined to give green anode-electrolyte-cathode multilayers, which were co-fired below 14OO’C. Monolithic ceramic distributor channels, as well as those consisting of Ni-Cr alloy, were also examined. A lo-cell 100 cm2 stack with glass seals gave 0.6 V at 0.50 A/cm2, presumably at low utilization .556 A 1 kW-class stack developed in 1992 had a structure resembling that of the Siemens SOFC,449 with internal manifolding in a frame similar to that of the Hitachi MCFC318 but on a smaller scale (c.f., Ref. 555, Mitsui Engineering and Shipbuilding Co., above). Th[e current collectors were Ni and Ni-Cr alloys on the anode and cathode side respectively. The interconnects; were NiCr alloys. The anode and cathode were each about 40 pm thick, and were bonded to an electrol,yte which was a laminate of PSZ (Refs. 427, 444, 528) and YSZ sheets. The total thickness of the ensemble was about 300 pm. The cell-to-cell distance was 8 mm. Each window unit was 150 cm2, with an effective area of 110 cm2. Considerable performance degradation was observed in small single cells, especially at high current density. although little change in anode and cathode morphology was noted after 1,000 hours. Single cells with 110 cm2 active area achieved 0.30 A/cm2 at 0.7 V, and 0.60 A/cm2 at 0.5 V, presumably at low utilization. The performance of a 6-cell stack under constant flow conditions at unstated utilization was 30 A (0.27 Alcm2) at about 0.63 V .ss7 Later information included details of the co-firing process for the anode, electrolyte , and cathode, which were standard materials. After lamination, co-firing took place at 1,400”C. Mismatching of shrinkage profiles and thermal expansion coefficients was minimized for successful results to be obtained. Interconnects were either Ni-Cr alloy or lanthanum chromite of unspecified composition. Grinding was used to create grooved gas channels on interconnects, which were sealed with compounds of unspecified composition to co-fired cells. A three-cell stack with the Xi-Cr alloy interconnects gave an average of about 0.65 V at 0.15 A/cm2 and 40% hydrogen utilization. In contrast, a two-cell stack with lanthanum chromite interconnects gave an average of 0.7 V under the same conditions. The loss in the interconnect appeared to be about 30% of that in the oxide film on the metal interconnects. Evidence was given of the performance stability of improved anodes and cathodes over 450-500 operating hours.ssa The above Murata work was supported by NED0.SS7Sss In a parallel program for the Osaka Gas Company, cells were fabricated by screen-printing layers of Ni-YSZ and 50 pm thick LSM-YSZ (not pure LSM) onto 0.3 mm thick sintered YSZ. These were sintered to give 12 cm x 12 cm cells. The 12 cm, x 12 cm LSC interconnect was flat on the anode side, and had grooved gas channels on the cathode side. The flat side contacted the anode of the next cell via a nickel felt (c.f.. Westinghouse), which served as a fuel gas distributor. Each cell was 5 mm thick:, and was surrounded by a ceramic cell frame (or frames), containing internal manifolding for fuel and air on opposite sides of the active cell area. The gases passed in co-flow through the stack, and in cross-flow through each cell. In a 5-cell stack, 70 W was obtained at 0.15 A/cm2 at unspecified hydrogen utilization. In a 65-cell stack with the same active cell area, 70 W was obtained at about 0.62 V at the same current density and at fuel and oxidant utilizations of 12% and 40% respectively. Without the 3 lowest-performing 5-cell modules removed, 0.7 V at about 0.09 A/cm2 was obtained, and degradation was 6% per 1,000 hours. A 90 mV

620

A. J. Appleby

reduction in OCV and performance was observed after a thermal cycle, which had resulted in leakage. In post-test analysis, anode sintexing and the presence of La2Zr$J7 was detected in the electrolyte.“s National Chemical Laboratory for Industry (Tsukuba, Ibaraki): The laboratory has described a new stack concept which may be suitable for small co-fired components, which should be most economical in mass production. The proposal is called the “Train” Stack, in which cell block would operate at the same current but different voltages, and would be supplied with fuel in series (i.e., in a train), so that the anode entry fuel becomes progressively more dilute from stack to stack, until 80% utilization is reached. The problems of co-firing involved the differential shrinkage of different porous and dense components, diffusion effects which prevents densification of the lanthanum chromite interconnects, and &gradation of lanthanum manganite at high sintering temperatures. The second problem might be avoided by the use of a polyurethane foam impregnated with lanthanum chromite sandwiched between two films of lanthanum chromite and YSZ respectively. The assembly may be co-sintemd to give dense interconnect and electrolyte films joined by a lanthanum cluomite foam plate, which could be subsequently impregnated with lanthanum manganite, which in turn could be sintered at lower temperature. Similarly, the anode side could have a foam impregnated with YSZ, giving a porous YSZ layer which could be impregnated with NiO-YSZ. Other variations on the same proposed technique were possible. 560 Other work in the same laboratory has examined the preparation of air-sinterable La(Ca)CQ interconnect material, the circumstances of formation of an a-CaCrO4 phase,561 and oxygen permeation through the interconnect

materia1.562

NGK Insulators, Ltd. (Nagoya): This company has an active program development, which is aimed at reducing contact resistances in co-fired structures metallized LSC bipolar plates.514 The company has reported on the properties thermal spray-sintering process. This produces a product with high gas-tightness, small shrinkage. It allows easy masking and easy doping with other elementssfl

on SOFC component and the use of nickelof LSC prepared by a high conductivity, and

NKK Corporation (Kawasaki): A planar SOFC with a metallic separator has Alloys studied included NiCrFeAl, Corporation, also under NED0 funding. compositions, which were compared without coating and coated with a conducting l.trn thick prepared by plasma-spraying. Oxide formation on the coated material uncoated samples, and two coated alloys (NiCrFe and NiCrAlFe) forming Cr2Og

been reported by NKK NiCrFe, and NiCrAl oxide coating about 40 was about half that of films maintained a low

resistance of 5 mR cm2 for 8,000 hours. This did not occur with alloys forming superficial Al203 films. Rectangular internally-manifolded cells with an active area of 144 cm2 were prepared by doctor-blading of YSZ films with screen-printed standard anode and cathode components. No sintering procedures were given. Each cell with a coated metal bipolar plate was 5.5 mm thick. Whether coatings were applied to both sides, or only to the cathode side, was not stated. Single cells operated at an initial performance of 0.74 V at 0.30 Afcm2, and an g-cell stack operated at 0.65 V and 0.30 Alcm2, both at 31% fuel utilization.s64 hG+T(interdisciplinary Research Laboratories, Musashino-shi, Tokyo): A cell has been designed with what is described as a tubular porous flat plate (i.e, a plate in the form of a flattened tube) as the support element. This was made from anode material (60 wt % nickel oxide, 40 wt % Tohso TZ8Y YSZ). This was mixed with a water-soluble binder and cast or extruded into porous plates. After sintering at 1,300°C, its 1,OOO”Cspecific conductivity was 300 S/cm. The plates are described as being 12 cm long and 4 cm diameter, with a thickness of 4 mm. The description of the cell geometry is not entirely clear, but it is stated that an plasma-sprayed (in air) YSZ electrolyte layer about 200 pm thick may be placed on one side, together with an LSM air electrode layer. An air plasma-sprayed lanthanum chromite (presumably LSC) layer could be sprayed on the other side. The YSZ and LSC layers had reasonably satisfactory gas permeabilities, which required improvement. The tubular plates would by supplied with hybogen on the inside, and would be interconnected by unspecified “conducting porous material” on the cathode side. The flattened anode tube would have internal conducting supports or pillars to allow perpendicular current flow. The whole structure would show low IR drop, and would only require end sealing with suitable glasses. A single cell of the above dimensions (active area 24 cm2) gave 0.65 V about 0.5 A/cm2 at 9OO’C and at about 0.8 A/cm2 at l,OOO°C on hydrogen and oxygen at unstated utilizations. 565 Work on the cubic stabilization and ionic conductivity in the ZIO~-SC~O~-A~~O~ system has also been reported.sa Sanyo Electric Company (Moriguchi-shi, Osaka): This company was developing planar SOFC stacks characterized by the use of alloy bipolar plates. The other materials were standard, with an LSM (Srg.1) cathode, sintered for 4 hours at 1lOO’C in air. The Ni-YSZ cermet was sintered for two hours at 1,250’C. The system was sealed by an SiO2 or B203-Si02 glass, combined with a “flexible seal” to the bipolar plate. Cells were 5 cm x 5 cm and 15 cm x 15 cm, with active areas of 20 cm2 and 125 cm2 respectively. They operated at 0.84 V and 0.74 V respectively at 0.30 A/cm2 at unknown (presumably low) utilization. A locell 125 cm2 stack had achieved 0.59 V per cell at 0.30 A/cm2 at l,OOO°C at 50% fuel utilization and 15% oxidant utilization. The effect of decreasing YSZ particle size in the anode to increase cell performance by

Fuelcell technology

621

lowering the interfacial resistance was also studied. 567 Single cells had been sealed with over 99% efficiency. A 125 cm2 single cell operated at 0.7 V at 0.30 A/cm2 at a fuel and oxidant utilization of 40% and 25% respectively, a 1l-cell, 125 cm2 stack operated at 0.64 V (average), and a 20-cell, 125 ,cm2stack operated at 0.5 1 V (average), both at 982OCand 0.30 A/cm2, and at fuel and oxidant utilizations of 50%, 15% and 30%, 15% respectively. Another plot in the same report showed the performance of the 1l-cell, 125 cm2 stack as a function of fuel utilization at an oxygen utilization of 15%. This indicates an average of about 0.51 V at 30% fuel utilization, 0.47 V at 5096, and 0.41 V at 80%. A 1,000 hour endurance test was also given, which showed performance at 0.30 A/cm2 at 50% fuel utilization for the first 600 hours, with a decay under these conditions from slightly more than 0.60 V (average) to 0.45 V.568 It would therefore seem that the results refer to different test times. Further details of these tests and of the construction of the stacks was given in a later report. The stacks were internally manifolded with square holes, and the electrode was also cut out for manifolding. The electrolyte was specified as partially stabilized zirconia (PSZ, 3% yttria, c.f., Refs. 427,444,528,557). The performance of the 1l-cell stack was again stated as being 263 W at 50% fuel utilization and 0.30 AJcm2, i.e., 37.5 A at 7.0 V, or 0.64 V per cell average.569 Recent work (1994) has pointed out the problems associated with evaporation of chromium as Or03 on the cathode side of the bipolar plate (c.f., Siemens, above). A good correlation was found between Cr loss and vapor pressure, and polarization due to the presence of Cr2O3 films increased rapidly as the operating temperature was reduced from l,lOO”to 85OOC.Polished and heat-treated Inconel600 was less susceptible to these effects due to the formation of thin NiO and Fe-04 layers outside of the 15 pm CQ@ layer. The application of a ca. 50 pm protective layer containing La203 (10 wt 96)and LS(O.l)M was examined, which could stabilize chromium loss for at least 700 hours. A 15 cm x 20 cm 3O-cell stack using PSZ electrolyte and untreated Inconel600 bipolar plates, with cathode current collectors with the above protective coating (70 pm thick) was constructed and tested at l,OOO°C.Rather stable performance was obtained over almost 900 hours at 0.3 A/cm2. At 0.25 Afcm2 and 30% and 15% fuel and oxidant utilizations, 0.,67 V was obtained.5’0 Work at Sanyo was partially supported by NED0 under the New Sunshine Project.569*570 Tonen Corporarion (Irumu-gun, Saiturnu): Research on planar SOFCs started at Tonen Cor]porationin 1987, with PSZ (3% yttria, 85% tetragonal, 15% cubic) as the electrolyte of choice, because of its toughness (Refs. 427, 444, 528, 557. 569). Small single cells (0.5 cm2) were examined early in the program to test this electrolyte. Electrolyte plates of 2.5 cm diameter and 0.2 mm thickness were spread with electrode slurry on each side, containing the active powder, binders, and a solvent. Sealing was via a glass which softens at the operating temperature. These cells were used to determine the effects of alumina additives to the electrolyte, and the effect of adding platinum to the LSM (Sro.1) air electrode. Small cells with platinum mesh contacts gave over 0.5 W/cm2. Single 5 cm x 5 cm cells with an active area of 18 cm2 were tested with heat-resistant alloy bipolar plates, which were sealed via glass to allow for the difference in expansion coefficient. These cells typically achieved 0.20 W/cm2, or 0.28 W/cm2 with a 0.1 mm thick electrolyte. A IO-cell stack with 100 cm2 active area gave about 0.32 A/cm2 at 0.6 V, and 0.3.5 A/cm2 at 0.55 V, the latter value being at a fuel and oxidant utilization of 30% and 15% respectively. The stack was contained within a circular alumina ring, which served for external cross-flow manifolding.s71 In 1991, a 30-cell, 225 cm2 stack was developed. The alloy (Inconel600) and L~$ro 2Cro.gCoo_103(LSCC) as the bipolar plate material were compared. With the metal plate, an increase in cathode overpotential was observed after 50 hours, and current density fell to 50% of the initial value after 600 hours. This was identified as being due to the presence of 7-15 at % of Cr in the cathode-PSZ interface. With LSCC, no degradation was observed in oxygen, but some was observed in air. A source of degradation was sintering of the cathode at the interface, which was enhanced in regions of high electrochemical activity.572 In 1992, 5 cm x 5 cm cells were tested, with 0.2 mm thick YSZ (8% yttria) substituted for PSZ. The anode and cathode materials were painted on the electrolyte to give an active area of 16 cm2. Anode and cathode side bipolar plates were either both LSCC, or nickel and LSCC. The total material resistance was 0.16 W cm2, whereas cell resistances varied from 0.2 to 0.58 W cm2. Cells were operated at 0.18 W/cm2 over 1,000 hours at 80% hydrogen utilization and 40% LHV efficiency, i.e., 0.625 V at 0.29 A/crn2.sig A 7,500 hours test showed 2.3% decay per 1,000 hours. More recent work has reported the usle of direct hydrocarbon (methane) feedstock at a steam-to-carbon ratio of 2.5 in two single 16 cm2 cell with the same electrolyte and cathode as previously. Separators were improved LSCC. Anodes were chosen from Ni/ZIOz with 4.20, and 48 mole % of ceramic after performance stability experiments with steam-to-carbon ratios in the 2 - 3 range at l,OOO°C. Whereas performance quickly decayed for the 4% composition, the others remained stable. As a result, anodes with 20 mole 96ceramic were selected. Tests were conducted at 0.25 A/cm2 and 80% fuel utilization and 0.3 A/cm2 and 70% fuel utilization. The former gave 0.66 V initially, corresponding to 50% LHV efficiency. The latter gave about the same initial voltage, which decayed to just over 0.5 V over 6,000 hours, corresponding to about 36% LHV efficiency. Decay was 3.0% per 1,000 hours, and was related to anode sintexing.s74 Inconel-alumina cermets have been examined as possible bipolar plates materials (conductivity 180 S-cm-l, compared with 104 for Inconel

622

A. J. Appleby

600). They may be useful if the interface can be protected from migrating chromium. Work at Tonen is partially supported by the Petroleum Energy Center, which is subsidized by MITI.s74~7s TOT0 Ltd. (Chigasaki, Kanagawa): This company has worked in collaboration with Kyushu University in a program similar to the joint activity between the same University and Saibu Gas.sssJs‘t A Westinghouse-type cell with an AES support tube was described, in which the latter consisted of Lao.7&.25Mn(Al)(Ni)03. The composition was chosen to minimize reaction between the material and YSZ, and the Al and Ni dopants were added to reduce polarization. The tube was extruded, and could be either open- or closed-ended. The tube was sintered and masked, and an interconnect layer of La(C~.2@Q was deposited from a slurry and sintered. After sintering, the 100 pm thick layer was dense and showed little evidence of the formation of second phases such as CaCrG4. The conductivity of the interconnect layer as a function of Ca content was examined Measurements showed that the expansion coefficients of the cathode material and interconnect were 10 and 9 x 10-6PC respectively. The thickness of the slurry-coated dense YSZ film was 20-30 pm. The NiO-YSZ anode mix gave best performance with a fine particle size (0.2 pm) at a firing temperature of 1,400’C. The performance of a 50 cm cell with an active area of 124 cm2 was 0.41 A/cm2 at 0.7 V and 20% fuel utilization. About 0.70 A/cm2 was attained at 0.6 V.576 Recent work (1994) indicated that the support tube material had been replaced by standard LSM, and that the anode was 70 wt %INi-YSZ. The interconnect and electrolyte layers, and the preparation of the anode and these components were as in previous work. The effect of AES thicknesses from 1.7 mm to 3.1 mm and porosities from 22.6% to 42.8% on performance were examined. The highest power densities were given by 36% porosity. The performance was not strongly dependent on tube wall thickness, since there was some compensation better the effects of mass transport and electronic resistance. At 1,OOO°Con humidified hydrogen and oxygen, 0.75 A/cm2 was obtained at 0.7 V, at unknown (low) utilizationsn Other SOFC Developers: Other companies involved in the SOFC field were the Aso Cement Company (fabrication of 8YSZ sheets under 0.1 mm thick by extrusion), IHI (planar SOFCs using co-firing), and the Nippon Gil Company (steam-reforming catalysts for naphtha at low steam-to-carbon ratios).514 Supporting Work on the SOFC: Fundamental work at research laboratories includes the behavior of non-porous perovskite cathode materials operating by mixed conductivity,s’* modeling of gas diffusion and current density distribution in a Westinghouse-type tubular SOFC579 (both at the Electrotechnical Laboratory, Tsukuba), studies on laser spray coating 580 (the Electrotechnical Laboratory with Tsukuba University and the Ibaraki Prefectural Industrial Technology Center), and studies of the mechanical and electrical properties of alkaline earth-doped lanthanum chromites 5s1(at CRIEPI). Other work published by CRIEPI has included estimates of the production costs of SOFCs, based on 2 MW per month fabrication rate. Planar single cells operating at 0.21 W/cm2 were assumed to be fabricated by doctor-blading layers of green materials followed by firing, with interconnects made by pressing and firing. This would be followed by assembly into 400 W stacks, each with 20 cell and 21 separators. The total cost of a planar system of reduced thickness was 118,OOOy/kW,of which materials would represent 68,OOOy/kW.Of this materials cost, 80% was that of the interconnect (at 7,OOOY/kg,$7O/kg at the trading exchange rate). Tubular Westinghouse-type cells operating at 0.18 W/cm2 were assumed to be made by either EVD or plasmaspraying. The production cost of CSZ support tubes (at 6,OOOY/kg) was 77,OOOY/kW, of which materials were 29% (22,OOOY/kW).The total production cost by EVD was 54O,OOOY/kW, and by plasma spraying 216,OOOY/kW.The production of the support tubes alone required higher labor expenses (32,OOOy/kW) than those of the complete planar stack (25,OOOY/kW). The EVD process requited a very high materials cost (324,OOO~/kW) because of low (5%) materials utilization and the use of expensive pure metal chlorides (see comments in Section 29, Conclusions). It also was stated to have a very high labor expense (151,OOOY/kW, compared with 123,OOOY/kW by plasma spraying). The authors suggested that thinning of the interconnect.in the planar system and increasing performance to 0.5 W/cm2 would result in a commercial system costing about 38,OOOY/kW ($38O/kW at the trading exchange rate).s82 A further consequence of the study is the effect of substitution of an AES tube at 6,3OOY/kg.This would add only 1,OOOy/kW(at 0.18 W/cm2) to the materials and overall production costs, but would permit a substantial increase in power density, lowering the tube cost to perhaps 4O,OOOY/IcW or less. Whether this approach may lead to a viable commercial system of improved EVD or plasma-spray type remains to be seen. University work has included studies of the electrode behavior of LSM on YSZsss and conductivities of YSZsu (at Akita University), stress distribution in the Westinghouse-type tubular SOFC!sss(at Kyoto University), development of a vapor-phase process for preparation of Ni-YSZ cermetss6 (Kyoto University, with the Kansai Electric Power Company), the electrical properties of PSZ and aluminacontaining YSZ,s87 and the electrochemical properties of La(Ca)MnOg cathodessss (both at Mie University). Other University studies are represented by the use of Dy-doped BeCeO3 as a solid electrolytess9 (at Nagoya University), the electrophoretic deposition of YSZ,sgothe oxide ion conductivity of lanthanide oxide-alumina perovskites 591(both at Oita University), YSZ thin films with relaxed thermal stress,srQmeasurement of gas leakage between alloy bipolar plates and YSZ platess93 (both at the Tokyo

Fuel cell technology

623

Institute of Technology), electrical conductivity and thermal expansion coefficients of Mn perovskite~~~ (at the University of Tokyo), electronic conductivity and Seebeck coefficients of LSMsss (at Yokohama National University) and studies on patterned nickel anodes on YSZ 5% (Yokohama National ZJniversity with the Shibaura Institute of Technology, the Ion Engineering Research Institute Corporation, and the Tokyo, Osaka, Toho, and Saibu Gas Companies). 28. 1992-1995 FUEL CELL SYSTEMS STUDIES United b Department of Energy: An overview of probable contaminants in coal gas and their probable effect on the operation of the MCFC (starting August 1988 at ERC) and on the SOFC (starting September 1989 at Westinghouse) has been given.597 Results for the MCFC showed that NH3 had no effect (maximum concentration in raw gas 10,000 ppm. equilibrium concentration 55 ppmv after dissociation), as would be expected. Volatile metals, e.g., Cd and Hg (maximum 5 ppmv and 0.5 ppmv respectively) had no direct effect. Even at 30 ppmv Cd no direct effects were seen, although solid Cd0 could condense on cool piping. In contrast, Zn (maximum 60 ppmv) did show an irreversible loss at 35 ppmv, but no loss at 15 :ppmv. Sn (maximum 3 ppmv) showed no effect, although gaseous SnS at 40 ppmv showed the expected effects of sulfur contamination. At the time of reporting, Pb had yet to be tested. HCl (maximum 100 ppmv) had no direct effect on cell performance at the 0.1 ppmv level, but it reacted with the electrolyte and was removed in the exit gas as KCl. No attack on nickel was observed. The safe level is probably 0.1 ppmv. Both H2S and H2Se (maximum in raw gas 15,000 ppmv and 5 ppmv respectively) attack nickel. A minor performance loss was observed with 1 ppmv H2S, but none at 0.5 ppmv H2Se. Any loss was recoverable at open circuit in clean gas. AsH3 (maximum 10 ppmv) showed no immediate effect at 1 ppmv, but eventually it reacted to form NiAs, which was irreversib1e.s” Energy Research Corporation: In 1992, ERC (with Destec Engineering, Inc. and Haldor Topsee, supported by EPRI and DOE) described the systems work involved in integrating their 20 kW intemalreforming MCFC with the Destec demonstration coal gasification plant in Plaquemine, LA. The plant had a pressurized, entrained-bed, slurry-feed, slagging gasifier with continuous slag removal. Some of the cleaned gas from the plant was to be diverted after mixing with steam for the 4,000 hour MCFC test. The stack was to be the first to use the new 0.56 m2 (6 ft2) technology, with lightweight end-plates to improve thermal management. The MCFC demonstrator would be mounted on seven skids, and would be trucktransportable to enable it to be used for demonstrations elsewhere, e.g., of landfill gas or biogas.sa* The experimental test, which took place in 1993-1994. has been described in Section 26 (Ref. 177). A modeling analysis of performance data obtained has been given in Ref. 257. Up to the end of 1995, no performance evaluation on landfill gas or biogas had taken place. This would in any case require the construction of a new stack, since the Destec stack was dismantled for post-test analysis. ERC had also worked with Fluor Daniel and the Energy and Environmental Research Center of the University of North Dakota to determine the most effective coal gasifiers for use with fuel cells. Three conceptual 200 MW, systems using low-temperature catalytic gasification systems which maximize methane production were examined (c.f., the Exxon Gasifier, Section 17). With conventional cold gas clean-up, HI-IV efficiencies of 50.6% to 53.5% should be obtainable.sw GilberrlComnwnwealfhinc.: Integration of the MCFC in a coal-toliquids facility with indirect FischerTropsch liquifaction of clean coal gas (the “coal refinery”) has been described. Based on 1988 pressurized MCFC performance, the plant would have a total conversion efficiency of 56.5% 12.0% being electrical and 46.5% coal liquids and byproducts. The high efficiency of integrated conversion to electricity in the MCFC would subsidize the cost of liquifaction .55 By 1992, the company had identified fuel cells as being attractive if C@ capture for sale or sequestration is required, since their anode exit streams are undiluted by nitrogen. Five systems were examined, including (1) a 10 MW NG PAFC, (2) a 100 MW NG :MCFC,(3) a coal-fueled 100 MW MCFC, (4) a coal-fueled 200 MW SOFC, and (5) a 200 MW MCFC combined cycle system. For (1) and (2), CO2 could be removed from either the anode inlet or exit streams. For (3) alternatives were C@ capture at the flue exit or at the anode exit, with recovery of the amount required for cathode recycle. For (3). an attractive alternative was to bum the anode exit gas with pure oxygen from the gasifier supply plant, allowing simple CO2 separation. For (4), the corresponding alternatives were C@ capture at the flue exit or following acid gas clean-up. For the MCFC combined cycle, no recommendation could be made, presumably because the fuel cell required CQ recycle, which precluded recovery after gas clean-up, and flue gas recovery was not practical due to nitrogen dilution. This may require re-evaluation, since it is system-specific. Some alternative Coz separation techniques were discussed.sOO An update of the 1992 report, using ASPEN/SPTM&sign code to optimize the above systems was given in 1994. This estimated the increased cost of electricity for various options for the five basic systems.601 The base case for each was a system with no CO2 removal. The options involved Ca removal at logical points in each system (PAFC, at anode exhaust and anode feed, NG-MCFC, from flue gas and anode exhaust; NG-SOFC, from cycle exhaust and anode exhaust; coal-MCFC, from flue gas and

624

A. J. Appleby

via an 02 catalytic burner; coal-SOFC, from flue gas and anode feedstock). The base electricity costs varied according to system scale and efficiency, and according to the capital cost assumptions used. The key comparison between each system is the incremental costs of partial (i.e., optimized) C@ removal (i.e., the increased cost of electricity, COE) in each case. The emissions of C@ at the plant could be reduced by 65% to 94% of those of the base case, depending on the system. In part, the cost of CO2 removal reflected the capital cost of removal equipment, but the major part of the increased cost lay in the energy requirement for Co2 separation. The effect of this is seen in the reduction in system efficiency in each case. For the PAFC, the absolute plant efficiencies were degraded by 7% (for removal from anode exhaust gas) to 10% (base efficiency, 48.5% LHV), increasing COE by 62-74% from the base value of 6.5$ per kWh. The best case resulted in avoiding 63% of m emissions. For the NG MCFC, the only practical strategy was flue gas removal (83% of emissions avoided), which decreased absolute efficiency by 13.5% (base 61.5% LHV), and increased COE by 46% (base 5.46$ per kWh). The two options for the NG SOFC reduced plant efficiency (base 65.9% LHV) by 12.6% (84% emissions avoided) and 14.3% (94% emissions avoided) respectively, increasing COE by 48% and 87% (base 4.552 per kWh). For the two coal systems, the most practical solutions were: (MCFC) catalytic burner removal (79% emissions avoided, 23% reduction in absolute efficiency, base 45.5% LHV; 43% increase in COE, base 6.72~ per kWh) and (SOFC) anode feed removal (77% emissions avoided, 15.6% reduction in absolute efficiency, base 50.3% LHV, 39% increase in COE, base 5.62e per kWh). In general, costs would be lower as plant efficiencies increased, and with increasing H-to-C ratio in the fuel, i.e., as the amount of CO2 produced per kWh decreased. Tbe best-case costs (dollars per metric ton) for the C@ separated varied from $84-$154 (NG systems) to $44-52 (coal systems). The above costs are in January 1994 dollars (multiplier to mid-1995 dollars, 1.035). The repot@’ concluded that significant quantities of C@ could be disposed of in the deep oceans for a 4060% increase in COE, which would only be economical if carbon taxes were introduced. However, this neglects the cost of transportation and disposal in the deep oceans, which may be as much as $60~$100 per metric ton of C@. The cost of disposal would raise the effective COE from 85-125% (at $100 per metric ton for disposal) or by 75-95% (at $60 per metric ton). Gilbert/Commonwealth has also described the use of the ASPEN/SPT”* code for optimization of MCFC systems. Similar models were being developed for the PAFC and SOFC systems.602 Cerumarec, Inc.: SOFC cogeneration systems have been studied for residential and commercial applications with the Department of Mechanical Engineering, Marquette University, Milwaukee. These show the possibility of much greater second law efficiency than conventional energy supply.@jss Other work at Ceramatec includes studies on SOFC systems with stacks connected with a series fuel supply, to allow higher fuel utilization at an effectively greater aggregate average stack voltage (c.f., Ref. 560).604 AlliedSignal: This company has conducted studies on MSOFC integrated reforming. Systems examined were 10 and 50 kWe auxiliary and a 15 kW? 375 kWhe diesel-H202 system for autonomous underwater 50 kWe design would weigh 4.3 kg/kW (2.1 kg/kW for the fuel cell Efficiency was approximately 49% (LHV). The designs have also locomotive power plant.605

systems using diesel fuel with power units for the U.S. Army, vehicles for the U.S. Navy. The core), and occupy 4.0 liter/kW. been scaled up to a 3,730 kW

Argonne National Laboratory: The SOFC operating e.g. on LNG have also been examined for transportation applications, particularly for locomotives. The stress was on fuel economy and low emissions. For example, it is estimated that locomotives now produce 5-10% of emissions in Southern California. The authors point out that a MSOFC stack could be heated from ambient to 8OO’C without exceeding permissible thermal stresses. 606 A paper on the fundamentals of fuel cell system integration included a discussion of cost reduction and the learning curve as production increases.607 Other: Pressure swing absorption (PSA) has been considered as a means of removing hydrogen from SOFC anode gas for recycling. This can improve cell performance by increasing Nemst exit potential. As well as the energy trade-off in operating at higher cell voltage and utilization, compared with the work requirement for the PSA process, higher utilizations using external reforming will require higher steam-tocarbon ratios, which will incur significant energy penalties. 608 However, this will not be so if the system uses internal reforming, driven by in situ hydrogen consumption and product water formation.

The Netherlands: Different options for fuel cell-coal gasifler cogeneration plants have been modeled using the ASPEN PLUSTM process simulator. 6sae6ra In the early 199Os, 40% of world’s electricity was produced from coal, and coal was expected to continue to be important. The high-pressure slagging gasifiers considered were British Gas-Lurgi (oxygen-blown fixed bed, dry-feed, 92% efficiency based on * Simulation Sciences, Inc., Aurora, CO.

Fuel cell technology

625

the LHV of coal in to the LHV of gas out); Dow (oxygen-blown entrained-bed, slurry-feed, ‘74% LHV efficiency); Ptenflo-Shell (oxygen-blown entrained-bed, dry-feed, 81% LHV efficiency); Texaco (oxygenblown entrained-bed, slurry-feed, 74% LHV efficiency); and I-IT-Winkler (air-blown fluid&d bed, dryfeed, 88% LHV efficiency). The efficiency figures confii, or are very close to, those calculated in Section 17. Two MCFC plants with Texaco gasifiers and steam bottoming cycles, one with low temperature gas clean-up, the other with high-temperature clean-up, were compared to a Texaco integrated gasifier gasturbine combined cycle plant with low-temperature gas clean-up. Computed system efficiencies (LHV) were 49.2% 53.24, and 41.7%, respectively. For the 2020-2030 time-scale, three coal plant concepts were compared. They were pulverized coal with fuel gas desulfurization and NO;! removal; integrated gasifier combined cycle; and integrated gasifier MCFC or SOFC. They would have LHV system efficiencies of 468, 50%. and 55%. respectively. Expressed in g/MWh, N@ emissions would be 260, 185. and ~10; with SO2 emissions of 160, 30, and 2; and particulate emissions of 45, c6, and ~6. Corresponding investment costs would be equivalent to $1,330-1,13O/kW, $1,860-2,OOO/kW, and $2,1002,3OO/kW (mid-1995 dollars, at the then-current trading exchange rates). Other plants in the same timeframe with CQ recovery were oxygen-combustion pulverized coal, oxygen-combustion integrated gasifier combined cycle, integrated gasifier with shift and CO2 absorption followed by combined cycle, and integrated gasifier MCFC with membrane removal of Co;! after the anode exit. Respective LHV efficiencies were 37%, 45%. 42%. and 50%, with 96%. 96%, 88% and 97% CG2 recovery.6to The review discusses gas clean-up requirements for the MCFC and SOFC. The integrated gasifier combined cycle plant at Buggenum was to have a gas impurity composition after Sulfinol clean-up of 5 ppmv H2S; 15 ppmv COS; ~0.1 ppmv 15 ppm HCl; ~0.1 ppmv HF; and 100 ppmv CIQ. ‘The sulfur compounds would require polishing via a zinc oxide bed (or zinc titanate hot gas clean-up followed by zinc oxide polishing). Removal of the halogen compounds was adequate with Sulfinol, but an alkali or carbonate pretreatment would be required before hot-gas sulfur clean-up. Particulates would also require removal.610 An update was available on the performance of the Heron turbine.ra*rs The Pilot Model-l was a compact. truck-trailer size unit which was half of the size of the prototype Model-O. The prototype was a three-shaft machine because of lack of compressor optimization, and it operated at a compression ratio of 7.47 and a turbine inlet temperature of 915’C (power turbine exhaust 735°C compressor drive turbine inlet temperature 7OO’C). The Model- 1 was a 1.4 MW, 43% LHV efficiency two-shaft machine with back-toback centrifugal compressors driven by an axial low-pressure turbine. The compressors operated at 3 atma and 9 atma with an intervening intercooler. Both the centrifugal power turbine and axial compressor turbines had an inlet temperature of 86O’C. The exhaust heat from the power turbine (62O’C) went to a vertical tube recuperator which served as a heat exchanger for the air from the compressor. This is followed by a combustor to drive the compressor turbine, and a further combustor to drive the power turbine. Because of the low temperatures and lean burners, N02, emissions of 20 g/GJ (167 g/MWh) or less were expected, i.e., approximately 10 ppmv or less at 15% oxygen, dry basis.611 The aim was a 1-2 MW unit costing ca. $1,000/kW.612 Researchers at the Delft University of Technology have modeled HTFC systems to determine exergy losses in the MCFC and SOF@a and the dynamic behavior of integrated MCFC systems.614

Germany: The Jiilich nuclear research center has examined some system requirements for a cogeneration SOFC. For 1,OOO’Coperation with a co-flow system with external reforming and 70% fuel utilization at 0.8 V (i.e., zero polarization), a heat exchanger area of 0.48 rn2 per kW (electrical) would be required, which must be constructed from superalloys or ceramics. The cost of this air preheater will apparently be $1,65O/kWe (mid-1995, at the trading exchange rate). For 700°C, 900°C air inlet and outlet temperatures at 90% fuel utilization at 0.75 V with internal reforming, an austenitic steel heat exchanger may be used, which would cost only $75/kW (same basis) .‘j15 Systems optimization approaches for the MCFC have been considered by MTU Friedrichshafen GmbH (part of Deutsche Aerospace AG). This emphasized the effect of series production on the cost reductions of CSA components. In contrast, the series production of BOP would not result in significant cost reduction. It compared more complex MCFC systems with hydrogen transfer and anode recycle with simplified systems, and stressed the cost advantages of simple integrated systems operating at low pressures. As distinct from steam systems, gas turbine bottoming cycles would require pressurized MCFC operation, which was not favored because of cost, mechanical, and cathode corrosion considerations. At 30 atma operating pressure, 10 tons of stainless steel per MW would be required for the pressure vessel alone.616 Denmark: Up&ted information on the Haldor TopsBe heat exchange reformer has already been given in Section 25 in the description of PAFC progress in Japan (c.f., Refs. 163, 164). The unit could operate on NG, naphtha, and kerosene, with appropriate modifications. The 1.25 MW demonstration unit with 7 concentric reformer and a central burner operated for 4,200 hours over two years. It used counter-current flow to that of the burner exhaust in the Fist catalyst bed adjacent to the burner, and co-current. flow in the second bed, in the half of each tube away from the burner. 617 A kerosene-reforming unit had been installed in the 200 kW (nominal) PAFC at the Nippon Refining Co.,92 and a NG unit was supplied in 1991 for the ENEA/AEM 1 MW PRODE PAFC in Milan. A unit was supplied to Japan for the Fuji Electric 5 MW demonstrator, and a 100 kW unit was supplied to IHI for an external reforming MCFC

626

A. J. Appleby

demonstration. A small pm-converter unit was to be delivered for an MCFC demonstration at Elkraft in Denmark for a system including internal reforming, which would include testing of appropriate catalysts.617 In 1992, it was reported that the system could be scaled up to include the power range from 100 kW to 30 MW, and that it could be operated on fuels as heavy as kerosene. The tube wall temperatute was relatively low (900°C), and the down-flow catalyst bed was stable. operation of the 1 MW Concept-3 pilot plant was started in Houston on June 30, 1992, and 1,280 hours had been acquired by September 11, 1992. The unit was tested on NG at loads between 30% and 105% of nominal maximum, at steam-tocarbon ratios between 2.5 and 3.5. Umeacted methane was less than 2% at inlet pressures of 6.7 atma (pressure drop, 0.42 atm), at an inlet temperature of 469Y!, and an outlet temperature of 575’C. The burner operated at 1.5 atma (4.5 atma inlet) and 1,300°C, with an outlet temperature of 52O’C.tu Sweden: Studies of a 1 MW MCFC cogeneration plant with external reforming and anodic and cathodic gas recycle have been conducted at Vattenfall in collaboration with Kinetics Technology International (KTD.618 Different system software was used by each company for verification purposes. The TurboPascal code used was SPENCE (Simulation of Processes for ENergy Conversion and Electricity production) developed by KEMA in the Netherlands. The system would use a Haldor Topsoe pressurized heat-exchange reformer with a steam-carbon ratio in the 2.5 to 3 range operated on anode loop off-gas. Reformer off-gas went to the cathode loop. The stack was process cathode-gas-cooled and operated under unstated pressurization conditions. Air pressurization for the fuel cell and reformer used a compressor driven by an expander using the cathode loop off-gas. This was followed by a heat-exchanger to raise steam for district heating. Fuel utilization in the 70-80% range was assumed. No efficiencies were given. A system in the 10 MW class was also being examined.618 A Swedish market study for cogeneration plants for small and large district heating plants (0.3 - 2.5 MWu, and 2.5 - 25 MWth respectively) and small and large municipal plants (2 - 100 MWu, and ~100 MWu,) was being conducted, and sensitivity analyses for fuel cell and conventional plants in the 10 MWu, range were being compared. It appeared that the market entry of fuel cells over the next decade would be favored if electricity and fuel cost escalation at 3% and 1% per annum, respectively, occurred. Because of the high quality waste heat produced by the high temperature FCs, their capital cost could be higher than that of the PAFC, about $1,46O/kWe versus $1,040-$1,14O/kWe (1995).6** United Kingdom: Rolls-Royce and Associates, Ltd. has described a design for a pressurized (3 atma) 50 kW NG proton-exchange-membrane (PEMFC) system. This would operate at 80% fuel utilization, the anode off-gas being used to supply a 19.8% (LHV) efficient 5 kW Brayton cycle cathode feedstock compressor. The electrical-to-thermal energy balance indicated a fuel cell voltage of 0.75 V. Because tbe CSA would operate at 90°C, all steam (steam-to-carbon ratio 3 : 1) would be raised by burning NG. The catalytic combustor providing the enthalpy of steam-raising and reforming would require 38.5% of the NG feedstock. A total of 55.3% of its thermal output would be used in the reformer, with 30.7% in the feedwaterpreheater (2.6%) and steam boiler (28.1%). This would result in a gross dc LHV efficiency of 34.2%. The gross ac efficiency after the 95% efficient inverter was 32.58, and the net ac LHV efficiency would be 30.5% after parasitic electrical power requirements were accounted for. These included a fuel compressor, heat-dump blowers, and the requirements for a hydrogen separator to supply hydrogen storage for peaking and start-up. The system cost was expected to be $1,65O/kWe (mid-1995, at the trading exchange rate). A number of variations on the system were discussed. The HHV efficiency of the reformer described (including steam requirements) was 74.7%. This figure was the HHV of the total feedstock compared with the HHV of the shifted FC anode stream before partial oxidation to reduce CO to acceptable levels. Of the total losses, 12.1% was useful process heat (200’-45O’C) which could have been used to raise steam for reforming. Its use could have raised the reformer HHV efficiency to 83.0%, and the overall LHV ac efficiency to 34.0%. The most important improvement to the system would be an integrated autothermal reformer with a higher efficiency. A 30 kW integrated fuel processing system was tested, consisting of an autothennal reformer incorporating steam-raising and shift conversion in a “black box” configuration in which water, NG or propane, and air enter. Reformate with a low CO content was the product. The exit gas contained 2,000 ppmv CO at 25-30 kW equivalent output, and 1,500 ppmv at 15 kW. The complete prototype unit operated at 91% HI-IVefficiency (feedstock in compared with heating value of reformate out, including the heat required to raise steam). The system had a specific volume of 6 liter/kW, about twice the desirable value for use in transportation applications. The unit required a 15 minute heat-up period from a cold start. A second Mark-2 prototype was expected to operate in mid-1994.6*s Improving the system efficiency by eliminating external piping and heat-exchangers and lowering the cost by reducing weight and volume follow the expectations set out in Ref. 48. A 50 kW (net ac) PEMFC power plant* stack was projected to cost $900-$1,8OO/kWein 15 MW batches. The stack and power conditioner would each be 20% of this cost. The target stack materials cost was $50/kWe.‘j19 A plant operating at 0.75 V using the 91% HHV efficiency reformer could have a net LHV ac efficiency of 37.3%. In a further possible approach, the use of anode off-gas to supply the burner of a conventional reformer in a * Lie Rolls-Royce and Associates, Ballard Power Systems (Vancouver, BC), is also proposing a NG-powered PEM on-site system. Obtaining the required efficiency will be a challenge, since unlike the PAFC, the PEM cannot raise steam for refming. Further details are discussed in the Conclusions section of this Review.

Fuelcell technology

621

non-pressurized system could result in a net ac LHV efficiency of about 43% at 0.75 V, or 37% at 0.65 V. All waste heat from these plants would be 70°C hot water.

Chiyoda Corporation (Yokohama): Work has been described on the development of a hybrid combustor for a reformer in which heat of reaction was supplied by burning the dilute anode gas exit stream from an MCFC operating at high utilization in a catalytic combustor operating at about 8OO’C. This is followed by an afterburner operating at 12004Con fresh fuel. To reduce N@ and to eliminate flame-outs in this post-combustor, a ceramic regenerator core was used., e.g., Si-impregnated SIC honeycomb.‘jse This reformer was one of the two in competition fm use in the 1 MW MCFC demonstrator, for which the Hitachi catalytic combustion reformer was finally selected. 312 The 1 MW Chiyoda heat-exchange reformer operated for 941 hours from July 5 to September 9.1993 at Akagi 3s at a steam-to-carbon ratio of 3 : 1. It exceeded the specifications for hydrocarbon conversion (96.6%. 95% required), gas production; ramp rate (27.7% per minute, >25%); cold start time (3.33 h. ~3.5 h); hot start time (1.83 h, 4.0 h), and NO2 production at 4% 02 (2.5 ppmv, ~10 ppmv). No refractory cracking or metal part damage was apparent on tear-down, but some catalyst bed cracking was observed due to the effects of thermal shock.621 CRIEPI (Yokosuka-shi, Kanagawa): Designs of external reforming LNG MCFC power plants in the 20 MW class for dispersed generation, and in the 50 MW class for central station use have been described. Both have a turbine to use some waste heat, which produces a small percentage of total power. The LHV efficiencies would be 55.6% (80.6% including cogenerated heat) and 60.5% respectively for the best set of operating conditions. Five different sets of conditions were explored, namely (1), 0.15 A/err?, 1 atma, 55O’C MCFC inlet temperature; (2) 0.15 A/cm2,3 atma, 6OO’C;(3) 0.15 A/cmz, 1 atma, 6OOY; (4) 0.20 A/cm2, 1 atma, 6OO’C;and (5) 0.30 A/cm2, 1 atma, 6OO’C. For the first system, (3) gave the highest LHV efficiency at 55.6%. and (5) the lowest at 53.3%. For the second system, the corresponding figures were 60.5% for (1), (3) and (4), with a lowest efficiency of 53.5% for (5). These results are interesting, since they show that there may be no penalty for atmospheric pressure operation in systems using turbines.622 National Chemical Laboratory for Industry (Tsukuba, Ibaraki): The waste heat from an SOFC fuel cell has been examined to provide the heat of reaction in a coal gasifier in a concept called the “electrochemical coal gasifier.” It can also be extended to other fuels. It recommends the development of an anode which can directly oxidize carbon,623but a gasifier operating on steam and oxygen at 1000°C would :notrequire such a system. However, it would require an anode which is highly impurity-resistant, and which may not exist today.

NlT (Interdisciplinary Research Laboratories, Musashino-shi, Tokyo): Nm has examined the use of a PAFC uninterruptible power source supplied by a reformer containing 12 wt % Ni on Al2O3 catalyst which can use either NG or alternative fuels (e.g., propane). Satisfactory results were obtained iina system intended to deliver reformate of constant heating value.6” Osaka Gus Co., Ltd.: Computer simulations of SOFC systems have been conducted, but few details were available in early work.‘j25 In 1994, information was provided on an advanced desulfurization process with low hydrogen requirements and an advanced steam-reforming process. These were described at the end of Section 25 (Refs. 165,166). Tokyo Gas has developed a similar desulfurization process with low hydrogen requirements, which is being used by MC-Power in the United States.rw 29. CONCLUSIONS 1985-1995 Overview Technology: The materials technology of fuel cell stacks and future directions for research in this field were last reviewed in this journal in 1986 as the report of the first Advanced Fuel Cell Working Group (on Research Needs for Fuel Cells).626 This report contained separate papers on research recommendations for the phosphoric acid fuel cell (PAFC),s alkaline fuel cell (AFC),627 solid polymer or proton exchange membrane fuel cell (PEMFC),62* molten carbonate fuel cell (MCFC),dr and solid oxide fuel cell (SOFC).629 Potential fuel cell markets and costs were only considered for the most advanced 1985 technology, the phosphoric acid fuel cell (PAFC) operating in pressurized electric utility applications. The most urgent research need for the PAFC was to ensure and demonstrate its durability. Since that time, this has been effectively demonstrated in atmospheric pressure applications, as well as under more aggressive pressurized conditions. Major changes have occurred since 1986 in the consideration of what were then called “advanced’ or “later generation” fuel cells for utility applications, especially in the United States and Europe. These included the MCFC and the SOFC. A decade ago these were still on the laboratory bench, in the form of

628

A. J. Appleby

small-area MCFC short stacks and small-scale SOFC tube bundles. The fiit 2 MW MCFC demonstrator is now about to operate in the United States, and a 1 MW unit is soon expected in Japan. Progress in the SOFC field has also been extraordinarily fertile, especially from the viewpoint of the wide range of technological approaches used by a large number of offshore developers. In the PEMFC, the recommendations of the report have been largely fulfilled, resulting in spectacular improvement in platinum catalyst utilization and stack power density. The extent of these is indicated by the fact that the PEMFC is now considered by the major U.S., European, and Japanese car manufacturers to be a probable technology for advanced hybrid electric vehicles. Only the alkaline fuel cell, a mature technology in 1986 for space and defense applications, appears to have made little progress. This review* attempts to detail the progress ma& in the area of PAFC, MCFC, and SOFC fuel cells for stationary generation applications since 19861988, i.e., since the reviews in Refs. 6 and 625. This was incompletely covered in the second Advanced Working Group Report (on Commercialization, Ref. 83 a, b). It may therefore be used as background information for this Report. It complements another review on the recent historical development of commercial issues and probable costs, particularly those of PAFC technology.110 This concluding section also briefly considers the prospects of the NG-reformate PEMFC for stationary applications. Commercialization Issues: In 1993, the Office of Science and Technology (Office of Program Analysis, Research and Technical Assessment Division) of the Department of Energy commissioned the Advanced Fuel Cell Commercialization Working Group to examine the necessary strategies which required implementation to successfully commercialize the stationary fuel cell technologies then being supported by the Department. These were the MCFC (two developers) and the SOFC (one developer), and their necessary balance-of-plant. The Working Group took a broader view of the question, and attempted to put these into the context of the development of other technologies (the PAFC and PEMFC) in the United States and in the rest of the world, particularly in Japan and in the European Union. Commercialization strategies and problems were examined for all technologies, and for both stationary and mobile (traction) applications. The report of the Working GroupaQ*bexamined the developer’s experience in surmounting the problems of the precommercialization stages of the prepackaged 200 kW on-site IFC-ONSI PC25TMPAFC, and how such experience might be used to speed the acceptance of the HTFC technologies. Some of the problems of commercialization of the PEMFC for traction applications were also considered. About 40% of the report was devoted to technical improvements to technology which would make it more commercially attractive, including the ever-present problems of cost reduction.

The PAFC Prospects: After 1986-88, U.S. electric utilities felt that the pressurized phosphoric acid system had failed in two important respects: capital cost and efficiency. These factors were considered more important than dispersibility and low emissions. In contrast, 200 kW on-site PAFC systems operating on natural gas, together with a wider range of sizes developed in Japan, may very rapidly become a commercial proposition for small dispersed cogeneration applications in the United States, Europe, and Japan. They can supply electricity at an average lifetime 40% LHV efficiency with a technically-guaranteed performance over CSA lifetime of 40,ooO hours. This lifetime is expected to increase to >6O,OOO hours as electrolyte make-up systems are developed or improved. Performance very close to the stage of being commercially guaranteed for the IFC-ONSI PC25, which has a l-year warranty at present, with the option of purchase of an extended warranty. At nominal stack end-of-life, a customer will have the option to purchase and install a new stack whose performance and lifetime will exceed that of today’s, or to eventually refurbish the old stack at low cost by replenishing the electrolyte inventory. This would involve taking a small efficiency penalty until the next nominal replacement interval. There is no reason to doubt that the BOP will have an effective lifetime equal to several nominal stack replacement intervals, e.g., 30 years. PC25 units operating today are demonstrating that minimal maintenance at one-year intervals is required, and that close to 100% availability between maintenance intervals can be expected. Present IFC-ONSI units can supply up to 50% of the heat content of the fuel as hot water. Future units with system modifications, and certain Japanese prepackaged PAFCs, will be able to supply about 15% of this heat as 170°C steam for absorption chiller air conditioning systems if desired, and 30% as hot water. Finally, this dispersible PAFC generating technology has NO;! emissions of much less than 10 g/MWh, or more than 15 times better than the best GTCC technology, which is in turn mom than 10 times better than conventional coal systems. This advantage of the PAFC will remain even as GT technology advances, since the latter is now close to its theoretical limits in this regard. Other emissions from the PAFC (CO, reactive organic gases) may be classified as negligible and undetectable, respectively. State-of-the-art Otto-cycle internal combustion engines with catalytic converters have N@ emissions exceeding 1,000 g/MWh, and diesel engine N& emissions considerably exceed this figure. In all countries, PAFC emissions are far lower than legislations require for on-site cogeneration

??This reviewand Ref. 110 represents the views of rhe author, and not those of the Advanced Fuel Cell Commericalization Working Group.

Fuel cell technology

629

equipment. Now that such best-available technology exists, legislators might seek an opportunity to

encourage its use for on-site cogeneration and uninterruptible power applications. A discussion of PAFCs for premium power applications at AT&T Bell Labs, Crawford Hill, NJ, points out that even at $2,000 per kW after government “buy down,” and in spite of their modest fuel consumption, these systems will still produce power at costs which are 20% higher than grid power, and 40% higher than the 5-6e/kWh which is expected to be offered to medium-load customers under the “retail wheeling” scenario. For many applications, facility-dedicated benefits other than simply cogeneration of hot water required identification and quantification. The report concluded that the fuel cell should not be purchased to provide low-cost electricity, but to offer a high-value continuous electrical service.630 A study by Arthur D. Little, Inc.631predicted a general fuel cell market in commercial buildings of 125 to >250 MW per year if the cost did not exceed $1,5OO/kW(1995). With utility Integrated Resource Planning (IRP) benefits (i.e., transmission and distribution, environmental, etc.), the market could increase considerably. At $l,OOO/kW(1995) with IRP benefits, the market could be 250-1,000 MW per year. Even at this capital cost, 40% or greater LHV efficiencies would be required, and fuel cells would only compete in ordinary applications only in regions of the country with high electricity rates. The payback time would always be less for hospitals and hotels than for office or retail buildings. It was important that O&M costs for fuel cells would be no more than 0.02 e/kWh, about the mean for IC engines under 200 kW. The major part of O&M would be the cost of stack replacement at 40,000 hours (about 0.009 e/kWh at a stack cost of $35O/kW). The remaining allowance corresponds to $14,000 (about 4.6% of the total $1,5OO/kWcost of a commercial unit) in annual maintenance costs per PC25. This is calculated at 75% load factor and 95% availability. This figure should be achievable if only one annual outage is planned. A reduction in O&M costs to 0.01 @/kWhby a combination of longer stack life and lower non-stack maintenance requirements would double the potential market at any given capital cost. Another discussion of the role of fuel cells in distributed generation 6~ indicates that since the Public Utilities Regulatory Policy Act (PURPA) of 1978, non-utility generators (NUPs) or independent power producers (IPPs) selling electricity at the avoided cost to utilities, represented 46% of new generating capacity in 1990, a figure which would reach 64% by 2000. The Energy Policy Act of 1992 permitted wholesale retail wheeling of electricity within the regional power grid under regulations to be established by the state public utility commissions. By early 1995, nine states had agreed to allow retail wheeling. Independents with low-cost equipment (mostly gas turbines) will then compete with high-cost utilities. Whether the latter could add transmission charges to wheeling rates had yet to be determined by the Federal Courts. Distributed generating technologies (either IPP or utility) could provide customers with better service to compete with wheeled power. Distributed technologies include gas turbines, IC engines, fuel cells, photovoltaic cells, and wind power. The financial benefits of distributed power include transmission and distribution (T&D) credits, credits for release of existing T&D capacity for other use, for the marginal cost of installing new capacity, for reduction of reserve margin, and for provision of customer standby power. Operational savings include reduced energy losses, and cogenerated heat. Finally, strategic benefits include improved reliability, reduced investment exposure, improved customer relations, and stabilization of fuel supply costs by the use of diversified generation technology. These have been quantified by the Electric Power Research Institute.633 Negative aspects of distributed generation may include reduced power quality resulting from the use of low-quality inverters, which would increase cost at all levels, and result in problems in the event of substation outages. First, isolated distributed generators will then attempt to serve the whole disconnected area. If they succeed in maintaining voltage and frequency to specifications, they and the grid may not synchronize when reconnection occurs. This will result in damage to equipment. Techniques were, however available to address these problems. Finally, if customers convert from utility-supplied power to independent on-site power, its fixed costs would become a burden on fewer customers, causing delivered electricity costs to rise, whether the power is from the local region or from remote generation capacity.Qs This will be the environment in which the on-site PAFC, or any other fuel cell technology, must compete. The cost of its power after credits for other services it furnishes would be the key to its widespread use. This equation reduces to the lowest possible capital and O&M costs at an attractive efficiency. Japan and Europe: In contrast to the change of view of U.S. electric utilities, in Japan there is even more interest in the PAFC for electric utility applications than there was ten years ago. There is also great interest in its application for on-site use. A 1990 MIT1 report entitled Long Term Energy Supply and Demand Prospecrs predicted a capacity of 1.05 GW of fuel cells, largely PAFCs, for electric utility use by 2000, and 5.5 GW in 2010. The corresponding capacity for private (on-site) units was predicted to be 1.2 GW and 5.2 GW respectively.3s The total market estimated by MIT1 was about 10% of the potential market for larger FCs estimated (using different assumptions) by AIST-NEDGJS In addition, the Japanese Government supported the PAFC by offering up to one-third of the cost of installation, even for units of foreign origins7 This has been essentially copied in the United States, though only for the PC25C. In late 1995, it appeared to be too late to see these Japanese predictions fulfilled by the targeted times, which would have to be pushed back by at least five years. Part of the problem is the fact that capital cost is still too high, because production has been limited. This was in turn because practical preprototypes, which could be mass-manufactured at economic costs, remained to have their performance convincingly proven. However, capital cost is less of a problem in a Japanese context than it is in the United States, even at a Purchasing Power Parity (PPP) exchange rate of Yl50 per dollar, which is about 50% greater than the late-

630

A. J. Appleby

1995 trading exchange rate. In the Japanese context, $2,500 per kW (1995, calculated at the trading exchange rate) will be competitive for on-site applications. The corresponding figure for the United States and Europe is closer to $1,500 (1995) per kW. In Europe, the target cost (calculated assuming trading exchange rates) is about the same as in the United States. The on-site PAFC is considered to be attractive, provided that target costs are reached. If capital and O&M costs can be controlled by good &sign, and if innovations such as new fuel cell and small turbine combined cycles can be developed,~2~13~61a~6*l the PAFC is assured of a promising future. The On-Site PEMFC Introduction: Although it was not intended to give an overview of the technical status of the PEMFC in this review, it is of interest to consider its future cost because of present interest in using it for on-site and traction systems.61*@4-636 Fuel cells generators for stationary applications may be commercially successful if their capital costs are under $1,5OO/kWand if their component degradation and lifetimes were satisfactory. On the other hand, PEMFCs for traction applications would have to compete with internal combustion engines. This would requite costs on the order of $5O/kWor less for light vehicle applications, and $lOO/kW for heavy vehicles. The contrast between the cost requirements for stationary and traction applications does not imply that one might be achieved, but not the other. A PAFC stack represents less than 10% of the weight of a PAFC on-site system, and is considerably heavier and less compact on a per kW basis than a PEMFC stack designed for vehicle applications. Ballard Power Systems (North Vancouver, BC) recently announced637the successive improvement of the specific power in (pressurized, 2-3 atma) PEMFC stacks from 150 W/liter in 1992-93 to 300 W/liter in 1994, and to 1.0 kW/liter (ti.7 kW/kg) in 1995. The improvements were also associated with an increase in stack efficiency, the gross cell voltage before correction for pressurization work having increased from 0.58 V to 0.68 V. New product water management techniques have also greatly increased the peak power density, e.g., 0.55 V.a8@’ The first-generation stacks were used in the small hydrogen-powered bus demonstrator in 1993, the second in the full-sized bus in 1994-1995, while the third has been developed for future vehicle applications in conjunction with Daimler-Benz AG. PEMFC Stack Performance and Costs: Operating under pressure at 0.68 V, the specific power of the Ballard stack (in W/cm2) is perhaps 2.5 times greater than that of the PC25 PAFC, and its power density (W/kg) is about 6 times greater. The weight per unit area of its cell components is therefore about 2.5 times less than that of the PAFC. The area of the Ballard cell is considerably less than 10% of that of the PAFC cell. At constant current density and pressure drop, this would reduce the height of flow channels by approximately 3.5 for the same flow geometry. However, the Ballard system operates at higher current density, but under pressurized conditions, whose effects on channel height tend to cancel out. Its flow pattern is also more tortuous than the straight-through pattern in the PAFC, which requites a higher pressure drop. In general, stacks with small cells intended for vehicle applications can be made with bipolar gasflow plates which are considerably lighter per unit area than those for stationary power applications. PEMFCs operate at less than 100°C. and their plates can be constructed from cheaper and less robust materials than the thicker pure graphite separators and large gas channels required for the PAFC. The thin plates will allow the use of graphite-plastic composites, since specific conductivity is a lesser consideration, and only pure product water contacts the plate, not corrosive electrolyte. It estimated that a PAFC stack can be manufactured for $3OO/kW,of which $6O/kW is platinum catalyst, and in which the heaviest solid component is 3-4 kg/kW of graphite. It is not unreasonable to suppose that lightweight PEMFC stack repeat parts (without catalyst and polymer electrolyte) can be manufactured for less than $4O/kW. The higher power density will give a platinum cost of less than $25/kW at the same loadings as those used in a PAFC, which recent work has shown may be reduced by a factor of at least 3, and possibly as high as lO.rrO The future problem may lie in the cost of the PEM electrolyte, which today costs $150-$6OOikW depending on the supplier and the proposed power density. This must be greatly reduced in cost if the PEMFC is to see wide applications, especially in the transportation field. These will require calendar lifetimes of at least 5 years, during which total operating lifetimes are only 3,000-15,000 hours, compared with 40,000 for stationary applications. These may be achieved using PEM materials with simpler and less costly chemistry.rrs For vehicle applications, the fuel may be hydrogen prepared from e.g., natural gas, and carried aboard the vehicle, or methanol from the same source, with an on-board methanol reformer. The latter will be much smaller, lighter and less costly than the system required for on site-NG applications. Combined with a pressure-swing absorption system, the reformer which will be mass-produced for the 200 kW PAFC will be ideal to supply hydrogen at a service-station level for hydrogen-powered PEMFC vehicles. Assuming a vehicle built to Partnership for a New Generation of Vehicles (PNGV) standards (one-third of current energy consumption, i.e., 0.42 kWhta/mile), the N@ emissions from the lean burner of this reformer correspond to 0.0005 grams per mile, almost three orders of magnitude below present legal requirements. Emissions of CO would be at similar levels, with reactive organic gas emissions below the level of detection. IFC-GNSI appears to show recent interest in using the PAFC reformer in this application.

Fuel cell technology

631

PEMFC On-Site System: The studies given in Ref. 619 show that a 3 atma PEMFC system operating at 0.75 V on NG feedstock can achieve an LHV efficiency of 30.5% with 12% of cogenerated heat as steam and about 34% as hot water in a non-integrated unit. In a unit producing no steam, the LHV efficiency could be 34.5% at 0.75 V, and 29.6% at 0.65 V. This could rise to an LHV efficiency of 37% in a 3 atma system, 0.75 V with a highly integrated fuel processor, or 37% in a 1 atma system operating at 0.65 V (43% at 0.75 V). Both of these could produce about 41% co-generated heat in the form of hot water. Thus, there would be a loss of only 3 percentage points in an integrated 1 atma system compared with a PAFC operating under similar conditions. On-site PEMFC systems may be attractive for small applications, e.g., as cogeneration systems in buildings. 640 Ballard Power Systems and the Dow Chemical Company (Midland, MI, a PEM electrolyte developer) had developed a 10 kW proof-of-concept reformed NG prepackaged PEMFC unit for such applications in 1994.=m This was intended as a subscale prototype of a 250 kW market entry generator. The first 10 kW plant was installed in a Dow facility in Freeport, TX, and other plants were being reportedly manufactured at Dow’s Russellville, AR plant. Work had started on the construction of a 250 kW preprotoype, expected in mid-1995 to be ready by 1998.** Later in 1995, Dow Chemical decided that this product did not fit into its commercial product line-up, but Ballard was reportedly continuing the development of this and other NG PEMFC units. The durability of the PEMFC is not in question. The market will be determined by the capital cost of PEMFC on-site systems.

The MCFC Introduction: Electric utility interest in the PAFC in the United States has been replaced by interest in the NG-fueled MCFC since 1988. In Japan, the development of practical MCFC plants was expected by 2000, with installation of large units expected by 2010. In the United States, Energy Research Corporation (ERC) and International Fuel Cells (IFC) were planning externally manifolded stack &signs with 0.8 m2 area. ERC was using 0.56 m2 CSAs in the Santa Clara, CA 2 MW demonstrator. The area of the MCPower internally-manifolded stack was 1.0 m2. In Europe, the ECN-BCN internally manifolded stack also used 1.0 m2. Ansaldo srl (Italy) has licensed externally-manifolded IFC technology, and DASA in Germany will use licensed ERC technology. In Japan, Ishikawajima-Harima Heavy Industries (IHI) and Hitachi were developing and testing internally-manifolded stacks with areas of approximately .l.Om2, the latter using a four-piece window configuration. Toshiba was planning large externally-manifolded stacks partly based on IFC experience. The Mitsubishi Elecnic Company (MELCG, 0.5 m2 area cells) and Sanyo (0.24 m2) were developing and testing externally-manifolded stacks based on licensed ERC technology. MCFC Endurance Issues: Certain MCFC endurance issues are still unclear, and will remain so until long-term tests (or accelerated life-tests) are conducted. Life-limiting factors are still disputed, as the discussion given in the Netherlands subsection of Section 26 indicates. According to Ref. 239, the lithiated nickel oxide cathode lifetime (time to shorting out by nickel dendrites) is 25,000 hours at a total pressure of 1 atma (at 0.3 atma COz), and 6.000 hours at 4 atma (at 1.2 atma C@). Similarly, at both 1 atma and 4 atma, evaporative loss of electrolyte (as hydroxide) was said to limit life to 6,000 to 10,000 hours, and spalling of the nickel cladding on the anode side of the Avesta stainless steel bipolar plate (25 : 20 : 0 : 5 Ni/Cr/Mn/Mo, some Cu) was said to occur in less than 10,000 hours. The spalling was due to water formation at the stainless steel oxide layer. These observations, obtained with reference gases under representative co-flow gas outlet temperature of 700°C, seem to have effectively put demonstration plans in the Netherlands on hold. This is being carefully observed by other European organizations. There is no reason to doubt the conclusions of the Netherlands work. The question is whether they will apply to all MCFC stacks using similar materials. The two U.S. developers (ERC and MC-Power with IGT) have performed long runs (up to 11,000 hours) on representative cells and stacks, as has MELCG in Japan. Both ERC and MELCO have operated under similar conditions using internal reforming. The latest relatively long-term (4,000 hours) test of a full-area ERC stack operating on coal gas”7 showed all parts in good condition, with no unusual loss of electrolyte. This stack was representative of expected performance in the 2 MW Santa Clara demonstrator. In the latter, the cathode gas contains 15.7% CO2 at the entry, and 4.8% at the exit, with a mean of 10.8%. The experiments in the Netherlands were conducted at 30% C@ (cathode entry), 27.7% (exit), and 28.9% (mean).= Since cathode dissolution is proportional to pCG2, the ERC cathode would ‘beexpected to last for about 50,000 hours at the entry, and 140,000 hours at the exit, based on the lifetime given in Ref. 239. Under ERC’s 1 atma operating conditions, with a lower exit temperature than that expected in the Netherlands because of the use of special internal-reforming geometry, a 40,000 hour cathode life may certainly be expected. Under the 3 atma operating conditions favored by MC-Power, the result may be more problematical, but the use of additives and alternative electrolyte composition@* should allow for a 40,000 cathode lifetime. Comments under Refs. 345b (Toshiba) and 35 1 (Matsushita Electric Industrial Company), above, should also be noted. The second life-limiting problem, alkali metal ion loss by evaporation of hydroxide. involves some more complex issues. If we assume that under Netherlands (ECN) test conditions, the anode exit (9.9%

632

A. J. Appleby

Hz, 39.4% CO2, 50.7% H20 before shifting) lost 6% of Li+ and 20% of K+ over 5,000 hours at 1 atma,zjs we can use some-mechanistic assumptions to estimate their losses as hydroxide under other operating conditions. At constant pressure, the loss will be proportional to some function of gas composition. and to the molar throughput at each electrode per hydrogen molecule oxidized. The hydroxide loss strongly depends on the cell exit temperature. Reducing this to the lowest possible value will result in longer life. In the ERC case, the cell hot-spot is at 675OCand the anode and cathode gases exit at 639OCand 664OC. This results from the use of special IIR geometry. ttr4b In contrast, the hot-spot and the anode and cathode exit temperatures am all at 700°C in the ECN co-flow cell. If one assumes equilibrium between CO2, Hz0 and K2CO3 via K20, evaporative loss will be proportional to (pH2O/pCO$5. The anode gas composition in the Netherlands tests contained more water than in the ERC case. It started as synthetic NG reformate at 30% humidification, compared with ERCs reformate with an initial steam-to-carbon ratio of 2.5 : 1. After allowing for the total number of moles of gas exiting per mole of hydrogen consumed, and correcting for the exit composition after water gas shifting, ERC’s hydroxide loss (at 1 atma) should be about 72% of that in the ECN tests at constant temperature tf the above equilibrium applies. In the Netherlands tests, a dry cathode gas was used, so no hydroxide loss would be expected. The system gases at the ERC cathode exit with the composition 4.8% COz, 21.4% H20, so that the ratio of the @H20/pC0@5 terms at the cathode and anode exits is 2.05. The moles of reactant exiting per mole of HZ oxidized are 7.0 at the ERC cathode exit (67% N2), compared with 2.83 at the anode exit. Thus, under conditions of constant temperature, the rate of loss at the ERC cathode should be 5.1 times higher than that at the anode, giving a total anode plus cathode loss 4.4 times higher than that under ECN conditions at constant exit temperature. However, the difference in the anode gas exit temperatures may make an almost three-fold difference in anode losses in the ECN and ERC cases, and the cathode exit temperature can mean a factor of two difference, under equal conditions of saturation. Even so, this corresponds to an overall anode plus cathode evaporation rate under ERC conditions equal to about 2.1 times the losses reported by ECN at their anode. It also suggests that a complete loss of K+ inventory under ERC conditions should take place over 12,000 hours, almost 90% of which would be from the cathode. Any evaporation approaching the above magnitude would be obvious. Such losses have never been observed. The interesting results on active evaporation under a simulation close to practical conditions obtained at the Mitsubishi Electric Company291292 may throw some further light on the problem. These were intended to explore the rate at which volatile phases might accumulate on a DIR catalyst. The design of the experiment included any effects resulting from lack of saturation of the gas stream. The data showed good agreement with loss as hydroxide, proportional to (pHzO/pCOz) 0.5. At 650°C, approximately the mean temperature of ERC’s anode and cathode exit streams, results suggested that 0.81 mg/cm2 per 1,000 hours would be lost from an anode stream operating at 75% fuel utilization at 0.16 A/cm2 with the pH~O/pC02 ratio normalized to 2.85 at 65OOC.After correction for the appropriate (pH20/pCO#5 values and for the lower exit temperature of the ERC cell compared with the isothermal MELCO experiment, this suggests an anode loss rate under ERC exit conditions of about 0.4 mg/cm2 per 1,000 hours at 0.16 A/cm2 at this fuel utilization. The total anode plus cathode loss rate would be about 3.0 mg/cm2 per 1,000 hours. This loss (120 mg/cm2 over 40,000 hours) is still quite high, but is still much less than that suggested by the ECN anode results (about 100 mg/cm2 over 5,ooO hours). We might possibly account for this discrepancy by suggesting that the kinetics of reaction between C@ and O= product in the cathode reaction are slow at the gas-electrolyte interface. This hypothesis is used to explain the observed oxygen electrode reaction orders (c.f., Ref. 41). The loss of hydroxide might then be more or less independent of pm, and be proportional to (pH20) 0.5. In this case, the total loss from anode and cathode at ERC should be about the same as that in the ECN tests. Even this has not be observed. The most probable explanation of the difference between these results is the fact that ERC’s stacks have a very small cell area (about 4%) over 675’C,rab compared with almost 50% in the ECN cells.2’t’JThis may be expected to make a dramatic difference in vapor losses in the two cases (see Section 27). Only 30% of the ERC stack area was over the temperature of the MELCO isothermal test. If this test represents the upper limit of evaporative loss at 650°C, then it would not be surprising if the total loss in the ERC case was closer to 40% of that in the MELCO case, i.e., about 50 mg/cm2 over 40,000 hours. We also should note that the anode exit gas is burned in the ERC system, then is supplied to the cathode. This will help reduce some of the cathode losses. If electrolyte evaporation losses indeed depend on (pH20/pC02)u*5 (as the MELCO results291f292 suggest) then the hydroxide vapor pressure is independent of operating pressure under the same gas composition conditions. However, the total inventory loss decreases with gas volume throughput, i.e., it is inversely proportional to operating pressure If the hydroxide vapor pressure depends on (pHzO)o*5,it increases with operating pressure. However, this proportionately reduces the gas volume throughput, so inventory loss will be independent of operating pressure if this mechanism applies. The real dependence is unknown, and no studies have been performed (except by inference) on electrolyte loss by evaporation in a humidified, lean a system cathode gas environment. Such measurements are overdue. The US developers can provide convincing arguments that evaporation of electrolyte will not limit a 40,000 hour life under their operating conditions. We should also note that the substitution of Na+ for K+

Fuel cell technology

633

will result in longer life, since the hydroxide vapor pressure will then be lower.*** IGT has developed larger-pare cathode structures aIlowing better anode filling to give an incmased electrolyte nxem~ir which is expectedto contain sufficient electrolyte for at least 36,000 operating hours.m The final life-limiting factor mentioned in the ECN tests is spalling of nickel on the anode side of the bipolar plate. This has never been seen in U.S. work. Any differences may depend on two factors. The first may be the nature of the oxide film on Avesta stainless steel (composition, 25 : 20 : 0 : 5 Ni/Cr/Mn/Mo, some Cu) compared with that on AISI 316L (lo-14 : 16-18 : 2 : 2-3 Ni/Cr/Mn/Mo). The second may involve the characteristics of the applied nickel film, e.g., its thickness (50 km at ECN), purity, and method of application. At ECN, electroplating has been used to apply the film, whereas hot-rolling has been favored in the United States. Electroplating may result in a porous nickel film, which may be a very hard, high-strength layer with considerable residual stress, containing dissolved or otherwise trapped hydrogen. These aspects of nickel layer application require investigation. A further problem which may limit life of certain MCFC systems is degradation of the DIR catalyst, if applicable. In cells using only DIR, the catalyst may degrade with time to the point of uselessness. However, in cells using IIR combined with DIR (e.g. ERC in the United States, Mitsubishi Electric Company in Japan), the IIR catalyst plates are not used in a recycle system and never come imo contact with electrolyte. Their degradation rate should be very low. The DIR catalyst is likely to be (or to become) strongly kinetically limited as its ages, and the reforming process will eventually be far from equilibrium. However, as Section 6 indicates, a considerable amount of unreacted methane (perhaps up to 10% of the incoming feedstock) can be tolerated in the anode exit stream at 75% overall fuel utilization before a significant decrease in cell voltage (e.g., 8-10%) is observed. If DIR catalyst degradation proves to be a problem, consideration may be given to the use of a small auxiliary reformer following the IIR plates. This could be fueled by some of the anode exit gas, and would require a heat-exchanger. How this might be integrated into a bottoming cycle is described at the end of Section 29. To resolve the above degradation questions, the importance of developing accelerated life-testing procedures is again emphasized. Many degradation phenomena can be accurately studied in the correct anodic and cathodic atmospheres in the absence of current flow, e.g., by using mock-ups with non-working components in tests performed in parallel to the development and testing of working hardware. In practical stacks, the only way to eliminate degradation mechanisms associated with large temperature gradients and high exit temperatures may be via internal reforming, which results in more efficient and simpler systems. MCFC Costs: The level of technical development of the MCFC is still less than that of the PAFC of a decade ago. Knowledge of the ultimate capital cost of MCFC systems is no more advanced than it was for the PAFC at that time. However, the relatively simple BOP required, particularly in 1 atma IIR/DIR systems, should be less costly than the system required in the PAFC. In the latter, it is possible to see how stacks may be manufactured within the cost requirements. This is much less certain for the MCFC. The argument that the MCFC stack (unlike the SOFC) is largely constructed from fairly conventional sheet-metal is two-edged. It means that the materials costs will not have much opportunity for further cost reduction as development and production go down the learning curve. The point raised by ECN and BCN in the Netherlands (Section 27), that the MCFC can scarcely compete if a stack contains 4.0 liters of materials per kW (ca. 25 kg/kW or $3OO/kW)83b*r is well taken. This is based on a power density of about 0.11 W/cm2 in a real system. Most current bipolar plate designs are over-engineered and overweight. One approach is to use stack components allowing an increased power density, which may only be marginally possible (e.g., an increase by 36% from 0.11 W/cm2 to 0.15 W/cmT). Today’s stacks show increasing curvature of the polarization slope as current densities go much beyond 0.15 A/cm2 at 1 atma (Figures 3 and 5). This means that increasing the current density may result in very little increase in power density at the expense of reduced efficiency. However, ERC plans include improvement of power density to 0.16 W/cm2 (0.21 A/cm2 at 0.76 V) by the careful control of internal resistance.rs5 Ref. 83b, p. 403 indicates a Japanese goal of 0.75 V at 0.3 A/cm2 (0.225 W/cmz). This may prove difficult to achieve in practical systems, even those operating under pressurized conditions. The stack materials cost (per kW) appears to require reduction by about a factor of two. The ECN FLEXSEP@ bipolar plate (6 kg/m2, potentially 4 kg/kW at 0.15 W/cmz)u* and the simplified IMHEX@ plate designs at MC-Power’” indicate the direction to be taken. Potentially, the materials costs for bipolar hardware and current collectors (a total of 4 kgikW) should be $5O/kW, and those for nickel components (anode, cathode, nickel plate) about S4O/kW. However, the unpublished Japanese work quoted on p. 410 of Ref. 83b appears to suggest that the finished cost of nickel components (including the anode coating and the electrodes) will be about 10% of stack weight but 60% of total stack cost, whereas the stainless steel plate (about 45% of stack weight) will be only 20% of stack cost. The cost of pressurized tie-down bellows systems should also not be underestimated.

The SOFC Progress: Recent growth in progress in the SOFC field outside of the United Srates, while based on U.S. experience, has been even more striking than MCFC developments. In the United States,

634

A. J. Appleby

each SOFC developer has examined a different technological approach. Westinghouse cells are tubular, with a self-supporting air electrode and an external anode. The tubes were now scaled up to 100 cm overall length, with a further doubling proposed. Ceramatec was examining an externally-manifolded built-up planar technology with a ceramic bipolar plate, scaled up to 100 cm2 area. Babcock and Wilcox was developing a similar technology to that of Ceramatec, with an initial scale-up to 25 cm2. AlliedSignal was examining a co-fired planar monolithic ‘system, which conceptually could either exist in extemallymanifolded cross-flow or internally-manifolded co-flow versions. The objective was the manufacture of complete stacks with a single firing. The 1993 status of this project was testing of 5 cm2 two-cell units. Ztek had a unique design with a 10 cm diameter internally manifolded built-up planar circular stack with a metal bipolar plate. Other known developers (e.g. Technology Management, Inc., TMI) had not published significant details of their proposed systems. However, it was known the TM1 intended to use a metal bipolar plate. Elsewhere, the most remarkable aspect of development work was the number of &sign options being pursued, although no work on true monolithic stacks was reported. Work on new ceramic options was also impressive. Tubular cells of Westinghouse type, fabricated by alternative methods, were being examined by five Japanese developers. These were Fujikura Ltd., the Idemitsu-Kosan Company, Osaka Gas, Saibu Gas (who was also examining tubular cells with an inverted Westinghouse configuration), and TOTO, Ltd. The Tokyo Electric Power Company (TEPCO) and the Tokyo division of Mitsubishi Heavy Industries (MI-II) were examining classical tubular ring cells arranged in series. This technology is obsolescent because of the amount of masking and manipulation required in fabrication, and because of the high IR drop resulting from long current-collection pathways. A unique tubular cell built on a self-supporting electrolyte with an external anode and internal cathode with 63 cm2 active has been examined in a joint Italian-Russian project. Built-up externally-manifolded planar stacks with ceramic bipolar plates (the Ceramatec approach) were being examined in Europe by Energy Center Nederlands (ECN, Petten, LaCaCrGg bipolar plate, 200 cm2 active area); by Domier in Germany (100 cm2); in the Danish DK-SOFC project (20 cm2); and in the Norwegian Statoil project. Similar work was under way or proposed in Australia and New Zealand. Similar systems (twelve designs) were being examined in Japan by ten developers. These were Fuji Electric Company (two designs with ribbed or flat LaCaCQ bipolar plate, 200 cm2, up to 0.25 m2 projected); W (built-up stack with co-fired electrochemical components); Murata Manufacturing Company (a Siemens “windows” approach); Mitsui Engineering and Shipbuilding Company (composite ceramic bipolar plate with inserted LaCaCrOg disks or windows, 100 cm2); the National Chemical Laboratory for Industry (NCLI, the “Train” system with a series fuel supply to several stacks containing cells with a complex ceramic interconnects); NIT (an experimental flattened tube system); Osaka Gas-Murata (a new &sign concept); TEPCG-MHI (Tokyo division: With low-resistance conductors and a flat bipolar plate, 100 cm2); TEPCO-MHI (Kobe division: Mono-block, layer-built, MOLB cell, 225 cm2); Tokyo Gas (25 cm2); and Tonen Corporation (100 cm2). Built-up planar stacks with metallic bipolar plates (the Ztek approach) were being examined by nine international developers. Five were in Japan: the Murata Manufacturing Company (4 x 150 cm2); NGK; NKK Corporation (144 cm2); Sanyo Electric Company (125 cm2); and Tonen Corporation (100 cm2). Four were in Europe: Siemens in Germany (4 x 4 x 25 cm2 active area); ECN in the Netherlands; and Sulrer-Innotek and Bossel in Switzerland. Sulzer-Innotek used a unique built-up planar 20 cm diameter circular cell design which incorporated a ceramic and metal bipolar structure serving as a built-in air preheater. The stack combined external and internal manifolding, and used ceramics technology from Ceramatec and metal parts from ECN. Bossell’s UBOCELL represented another unique Swiss design. It had sheet-metal bipolar current collectors incorporating an internal reforming catalyst, with all sealing on the fuel side. Siemens, ECN, and Murata used internal manifolding, and the electrochemical elements of individual cells in the Murata stack were co-fired. A problem exists in comparing the performance results published by many of the above SOFC developers, since fuel and air utilizations are either low, or often not given at all. The overseas efforts are also remarkable for the innovation of some of the materials work, for example, the use of partially stabilized (80% tetragonal) zirconia (PSZ) as a partial or entire substitute for cubic yttriastabilized zirconia (YSZ), and the use of alternative interconnect ceramics such as La(CaCoFe)CQ. In Japan, the number of operator and developer user groups and trade associations associated with high temperature fuel cells is striking. This suggests that rapid progress towards further development and commercializtion will occur in the near future. The very diversity of the SOFC technology under development world-wide shows that it is a far from mature technology, in spite of the fact that many stacks in the kW class using different approaches have been constructed and operated. However, the many approaches to fabricating working systems suggest that some will be less costly and more practical than others. SOFC Cost Issues: Materials costs for SOFCs have been examined at GRI.381J383The Ref. 383 analysis starts from Bossel’s geometry-performance study of different SOFC configurations.382 The material in Ref. 381 may be updated by assuming that the SOFC is in relatively mature production, and that all ceramic costs have fallen to twice the ultimate value of $3O/kg (the cost of barium titanate today).393

Fuel cell technology

635

The cost of suitable carbonyl nickel powder is increased from $lO/kgssl to a more realistic $15/kg, which in any case makes little difference to the overall matetials cost. The weight of 40% porous AES support tubes with Westinghouse dimensions would be 17.3 kg/m2 of active area. The dimensional assumptions am that wall thickness is equal to 10% of diameter, active area is equal to 75% of overall length, allowing for 10% of the area occupied by the interconnect. Based on a projected LSM cost of $6O/kg (rather than $25O/kg used in Ref. 381). their materials cost .would be $259/kW at 0.2 W/cm2 (0.3 Alcm2.0.68 V, c.f., Fig. 5). Assuming 40% porous. 100 l.trn thick electrodes (Ni-40 wt 8 YSZ and LSM) and a 10 pm thick YSZ electrolyte, the weights of carbonyl nickel powder, YSZ, and LSM would be 0.27 kg/m2, 0.23 kg/m2 (75% contained in the cermet), and 0.33 kg/m2 respectively (including the part under the interconnect). At $15ilcg, $6O/kg, and $6O/kg respectively, these correspond to $2/kW, $7/kW, and $lO/kW ($19/kW total). If the interconnect also costs $6Oikg
636

A. J. Appleby

the use of stainless steel heat exchangers615 and greatly reduce materials allowing low degradation rates over 100,000 hours.

and interdiffusion

problems,

HTFC Svstems Issues The simple-system NG-fueled MCFC promises an efficiency in sizes varying from 250 kW (or even less) to several MW which will approach that of the best 150-200 MW NG GTCC. More complex systems could exceed the efficiency of the large (>150 MW) GTCC. The system has the advantage of offering most of the remaining LHV of the fuel as high-pressure steam, which could be used in a bottoming cycle in large systems, or for double-acting absorption chillers. If widely adopted, it could make an outstanding contribution to the reduction of C@ emissions. It can cut the emissions by about 40% for a comparable mix of on-site electric power and cooling requirements provided by a central GTCC plant, by 55% for a central gas-steam plant, and by about 70% compared with a central coal plant. While Section 17 shows that MCFC-coal gasifier plants are attractive on paper, the issues to be resolved for pressurized MCFC operation make it unlikely that they will be built before several generations of MCFC stacks have been operated over their technical lifetimes. This will give confidence that they will perform as expected, and will allow them to achieve competitive costs. It may well turn out that no practical MCFC stack components am suitable for high-pressure (8 atma) operation for 40,OCOhours. If this should prove to be the case, then the MCFC will probably not be used in integrated gasifier combined cycle systems (IGCCs). Whether the pressurized SOFC is a suitable candidate for these applications remains to be seen. Incorporation of HTFCs in gas turbine bottoming cycles is usually considered to require either a large steam cycle, and therefore a large (pressurized or non-pressurized) HTFC, or a medium-sized turbine bottoming cycle operating with a pressurized HTFC. 6ts Both will require systems of central station size. An MCFC operating at gas turbine combustor pressures is certainly not feasible with today’s technology,6ts and the operation of pressurized SOFC has never been attempted, although it may be feasible with certain designs. However, the SOFC with today’s materials could never operate at the turbine inlet temperature of a high-performance gas turbine (1,260’-1,34O”C, 2,300’-2,450’ F), so that it could never be incorporated in the turbine combustor, as has been suggested.390 An alternative might be the use of the Heron-cycle turbine in relatively small sizes, which would open up some other options.l2,13~610,611 The 1.4 MW Model-l was a two-shaft machine with back-to-back intercooled centrifugal compressors providing a 9 : 1 compression ratio driven by an axial low-pressure turbine. The power and compressor turbines both had an inlet temperature of only 860°C, which is an excellent match for the waste heat of a moderate-temperature SOFC. The 62O’C exhaust heat from the power turbine went to a vertical tube recuperator to heat the compressor air. This temperature is an excellent match for the waste heat from a pressurized (or atmospheric pressure) MCFC. The separate combustors for the compressor and power turbines can be fired by the appropriate amount of heat using the MCFC or SOFC anode off-gas. An atmospheric-pressure internal-reforming SOFC with 86O’C exit-temperature might realistically operate at 0.7 V at 85% utilization. About 57.2% (gross) of the NG feedstock LHV would be available as dc power, with 24.1% as waste heat and 18.7% as uncombusted gas in the equilibrium shifted anode exit stream (2.1% CO, 8.8% Hz), Making an allowance of 10% of total output for dc-ac conversion and auxiliary power requirements, and assuming 43% conversion of the remainder to ac power via the turbine, the system would have a net ac LHV efficiency of 69.8%. A pressurized (9 atma) SOFC may operate at 0.735 V at 90% utilization (assuming that polarization losses are negligible), i.e., with an exit gas composition of 1.4% CO, 5.9% Hz. The SOFC would then become part of the turbine combustion chamber. In this case, 66.15% (gross) of the feedstock LHV would be available as dc power, with 21.4% as waste heat and with 12.45% remaining in the anode exit stream. With the same assumptions as those above, an overall net ac LHV efficiency of 74.0% could be attained. An atmospheric pressure IIR-DIR MCFC operating at 0.76 V with suitable heat-exchangers at 75% utilization (assuming 100% CIQ conversion) would give 54.8% of the LHV of the feedstock as dc electricity, 13.2% as waste heat, and 32.0% as uncombusted anode exit stream. Again, with the same assumptions, this would allow 68.8% net ac LHV efficiency. A 3 atma pressurized system operating at 0.8 V under the same conditions might yield 70.0% with similar assumptions. External reforming systems (or those with a small final reformer to replace the DIR stage in the MCFC) would have similar efficiencies if heat-exchange reformers were incorporated in the turbine combustor. The turbine exhaust in each case would be mote than sufficient to raise steam for reforming. If a 1.4 MW turbine611 can achieve these efficiencies, the sizes of the combined units, each with a 1.4 MW turbine, would vary from 5 MW for the atmospheric pressure MCFC to 7.1 MW for the pressurized SOFC. If the fuel cell system can be constructed for $1,5OO/kW in each case, and if the capital cost of the turbine is $1,000/kW,611 then advanced combined-cycle systems with ultra-high LHV efficiencies in the 69-7496 range may be feasible at costs ranging from $1,360-$1,4OO/kW. Because of the low temperatures and lean burners used, NO;! emissions should be similar to those reported for conventional HTFC systems operating at lower efficiency. Emissions of 7 g/MWh have been reported for the 1,OOOT SOFC.56 The figure was only 0.35 g/MWh for the 664OC exit temperature MCFC. 1s4b At comparable efficiency, the value should be about 2 g/MWh for an 86O’C exit temperature SOFC with internal reforming. Thus,

Fuel cell technology

631

corrected for efficiency, these advanced combined cycles should have NO2 emissions below 2 g/MWh. about the same as that of the PC25A PAFC.n*los and almost two orders of magnitude below those of the next best level of equipment, the state-of-the-art gas turbine. 30. REFERENCES 1. 2. 3. 4. 5. 6. I. 8. 9. 10. 11. 12. 13. 14.

15.

16. 17. 18.

19. 20. 21. 22.

23. 24. 25. 26. 27. 28. 29. 30. 31. 32.

W. Ostwald. Z. Elektrochem. 1, 122 (1894). W. R. Grove, original 1846 edition of The Correlolion of Physical Forces, 6th edn., Longmans Grmn and Co., London (1874). L. Mond and C. Langer. Phil. Mug. 46,296 (1889). B. C. H. Steele, I. Kelly, H. Middleton and R. Rudkin, Exr. Abs. 1988 Fuel Cell Seminar, Long Beach, CA. p. 179, National Fuel Cell Coordinating Group, Washington, DC (1988). M. Mogensen. B. Malmgren-Hansen, and B. Kindl, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, p. 195, National Fuel Cell Coordinating Group, Washington, DC (1990). A. J. Appleby and F. R. Foulkes. Fuel Cell Handbook, Van Nostrand-Reinhold, New York (1989). G. W. Scheffler and F. S. Kemp, Ext. Abs. I988 Fuel Cell Seminar, Long Beach, CA, p. 218. National Fuel Cell Coordinating Group, Washington, DC (1988). A. J. Appleby, Energy 11, 13 (1986). Anon., Fuel Cell RD&D in Japan, Fuel Cell Development Information Center, Tokyo, Japan (August 1991). M. K. Wright and L. E. Van Bibber, Ext. Abs. 1982 Fuel Cell Seminar, Orlando, FL, p. 69. National Fuel Cell Coordinating Group, Washington, DC (1982). S. Akimaru. Y. Tsutsumi, K. Tamura, S. Ono, K. Ogimoto, K. Sakamoto and N. Masunaga. Ext. Abs. 1983 Fuel Cell Seminar, Newport Beach, CA, p. 153, National Fuel Cell Coordinating Group, Washington, DC (1983). L. J. M. J. Blomen, J. Power Sources 37, 141 (1992). L. J. M. J. Blomen, KTI, Inc., Zoetemkr. The Netherlands, Private communication (December 1991). C. K. Pang, S. T. Lee, K. Lee and D. T. Imamura, Applications of Fuel Cells in Utility Systems, Vol. 1, Study Results, EPRI EM-3205, Vol. 1, EPRI, Palo Alto, CA, 1983; Anon., Temple, Barker and Sloane,, Inc., The Financial and Strategic Planning Benefits of Fuel Cell Power Plants (2 Volumes), EM-451 1, EPRI. Palo Alto. CA (1986). (a) D. W. Boyd, 0. E. Buckley, C. E. Clark, Jr., R. B. Fancher and J. R. Spelman. EPRI Roles in Fuel Cell Commercializafion. AP-5137. EPRI, Palo Alto, CA (1987); (b) E. W. Hall, L. M. Handley and G. W. May, Capital Cost Assessment of Phosphoric Acid Fuel Cell Power Plants for Electric Utility Applications, AP-5608, EPRI, Palo Alto, CA (1988). B. M. Bamett and W. P. Teagan, J. Power Sources 37, 15 (1992). J. J. Cut&a, “Key Commercialization Issues Associated with Fuel Cell Power Plants,” Proc. IAE Symposium on Fuel Cells and Advanced Batteries, Institute of Applied Energy, Tokyo (1986). N. R. Udengaard, L. J. Christiansen and D. M. Rastler, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA. p. 47, National Fuel Cell Coordinating Group, Washington, DC (1988); N. R. Udengaard, L. J. Christiansen, W. A. Summers, and D. M. Rastler, Endurance Testing of a High-Eficiency Steam-Reformer for Fuel Cell Power Plants. EPRI AP-6071, Electric Power Research Institute, Palo Alto, CA (1988). T. Watanabe, M. Koga and S. Morishima, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA, p. 56, National Fuel Cell Coordinating Group, Washington, DC (1988). Data for steam-injected 38 MW General Electric Frame 6 PG6531B. K. Yeager. Private communication, Advanced Power Systems Division, Electric Power Research Institute, Palo Alto, CA (October, 1991). L. M. Handley et al., 4.8 MW Fuel Cell Demonstrator, Final Report, FCR-3278. Contract No. DE-AC-01-76ET13 112, Department of Energy and the Electric Power Research Institute, United Technologies Corporation, South Windsor. CT (December 1981). L. M. Handley. M. Kobayashi and D. M. Rastler, Operational Experience with Tokyo Electric Power Company’s 4.5 MW Fuel Cell Demonstration Plant, Electric Power Research Institute, Palo Alto, CA (July 1986). F. Funahashi, T. Okamoto, R. Saito and 0. Tajima, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA, p. 222, National Fuel Cell Coordinating Group, Washington, DC (1988). N. Itoh. T. Kimura, H. Kaneko, and H. Kawamura, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach. CA, p. 226, National Fuel Cell Coordinating Group, Washington, DC (1988). T. Iino. J. S. Caraceni, Y. Shiba, and N. Kato, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA, p. 230, National Fuel Cell Coordinating Group, Washington, DC (1988). K. Shibata, J. Power Sources 37,81 (1992). Anon.. Assistant Secretary for Fossil Energy, US Department of Energy, Fuel Cell Systems Program Plan, FY 1990, U.S. DOE. Washington, DC (1990). Anon, Steering Committee Report, Fuel Cell Program of the Department of Energy, The Gas Research Institute, and the Electric Power Research Institute, U.S. DOE, Washington, DC (1990). G. J. Sandelli and R. J. Speigel, J. Power Sources 37,255 (1992). F. Sabbioni, in Fuel Cells, Trends in Research and Applications, p. 223, A. J. Appleby ed., Hemisphere, New York, NY (1987). C. E. Gibbs and M. C. F. Steel. J. Power Sources 37.35 (1992).

638

33. 34.

35. 36. 37.

A. J. Appleby K. Joon and P. Zegers, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, Appendix, p. 1, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Abe. Y. Ixaki, T. Watanabe, Y. Mugikura and K. Shimaxu, in J. R. Selman, H. C. Maru, D. R. Shores, and I. Uchida eds.. Proceedings of the Second Symposium on Molten Carbonate Fuel Cell Technology. Seattle, October 1990, p. 16, The Electrochemical Society, Pennington. NJ (1990). A. Fukutome, J. Power Sources 37,53 (1992). R. Anahara, J. Power Sources 37,119 (1992). J. B. J. Veldhuis. S. B. van der Molen, R. C. Makkus and G. H. J. Broers. Ber. Bunsenges. Phys. Chem. 94,947 (199Q.

38. 39.

40. 41. 42.

43. 44. 45. 46. 47. 48. 49. 50.

51.

:i:

54. 55. 56. 57. 58. 59. 60. 61. 62. 63. 64. 65. 66. 67. 68. 69. 70. 71. 72. 73. 74.

K. Kishida, in Fuel Cells, Tremis in Research and Applications, p. 173, A. J. Appleby ed., Hemisphere, New York, NY (1987). K. Kishida. Mitsubishi Electric Company, Amagasaki. Japan. Private communication (December 1991). N. Kakley and J. Giner, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA, p. 118, National Fuel Cell Ccordinating Group, Washington, DC (1988). J. R. Selman, Energy 11, 153 (1986). E. A. Gillis, J. R. Selman, H. C. Maru. D. R. Shores and I. Uchida eds.. Proceedings of the Second Symposium on Molten Carbonate Fuel Cell Technology, Seattle, October 1990, p. 1, The Electrochemical Society, Pennington. NJ (1990). Technical Assessment Guide, P-6587, p. 7, EPRI. Palo Alto, CA (1989). E. A. Gillis, J. Power Sources 37,45 (1992). J. A. Serfass and D. R. Glenn, J. Power Sources 37.63 (1992). E. H. Camara and F. C. Schora, J. Power Sources 37. 165 (1992). T. Benjamin, MC-Power Corporation, Burr Ridge, IL, Private communication (October 1991). A. J. Appleby, J. Power Sources 37,223 (1992). S. B. Alpert, Electric Power Research Institute, Presentation at “Electricity After 2000 Symposium,” Alexandria, VA (October 1991). S. S Penner, ed., Coal Gasification, Pergamon. New York (1987); S. S. Penner, et al. Energy 12.623-903 (1987). D. R. Simbeck, R. L. Dickenson and E. D. Oliver, Coal Gasification Systems: A Guide to Status, Applications, and Economics, Ap-3109, Electric Power Research Institute (EPRI), Palo Alto, CA (1983). N. A. Halt, “Cool Water Project Update,” EPRI Journal 11,34 (1986). W. G. Snyder and C. A. Depew, Coproduction of Carbon Dioxide (CO2) and Electricity, AP-4827, Electric Power Research Institute (EPRI), Palo Alto, CA (1986). See also T. A. Matchack, A. D. Rao, V. Ranathan and M. T. Sander, Cost and Peiformance for Commercial Applications of Texaco-Based Gasification Combined Cycle Plants, AP-3486, BPRI (1984). K. Yeager, presentation “Electricity after 2000 Symposium, Electric Power Research Institute-Central Research Institute of the Electric Power Industry,” Alexandria, VA (October 1991). H. T. Chen, J. H. Hirschenhofer, M. G. Klett and M. D. Rutkowski. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, p. 148, National Fuel Cell Coordinating Group, Washington, DC (1990). W. J. Dollard, Westinghouse Electric Corporation, Pittsburgh, PA, Private communication (September 1991). B. C. H. Steele, Imperial College, London, Private communication (December 1991). F. J. Rohr, Proc. Workshop on Solid Oxide Fuel Cells, Brookhaven Nationat Laboratory, Upton. NY (1977). E. R. Ray, Ext. Abs. 1990Fuel Cell Seminar, Phoenix, AZ, November 1990. p. 506, National Fuel Cell Coordinating Group, Washington, DC (1990). Y. Yamamoto, S. Kaneko and H. Takehashi. Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA, p. 25, National Fuel Cell Coordiiting Group, Washington, DC (1988). Y. Mori and M. Harada, Ext. Abs. 1988 Fuel Cell Seminar, Long Beach. CA, p. 18, National Fuel Cell Coordinating Group, Washington, DC (1988). J. E. Brute. Asea Brown Boveri (U.S.A.), Fuel Cell News Update (June 1991). W. J. Dollard, J. Power Sources 37, 133 (1992). P. Zegers, Oral presentation, 1988 Fuel Cell Seminar, Long Beach, CA (October 1988). T. Hoshina, T. Yoshida and S. Sakurada, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, p. 516, National Fuel Cell Coordinating Group, Washington, DC (1988). M. Hsu. Ext. Abs. 1988 Fuel Cell Seminar, Long Beach, CA, October 1988, p. 36, National Fuel Cell Coordinating Group, Washington, DC (1988). Anon., Arthur D. Little, Inc., Cambridge, MA, The Role of Fuel Cell Technology in the International Power Equipment Market - Policy/Strategy Issues, Ref. 44335, World Fuel Cell Council, Frankfurt, Germany, 1993. M. J. Mayfield. Supplement to Plenary Session, Jnt. Fuel Cell Conf. Proc.. MITI, Tokyo (1992). Anon. (International Fuel Cells, South Windsor, CT), Advanced Water-Cooling PAFC Development, Final Report No. DE/MC!/24221-3130, US DOE Contract No. DE-AC21-88MC24221, September 1992. J. H. Hirschenhofer, D. B. Stauffer, and R. R. Engleman, R. R., Fuel Cells, A Handbook (Revision 3), DGE/METC94/1006 (DE94004072). p. 3-1, National Technical Information Service, U.S. Department of Commerce, Springfield, VA, 1994. B. M. Bamett, W. P. Tcagan, and D. E. Kleinschmitt, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 423. National Fuel Cell Coordinating Group, Washington, DC (1992). R. P. Wichert and R. Rose, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 424, National Fuel Cell Coordinating Group, Washington, DC (1992). M. El-Gas&r and D. M. Rastler, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p.428, National Fuel Cell Coordinating Group, Washington, DC (1992). J. A. Serfass, M. K. Bergman, and W. Rodenhiser, J. Power Sources 49, 193 (1994).

Fuel cell technology

::: II.

78. 19.

J. Packer, J. Power Sources 37, 101 (1992). J. Doelman, J., J. Power Sources 37, 75 (1992). L. Sjunnesson, Ext. Abs. 1994 Fuel Cell Seminar, San Diego. CA. p. 15, Fuel Cell Seminar Crganizing Committee, Washington, DC, 1994. G. Wismann, ELI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 325, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. P. Layman, Chemical and Eng. News, p. 11, October 2,1995. G. K. Troost, J. Power Sources 49. 185 (1994). P. Zegers, Plenary Session, Int. Fuel Cell Conf. Proc., p. 3. MITI, Tokyo (1992). P. D. Michael and J. Maguire, European Fuel Ceils R&D Review, ETSU, Oxfordshire/UK-Argonne National Laboratory, ANL-94/46, National Technical Information Service, Springfield, VA, 1994. S. S. Penner, A. J. Appleby, B. S. Baker, J. L. Bates, L. B. Buss, W. J. Dollard, P. J. Farris, E. A. Gillis, J. A. Gunsher, A. Kbandkar, M. Krumpelt, J. B. O’Sullivan, G. Runte, R. F. Savinell, J. R. Selman, D. A. Shores, and P. Tarman. (a) Prog. Energy Combust. Sci. 21,145 (1995); (b) Energy 20,331 (1995). R. Anahara, J. Power Sources 49, xi (1994). (a) Anon., Fuel Cell R&D in Japan, Fuel Cell Development Information Center, Tokyo, November 1994; (b) Ibid., November 1995. T. Taniguchi. Supplement IOInt. Fuel Cell Conf. Proc.. MITI, Tokyo (1992). 0. Yarnamoto, H. Tajima, and S. Ohga, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 46, National Fuel Cell Coordinating Group, Washington. DC (1992). T. Makate, K. Ohkawara, H. Maebayashi, M. Abe, and Y Usami, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 338, National Fuel Cell Coordinating Group, Washington. DC (1990). H. Maebayasi, S. Oncdera and Y. Kanai. Inr. Fuel Cell Conf. Proc., p. 95. MIT& Tokyo (1992). M. Harada. N. Hahimoto, Y. Tanohata. and S. Sugiura, Ezr. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 383, National Fuel Cell Coordinating Group, Washington, DC (1990). S. Yanagida, T. Sioiri, and S. Satake. Ext. Abs. 1990 Fuel Cell Seminar. Phoenix, AZ, November 1990, p. 326, National Fuel Cell Coordinating Group, Washington, DC (1990). K. Shiori, Int. Fuel Cell Cot& Proc., p. 15, MITI, Tokyo (1992). T. Terayama, J. Miyake, and N. Sato, N., Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 5, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. W. H. Podolny and J. W. Schmitt, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 631, National Fuel Cell Coordinating Group, Washington, DC (1992). (a) T. Sugimoto, Lars A. Sjunnesson, and E. A. Gillis. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 1, National Fuel Cell Coordinating Group, Washington, DC (1992); (b) J. R. Hirschenhofer, Proc. 29th. IECEC Meeting, Monterey, CA, August 1994, p. 806, American Institute of Aeronautics and Astronautics, Washington, DC, 1994; (c) J. R. Hirschenhofer, Proc. 30th. IECEC Meeting, Orlando, FL, August 199.5, p. 3-165, American Society of Mechanical Engineers, New York, NY, 1995. M. Whelan, Int. Fuel Cell Conf. Proc., Plenary Session, p. 21. MITI, Tokyo (1992). P. J. Farris, International Fuel Cells, South Windsor, CT, Information provided for Ref. 83 (August 1993-August 1994). P. R. Gerst. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 224, National Fuel Cell Coordiiting Group, Washington, DC (1992). A. C. Lloyd, J. H. Leonard, and R. George, J. Power Sources 49,209 (1994). H. Nymoen, J. Power Sources, 49,63 (1994). K. Nishizaki. M. Ikeda, M. Ohkuda. and M. Kaisaki, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 21, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. N. Iwasa and E. Hayashi, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 25, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994, p. 25. A. Meyer, International Fuel Cells, Inc., South Winsdor, CT, Private communications (July 1994-November 1995). M. J. Binder and G. L. Cler, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 665, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. M. A. Schiazza and G. L. Gibson, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 65, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. (a) R. H. McClelland, T. Cook, C. Berry, P. McGrath, S. Legedza, K. Spitznagel, S. Sanders, L. B. Herzog, R. Quick. A. Plonka, D. Rider, L. Wittrup, and R. Brown, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p, 11, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994; (b) R. H. McClelland, Proc. 3001. IECEC Meering, Orlando, FL, August 1995, p. 3-171, American Society of Mechanical Engineers, New York, NY, 1995; R. Yokoyama and K. Ito, Proc. 29th. IECEC Meeting, Monterey, CA, August 1994, p. 823. American Institute of Aeronautics and Astronautics, Washington, DC, 1994. J. M. King, L. J. Bonville, and G. J. Sandelli. EXI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 1, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. G. J. Sandelli, J. C. Trocciola, and R. J. Speigel, J. Power Sources 49. 143 (1994). L. A. Wittrup, E. Smeloff. and R. P. Wichert, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 566, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. A. J. Appleby, J. Power Sources, in press. H. C. Healy and P. K. Kregling, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 261, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. Anon., IFCmNSI-Enron/EETI Product Brochure, 1994. M. K. Wright, J. M. Feret, and M. T. Lee, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 254, National Fuel Cell Coordinating Group, Washington, DC (1990). L. E. Van Bibber. W. A. Summers, and J. K. Feret, in Hydrogen Energy Progress IX, T. N. Veziroglu, ed., p. 1497, M.C.I., Paris, France (1991).

Et: 82. 83. 84.

85. 86. 81. 88.

91. 92. 93. 94. 95.

E: 98. 99.

100. 101. 102. 103. 104. 105. 106.

107. 108. 109. 110. 111. 112. 113. 114.

639

640

115. 116. 117. 118. 119. 120. 121. 122. 123. 124. 125. 126. 127. 128. 129. 130. 131. 132. 133. 134. 135. 136. 137. 138. 139. 140. 141. 142. 143. 144. 145. 146. 147. 148. 149. 150. 151. 152. 153. 154. 155. 156. 157. 158. 159.

A. J. Appleby M. T. Le, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 467, National Fuel Cell Coordinating Group, Washington, DC (1990). L. Canuti, Ext. Abs. 1990 Fuel Cell Seminar, San Diego, CA, November 1994, p. 3%, Fuel Cell Seminar Organizing Committee.Washington. DC, 1994. G. Simader and K. Kordesch, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 613. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. L. Sjunnesson, Sydkraft, Personal Communication, February 1994. U. Henfridsson, L. Spante. N. Carlstedt. and C. Sandqvist, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 515, Fuel Cell Seminar Organizing Committee,Washington, DC, 1994. T. Bozzoni, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. . 353, National Fuel Cell Coordinating Group, Washington, DC (1992). T. Bozzoni. CLC srl. Genoa. Italy. Information txovided for Ref. 83 (June 1994). W. Drenckhahn, Seimens AG, E&ngen. Germany. Information provided for Ref. 83 (June 1994). W. Dbnitz, Daimler-BenJDomier, Friedrichshafen, Germany, Information provided for Ref. 83 (June 1994). B. G. Marcenaro. M. Mazzieri, U. Haus, V. Cincotti. and F. Di Mario, Ext. Abs. 1990 Fuel Cell Seminar, Phoenir, AZ, November 1990. p. 260, National Fuel Cell Coordinating Group, Washington, DC (1990). R. Vellone. F. Di Mario, V. Cinotti, and M. Brocco. J. Power Sources 37, 111 (1992). V. Cincotti, U. Haus, and D. Sardone, Inr. Fuel Cell Conf. Proc., p. 113, MITI. Tokyo (1992). T. Matsushita, T. Terayama, and Y. Shiba, Inr. Fuel Cell Conf. Proc., p. 137, MITI, Tokyo (1992). H. Kawahara, Exr. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 491, National Fuel Cell Coordinating Group, Washington, DC (1990). 0. Yamamoto, Y. Orawa. and S. Ohga, Inr. Fuel Cell Con& Proc., p. 67, MITI, Tokyo (1992). 0. Yamamoto, H. Tajima, and S. Ohga, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 46, National Fuel Cell Coordinating Group, Washington, DC (1992). M. Kaizaki, S. Kaneko, and M. Ike& Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p, 330, National Fuel Cell Coordinating Group, Washington, DC (19%). T. Nogi. T. Toma. and H. Yamazaki, Ext. Abs. 1990 Fuel Cell Seminar. Phoenix, AZ, November 1990, p. 322. National Fuel Cell Ccordinating Group, Washington, DC (1990). A. Kitamura, K. Nakaji, and H. Matsuda. lnrernarional Fuel Cell Conference Proceedings, p. 99, MITI, Tokyo (1992). H. C. Lim. C. W. Lee, and K. S. Ahn, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p, 507, Fuel Cell Seminar Organizing Committee,Washington, DC, 1994. T. Yanagino. H. Matsumoto, B. Kariya, N. Kadoya, and E. Yoshino, Inf. Fuel Cell Conf. Proc., p. 79, MITI, Tokyo (1992). H. Ishioka, T. Koshimizu, H. Miyoshi, and Y. Mizumoto, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 318, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Omoto, H. Tomei, Y. Yuasa, and H. Yamazaki, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 334, National Fuel Cell Coordinating Group, Washington, DC (1990). H. Yamamoto, Y. Matsumoto, and Y. Mizumoto, Inr. Fuel Cell Conf. Proc., p. 91, MITI, Tokyo (1992). M. Matsumoto, K. Usami, and T. Murahashi, Int. Fuel Cell Co@ Proc., p, 133, MlTI, Tokyo (1992). K. Usami, H. Tomei, Y. Mizumoto, M. Matsumoto. and T. Murahashi, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 366, National Fuel Cell Coordinating Group, Washington, DC (1992). T. Homma, S. Mori, and A. Nakaoka, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p. 615, Fuel Cell Seminar Organizing Committee,Washington, DC, 1994. K. Yokata, K. Uehara, J. S. Caraceni. Y. Shiraiwa. and T. Amemiya, Int. Fuel Cell Conf. Proc.. p. 87. MITI, Tokyo (1992). K. Yokata, T. Misono, G. Vartanian, N. Kate, and T. Amemiya, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 195, National Fuel Cell Coordinating Group, Washington, DC (1992). T. Iino, J. S. Caraceni, Y. Shiba, N. Kato, and K. Hayakawa, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 264, National Fuel Cell Coordinating Group, Washington, DC (1990). K. Harasawa. I. Kanno, I. Mast&, EXI. Abs. 1992 Fuel Cell Seminar, Phoenix, AZ, November 1992, p. 191, National Fuel Cell Coordinating Group, Washington, DC (1992). K. Okano,hf. Fuel Cell Coy? Proc., p. 129, MITI, Tokyo (1992). M. Sakurai. K. Okano, and R. Anahara, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ. November 1992, p. 641, National Fuel Cell Coordinating Group, Washington, DC (1992). R. Anahara, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 486, National Fuel Cell Coordinating Group, Washington, DC (1990). M. Ike&, N. Iwasa, and H. Yoshida, Int. Fuel Cell Conf. Proc., p. 121, MITI, Tokyo (1992). I. Kanno, Int. Fuel Cell Con& Proc., p. 1, MITI, Tokyo (1992). K. Kimoto, Ink Fuel Cell Conf Proc., p. 5, MITI. Tokyo (1992). N. Hashimoto, I. Tsushi, and Y. Sawada, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 633, National Fuel Cell Coordinating Group, Washington, DC (1992). Y. Sawada, E. Ide, N. Iwasa. I. Tsushi, and N. Hashimoto, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 362, National Fuel Cell Coordinating Group, Washington, DC (1992). N. Hashimoto, I. Tushi, N. Iwasa, Y. Sawada, and R. Ide, Int. Fuel Cell Conf Proc., p. 125, MITI, Tokyo (1992). T. Koshimizu, K. Ito, and S. Kaneko, EXI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 501, National Fuel Cell Coordinating Group, Washington, DC (1992). T. Satomi, S. Someno, and M. Nakamura, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 29. Fuel Cell Seminar Organizing Committee,Washington, DC, 1994. M.Yamaguchi, N. Uozumi, M. Izumitani, and Y. Tsutsumi, Ext. Abs. I990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 375, National Fuel Cell Coordinating Group, Washington, DC (1990). L Yoshioka, Int. Fuel Cell Co@ Proc.. p. 9, MITI, Tokyo (1992). T. Take, K. Oshima, and T. Koyashiki. Inf. Fuel Cell Conf. Proc., p. 63. MITI, Tokyo (1992).

Fuel cell technology 160. 161. 162. 163. 164. 165. 166. 167. 168. 169. 170. 171. 172. 173. 174. 175. 176. 177. 178. 179. 180. 181. 182. 183. 184.

185. 186. 187. 188. 189. 190. 191. 192. 193. 194. 195. 196. 197. 198.

641

T. Take, T. Hasegawa, K. Oshima, and T. Koyashii, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ. November 1992, p. 477, National Fuel Cell Coordinating Group, Washington, DC (1992). N. Iwasa and K. Okada, lnr. Fuel Cell Conf. Proc., p. 83, MlTl. Tokyo (1992). 0. Okada. S. Takami, N. Iwasa, T. Ohhama, and H. Yamamoto, Exr. Abs. 1992 Fuel Cell Seminar, ‘Tucson, AZ, November 1992, p. 473, National Fuel Cell Coordinating Group, Washington, DC (1992). M. Ogawa, H. Shingai. T. Ueyama. Y. Tanaka, and C. L. Laursen. Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 485, National Fuel Cell Coordinating Group, Washington, DC (1992). H. Stahl and C. L. Laursen, Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 465, National Fuel Cell Coordinating Group, Washington, DC (1992). M. Matsuda, S. Takami, and 0. Okada. Ext. Abs. 1994 Fuel Cell Seminar. San Diego, CA, November 1994, p. 376, Fuel Cell Seminar Organizing Committee,Washington. DC, 1994. M. Masuda, 0. Okada, S. Takami. and S. Nagese. Exl. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 380, Fuel Cell Seminar Organizing Committee,Washington, DC, 1994. Y. Fuji@ K. Shima, and I. Satoh, Inr. Fuel Cell Co& Proc., p. 105. MITI. Tokyo (1992). Y. Fukao. T. Hiram Y. Yoshikawa, T. Baba, and T. Inaba, lnt. Fuel Cell Conf. Proc., p. 109, MITI, Tokyo (1992). K. Shibata and K. Watanabe, J. Power Sources 49.77 (1994). D. R. Glenn and J. A. Serfass. Ext. Abs. 1994 Fuel Cell Seminar, San Diego. CA, November 1994, D. 630, Fuel Cell Seminar Organizing Committee,Washington, DC, 1994. L. Paetsch, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 32, National Fuel Cell Coordinatine Grout). Washineton. DC (1990). H. Maru, Energy R&earch C&po&on; Danbury, CT, Private communication (October 1993). H. C. Maru, M. Farooque, L. Paetsch. C. Y. Yuh, P. Patel., J. Doyen, R. Bernard, and A. Skok, In?. Fuel Cell Conf. Proc., p. 145, MITI, Tokyo (1992). D. Hermann and C. Middleton, EXI. Abs. 1990 Fuel Cell Seminar. Phoenix, AZ, November 1990, p. 36, National Fuel Cell Coordinating Group, Washington, DC (1990). H. C. Mant, M. Farooque, L. Paetsch, C. Y. Yuh, P. Patel. J. Doyon, R. Bernard, and A Skok, Exf. Abs. 1992 Fuel Cell Seminar. Tucson. AZ. November 1992, P. 29. National Fuel Cell Coordinating Group, Washington, DC (1992). D. M. Rastler, G. Devote, R. Castle, and C.-Chi, Ext. Abs. 1992 Fuel Cell Seminar, T&on. AZ,November 1992, p. 186, National Fuel Cell Coordinating Group, Washington, DC (1992). L. Paetsch. J. Hunt, C. Y. Yuh. and D. Rastler. Ext. Abs. 1994 Fuel Cell Seminar, San Diego. CA, p. 253, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. H. C. Maru. G. Steinfeld. B. S. Baker. and P. H. Eichenberaer. Exf. Abs. 1990 Fuel Cell Seminar, Phoenix. AZ, November 1990. p. 267, National Fuel Cell Coordinating Groip,.Washington, DC (1990). P. H. Eichenberger and T. P. O’Shea, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November i992, p. 183, National Fuel Cell Coordinating Group, Washington, DC (1992). (a) T. P. O’Shea and A. J. Leo, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 462, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994; (b) T. P. O’Shea and A. J. Leo, Proc. 29rh. fEC.EC Meeting, Monterey, CA, August 1994, p. 817, American Institute of Aeronautics and Astronautics, Washington, DC, 1994. J. A. Serfass, D. R. Glenn, and R. W. Claussen, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 437, National Fuel Cell Coordinating Group, Washington, DC (1992). P. H. Eichenberger, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 293, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. H. C. Maru, Energy Research Corporation, Danbury, CT, Information provided for Ref. 83 (October 1993). (a) H. C. Maru. M. Farooque, and B. S. Baker, Proc. 29th. IECEC Meeting, Monterey, CA, August 1994, p. 838. American Institute of Aeronautics and Astronautics, Washington, DC, 1994: (b) M. Farooque, R. Bernard, P. Patel, A. Skok, C. Yuh, J. Doyon, and H. Maru, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 234, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. H. C. Maru. Eneruv Research Corooration, Danbury. CT, Private communications (January-November, 1995). B. S. Baker; Enerzy Research Corporation, Danbury, CT, Private communications (September-December 1995). L. M. Paetsch. J. D. Dovon. and M. Faroouue. Proc. Third Svmo. on Molten Carbonate Fuel Cell Technology, -. PV 93-3, p. 89, The Electrochemical Society, Inc.,.Pennington, NJ (1993). C. Yuh, R. Johnsen, M. Farooque, and H. Maru, Proc. Third Symp. on Molten Carbonate Fuel CeU Technology, PV 93-3, p. 158, The Electrochemical Society, Inc.. Pennington, NJ (1993). A. Pigeaud and G. Wilemski. Proc. Third Syrnp. on Molten Carbonate Fuel Cell Technology, PV 93-‘3,p. 186, The Electrochemical Society, Inc., Pennington, NJ (1993). A. Pigeaud, J. J. Helble, C. L. Senior, Exr. Abs. 1994 Fuel Ceil Seminar, San Diego, CA, p. 539, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. S. G. Abens. G. Steinfeld. P. Pad. and M. Piwetz. and T. S. Christiansen, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, i. 651, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. R. J. Petri. C. Sishtla. E. One. R. Remick. R. Platen. D. Vasil. B. Evans. T. B. Bcniamin. and R. A. Jurish, Ext. Abs. 1990’ Fuel Cell’Semin&, Phoenix, kZ, November 1996. p. 48, National Fuel Cell Coordinating Group, Washington, DC (1990). E. H. Camam, W. C. Racine, and I. A. Scroppo, lnr. Fuel Cell Confi Proc., p. 149, MITI, Tokyo (1992). R. R. Woods and P. Tarman, MC-Power Corporation, Burr Ridge, IL, and L. G. Marianowski, Institute of Gas Technology, Chicago, IL, Information provided for Ref. 83 (November 1993). T. G. Benjamin, R. M. Laurens, and M. P. Whelan, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 21. National Fuel Cell Coordinating Group, Washington, DC (1992). D. K. Fleming, T. G. Benjamin, and R. J. Remick, Proc. Third Symp. on Molten Carbonafe Fuel Cell Technology, PV 93-3. p. 25, The Electrochemical Society, Inc., Pennington, NJ (1993). G. Wilemski, N. H. Kemp, and A. Gelb, Molten Carbonate Fuel Cell Performance Model Updale, Final Report, DOE/Fw15078-1742, NTIS, U.S. Department of Commerce (January 1985). (a) R. M. Laurens. V. J. Petraglia, R. J. Petri. T. G. Benjamin, G. L. Reznikov, D. S. Erickson, L. A. Jakaitis, and N. N. Shah, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 242, Fuel Cell Seminar Organizing Committee,

642

199.

200. 201. 202. 203. 204. 205. 206. 207. 208. 209. 210. 211. 212. 213. 214. 215. 216. 217. 218. 219. 220. 221. 222. 223. 224. 225. 226. 227. 228. 229.

230. 231. 232.

A. J. Appleby Washington, DC, 1994; (b) T. Benjamin, R. M. Laurens. V. J. Petraglia, and R. J. Petri, Proc. 29th. IECEC Meeting, Monterey.CA, August1994. p. 835, American Institute of Aeronautics and Astronautics, Washington, DC, 1994; (c) T. G. Benjamin, R. M. Laurens. V. J. Petraglii. and R. J. Petri, Proc. 30th. /ECEC Meeting. Orlando. FL, August 1995, p. 3-215. American Society of Mechanical Engineers, New York, NY, 1995. (a) T.-P. Chen, C. R. Brown, J. J. Senetar, N. Kudlu, T. M. Andews. and T. A. Robinson, Proc. 29th. IECEC Meeting, Monterey.CA, August1994, p. 829, American Institute of Aeronautics and Astronautics, Washington, DC, 1994; (b) C. R. Brown, J. J. Senetar, N. Kudlu, T. P. Chen, T. M. Andrews. T. A. Robertson, J. Scroppo, A. Figueroa, and R. J. Craig, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 454, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. R. R. Woods, R. W. Lighthipe, C. T. Ratcliffe. and W. C. Racine. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 433. National Fuel Cell Coordinating Group, Washington, DC (1992). R. A. Figuaroa, R. J. Petri, J. Scroppo. and R. Goldstein, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 370, National Fuel Cell Coordinating Group, Washington, DC (1992). R. A. Figueroa and R. R. Woods, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 257. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. E. Camara and S. Huval, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p, 589, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. E. T. Ong, Exr. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 314, National Fuel Cell Coordinating Group, Washington, DC (1990). M. A. Cobb and R. Meacham, Technical and Economic Assessmentof MoltenCarbonate Fuel Cell Manufacturing Costs,EPRI TR-101525, Electric Power Research Institute, Palo Alto. CA, 1993. E. T. Gng. Int. Fuel Cell Conf. Proc., p. 219, MITI, Tokyo (1992). R. J. Petri, E. T. Ong, R. J. Remick, and C. Sishtla, Ext. Abs. 1992 Fuel Cell Seminar, Tucson. AZ, November 1992, p. 134, National Fuel Cell Coordinating Group, Washington, DC (1992). E. T. Ong. R. A. Donado, K. Hrdina, C. Houston, and R. Goldstein, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 130, National Fuel Cell Coordinating Group, Washington, DC (1992). P. M. Brown, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 289, National Fuel Cell Coordinating Group, Washington, DC (1990). P.M. Brown, Int. Fuel Cell Conf Proc.. p. 177, MlTI. Tokyo (1992). C. Shishtla, D. Vasil, R. Platen, E. T. Gng, R. J. Remick, and R. J. Evans, Ext. Abs. I994 Fuel Cell Seminar, San Diego, CA, p. 400, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. E. T. Ong. R. J. Remick, and C. Shishtla. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 404, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. H. C. Healy, W. H. Johnson, and C. A. Reiser. Int. Fuel Cell Conf Proc., p. 261, MITI, Tokyo (1992). H. R. Kunz and J. W. Pandolfo, J. Elecrrochem. Sot. 139, 1549 (1992). J. R. Selman and I. Uchida, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 298, National Fuel Cell Coordinating Group, Washington, DC (1990). H. R. Kunz. Proc. Third Symp. on MoltenCarbonateFuel Cell Technology, PV 93-3, p. 385, The Electrochemical Society, Inc., Pennington, NJ (1993). D. Shores, J. R. Selman, and E. T. Ong, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 294, National Fuel Cell Coordinating Group, Washington, DC (1990). D. R. Shores and Y. Qu,, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 356, The Electrcchemicai Society, Inc., Pennington, NJ (1993). D. Shores and M. Pischke, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 214, The Electrochemical Society, Inc., Pennington, NJ (1993). M. De Gurie, M. J. Shingler, and E. Dincer. Doped Cerium Oxidefor Molten CarbonateFuel Cell Cathodes.EPRI Report No. ER-6983, Electric Power Research Institute, Palo Alto, CA (1990). S. Elongovan. A. Khandkar. D. Tucker, and R. Mayhew. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix,AZ, November 1990, p. 222, National Fuel Cell Coordinating Group, Washington, DC (1990). A. P. Brown, G. H. Kucera. M. F. Roche. D. D. Chu, and E. Indachochea. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 125, National Fuel Cell Coordinating Group, Washington, DC (1992). G. H. Kucera, K. M. Myles, A. P. Brown, M. F. Roche. and E. Indacochea, in Proc. 4th Annual Fuel Cell ContractorsReviewMeeting, p. 31, DOE Morgantown, WV (1992). J. L. Smith. G. H. Kucera, and A. P. Brown, Lithium ManganiteDevelopmentas a Molten Carbonate Fuel Cell Cathode,EPRI Report No. GS-7288. Electric Power Research Institute, Palo Alto, CA (1991). G. L. Lee and J. R. Selman, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 542, National Fuel Cell Coordinating Group, Washington, DC (1992). J. R. Selman and G. L. Lee. Proc. Third Symp. on Molten CarbonateFuel Cell Technology, PV 93-3, p. 309, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Watanabe and J. R. Selman, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 559, National Fuel Cell Coordinating Group, Washington, DC (1992). Y. Izaki. Y. Mugikura. T. Watanabe, and J. R. Selman, Ext. Abs. 1994 Fuel Cell Seminar. San Diego. CA, p. 168, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. (a) T. J. George and M. C. Williams, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ. November 1990, p. 53, National Fuel Cell Coordinating Group, Washington, DC (1990); (b) M. C. Williams, E. L. Parsons, and M. J. Mayfield, Proc. 29th. IECEC Meeting, Monterey, CA, August 1994, p. 812, American Institute of Aeronautics and Astronautics, Washington, DC, 1994: (c) D. T. Hooie and M. C. Williams Prod. 30th. IECEC Meeting, Orlando, FL, August1995, p. 3-171, American Society of Mechanical Engineers, New York, NY, 1995. M. Williams and M. Mayfield, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 442, National Fuel Cell Coordinating Group, Washington, DC (1992). H. Koner, W. Gauntlett. and J. Abbott, Ext. Abs. 1992 Fuel Cell Seminar. Tucson, AZ, November 1992, p. 336, National Fuel Cell Coordinating Group, Washington, DC (1992). K. Joon, Energy Center Netherlands, Petten, The Netherlands, Information provided for Ref. 83 (June 1994).

Fuel cell technology 233. 234.

235. 236. 231. 238. 239. 240. 241. 242. 243. 244. 245. 246. 241. 248. 249.

250. 251. 252. 253. 254. 255. 256. 257. 258. 259. 260. 261.

263. 264. 265. 266. 261. 268. 269. 210.

643

K. Joon. P. C. Van der Laag, and D. Jansen. Plemxry Session, Inr. Fuel Cell Co@. Proc.. 9.25, MITI, Tokyo (19% L. A. H Machielse, J. H. N. Verheugen, R. J. Boesma, C. Croon, W. M. A. Klerks, and G. Rietveld. Ext. Abs. %O Fuel Cell Seminar, Phoenix, AZ, November 1990, Appendix, p, 6, National Fuel Cell Coordinating Group, Washington, DC (1990). L. A. H. Machielse, R. J. Boesma. C. Croon, W. M. A. Klerks. and G. Rietveld, Inl. Fuel Cell Con& Proc., p. 269, MD-I. Tokyo (1992). R. G. Onemanger, R. J. Boesma, and L. P. der Vaal. Proc. 1992 Fuel Cell Seminar. Tucson, AZ. National Fuel Cell Conrdinating Group, Washington, DC, 1992. p. 31. W. M. A. KJerks. G. J. Kraaij, and G. Rietveld. Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 160. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. P. C. van der Laag and T. W. Verbtuggen. EXI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 152, Fuel Cell Seminar Organizing Committee, Washington. DC, 1994. L. Plomp. R. C. Makkus, E. F. Sitters, and G. Rietveld, Ext. Abs. 1994 Fuel Cell Seminar, Sun Diego, CA, p. 164, Fuel CelJ Seminar Organizing Committee, Washington, DC, 1994. W. He, R. W. J. Kouffeld,‘A. Korving, and J. G. M. Becht. Ext. Abs. 1994 Fuel Cell Seminar, San Diego. CA, p. 602, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. C. A. M. de Koning and L. P. der Vssl, BCN. The Hague, The Netherlands, Information provided for Ref. 83 (June 1994). A. de Groot, M. J. Meijer. and N. Woudstra, Exf. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 619. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. K. Joon and L. P. der Vaal, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 273, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. P. C. van der Laag, Exf. Abs. 1990 Fuel Cell Seminor. Phoenix, AZ, November 1990, p. 175, National Fuel Ccl1 Coordinating Group. Washington, DC (1990). A. B. J. Oudhuis, D. Jansen, and P. C. van der Laag, Modern Power Systems, November 1991, p. 25. B. S. Baker, Energy Research Corporation, Danbury, CT, Information provided for Ref. 83 (October 1993). L. A. H. Machielse, A. L. Dick& and S. Freni, EXI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 495, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. G. P. J. Dijkema. A. F. Veenstra, M. Vriesendotp. and H. C. de Lathouder. Exr. Abs. 1994 Fuel Cell Seminar. San Diego, CA, p. 299. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. J. B. J. Veldhuis, F. C. Eches, and L. Plomp, J. Electrochem. Sot. 139, L7 (1992). L. Plomp, E. F. Sitters, 1. B. J. Veldhuis, R. C. Makkus, and S. B. Van Molen, Proc. Third Symp. on Molten Carbonufe Fuel Cell Technology, PV 93-3. p. 171, The Electrochemical Society, Inc., Pennington, NJ (1993). L. Plomp, 1. B. J. Veldhuis, E. F. Sitters, F. P. F. van Berkel, and S. B. van der Molen, Int. Fuel Cell Conf. Proc., p. 157, MITI, Tokyo (1992). L. Plomp, J. B. J. Veldhuis, E. F. Sitters, and S. B. Van der Molen. J. Power Sources 39,369 (1992). L. Plomp, F. P. F. van Berkel. J. B. J. Veldhuis, and S. B. van der Molen. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 310, National Fuel Cell Coordinating Group, Washington, DC (1990). S. B. Van Molen and L. Plomp. Proc. Third Symp. on Molten Carbonare Fuel Cell Technology, PV 93-3, p. 212, The Electrochemical Society, Inc., Pennington, NJ (1993). J. P. T. Vossen, L. Plomp, and J. H. W. de Wit, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology. PV 93-3, p. 278. The Electrochemical Society, Inc., Pennington, NJ (1993). J. A. Prins-Jansen, C. J. van Duyn, K. Hemmes. and J. H. W. de Wit, Proc. Third Symp. on Molten Carbonare Fuel Cell Technology, PV 93-3, p. 468. The Electrochemical Society. Inc., Pennington, NJ (1993). R. van Gerwen and H. Koetzier, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 77, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. N. J. J. Dekker. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 156. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. R. J. Boersma. L. A. H. Machielse. and R. Q&an, Int. Fuel Cell Conf Proc., p. 255, MITI, Tokyo (1,992). K. Joon and H. Barten, Ext. Abs. 1994 Fuel Cell Seminor. San Diego, CA, p. 679, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. H. Wendt. 0. Bbhme. and F.-U. Leidich, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 160, National Fuel Cell Coordinating Group, Washington. DC (1990). H. Wendt, 0. Bohem, F.-U. Leidich, T. Brensheit, Proc. Third Symp. on Molten Carbonate Fuel Gel! Technology, PV 93-3, p. 486. The Electrochemical Society, Inc., Pennington, NJ (1993). 0. B(lhme, U. Haus. F. U. Leidich, H. J. Salge, and H. Wendt, Ext. Abs. 1994 Fuel Cell Seminar, Son Diego, CA, p. 61. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. T. Brensheit, K. Janowitz, and H. Wendt, Exl. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 65, NationalFuel Cell Coordinating Group, Washington, DC (1992); K. Janowitx and H. Wendt, Int. Fuel Cell Co@ Proc., p. 47, MITI, Tokyo (1992). B. Rohland, M. Bischoff, U. Jantsch, and V. Plzak, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA., p. 623, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. G. Schaumberg. K. Ledjeff, and L. Stcckert, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 117, National Fuel Cell Coordinating Group, Washington, DC (1992); H. Koch, B. Roland, and H. Wendt, Ext. Abs. 1992 M. Brossa, A. Dufour, E. Hermana, J. F. Jiminez, and F. Sanson, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 238, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. F. Parodi and R. A. Sanderson. Ext. Abs. 1994 Fuel Cell Seminar. San Diego. CA, p. 420, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. G. Roccini. M. Scagliotti, and A. Torarza, Exf. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. ti73, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. P. Araldi, L. Bigoni, A. Colombo, F. Gariboldi. B. Passalacqua. P. Savoldelli. and M. Zappaterra, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 570. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994.

644 271. 272. 273. 274. 275. 276. 277.

278. 279. 280. 281. 282. 283. 284. 285. 286. 287. 288. 289. 290. 291. 292. 293. 294. 295. 296. 297. 298. 299. Z 302: 303. 304. 305. 306.

A. J. Appleby S. Fmni. E. Passalacqua. M. Minutoli, and N. Giordano. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 388. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. S. Freni. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 191. National Fuel Cell Coordinating Group, Washington, DC (1990). M. Aquino, S. Cavallaro, S. Freni. and N. Giordano. EXI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 285, National Fuel Cell Coordinating Group, Washington, DC (1992). L. Bigoni, R. Frezzi, M. Scagliotti. M. Leonini. B. Passalacqua, R. Perrelli, M. Zappatem, and G. Rocchini, EXI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 121, National Fuel Cell Coordinating Group, Washington, DC (19%). L. Bigoni. R. Fezzi, M. Leonin, B. Passalacqua, G. Rocchini, M. Scagliotti, A. Torazza, and M. Zappaterra, fnr. Fuel Cell Co& Proc., p. 211, MITI. Tokyo (1992). G. Liberati and G. Spazzafumo. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ. November 1992, p. 69. National Fuel Cell Coordinating Group, Washington. DC (1992). L. Giorgi, M. Carewska. M. Patriarca, S. Scaccia, E. Simonetti, and A. Di Bartolomeo, J. Power Sources 49,227 (19%); L. Giorgi, E. Simonetti, M. Carawska, S. Scaccia, and F. Zarzana, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. p.172. Fuel Cell Seminar Organizing Committee, Washington, DC, 1994; M. Carewska. Scaccia, C. Chiodelh, L. Giori, and E, Simonetti, Ibid., p. 176. C. Laursen and N. Untergaard, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. p.188, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. L. J. Christiansen and K. Aasberg-Petersen, Inr. Fuel Cell Co@ Proc., p. 231, MITI, Tokyo (1992). B. Bergman, E. Fontes, G. Lindbergh, C. Ladergren, A. Lundblad, S. Schwartz, D. Simmonsson. and Sylwan. Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 73, National Fuel Cell Coordinating Group, Washington, DC (1992). D. Simonsson,. Proc. Third Symp. on Molten Carbonate Fuel Cell Technology. PV 93-3, p, 401, The Electrochemical Society, Inc., Pennington, NJ (1993). M. Bursell. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 419, National Fuel Cell Coordinating Group, Washington, DC (1990). B. Bergman, C. Lagergren, and A. Lundblad. Proc. Third Symp. on Molren Carbonate Fuel Cell Technology, PV 933, p. 342, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Kivisaari. Exr. Abs. 1992 Fuel Cell Seminar. Tucson, AZ, November 1992, p. 325, National Fuel Cell CoordinatingGroup, Washington, DC (1992). A. Ramskllld. N.-E. Carlstedt. and L. Snante. Exr. Abs. 1992 Fuel Cell Seminar. Tucson. AZ. November 1992. D. . 585, NationaiFuel Cell Coordinating G&p. Washington, DC (1992). A. Ramsk&ild, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. p. 551, Fuel Cell Seminar Organizing Committee. Washington, DC, 1994. T. Kivisaari, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p, p. 531, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. T. Kivisaari. Exr. Abs. 1994 Fuel Cell Seminar. San Diego. D. D. 535, Fuel Cell Seminar Orrranizing _ _ -- CA. ._ Committee, Washington, DC, 1994. K. Sato, T. Tanaka, and T. Murahashi, Exr. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990. p. 40. National Fuel Cell Coordinating Group, Washington, DC (1990). T. Tanaka, M. Matumura, T. Gonyo. M. Miyazaki, A. Sasaki, K. Sato, H. Urushibata, and T. Murahashi, Proc. 26rh IECEC. D. 583 (1991). M. Matumura, Y. Gonjyo, C. Hirai, and T. Tanaka, Inr. Fuel Cell Conf. Proc., p. 247, MITI, Tokyo (1992). C. Hirai, M. Matsumura, A. Sasaki, and E. Nishimiyama, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 61, National Fuel Cell Coordinating Group, Washington, DC (1992). C. Hirai, M. Matsumura, and A. Sasaki, Proc. Third Symp, on Molren Carbonare Fuel Cell Technology, PV 93-3, p. 146, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Murahashi, A. Sasaki. M. Matasumura, H. Urushibata, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. p. 230. Fuel Cell Seminar Orrranizinn Committee. Washington. DC, 1994. J. dhtsuki, A. Kusunoki, ?. Mu&hashi. T. Tanaka, aid E: Nishiyama, Inr. Fuel Cell Conf. Proc., p. 251, MITI, Tokyo (1992). M. Miyazaki, T. Okada, H. Ide, S. Matsumoto, T. Shinoki, and J. Ohtsuki, Proc. 27rh IECEC. p. 287 (1992). J. Ohtsucki, T. Seki, S. Takeuchi. A. Sasaki. H. Urushibata. and T. Murahashi, Proc. Third Symp. on Molren Carbonate Fuel Cell Technology, PV 93-3, p. 48, The Electrochemical Society, Inc., Pennington, NJ (1993). A. Sakai. S. Matsumoto. M. Fujitsuka, T. Shinoki. T. Tanaka, and J. Ohtsuki, IEEE Winter Meeting, 92WMOlO9EC. (1992). Y. Mugikura, Y. Izaki, T. Watanabe, H. Kinoshita, E. Kouda, T. Abe, H. Urushibata. S. Yoshioka, H. Maeda, and T. Murahashi. Inr. Fuel Cell Con& Proc.. p. 215, MITI, Tokyo (1992). H. Urushibata and T. Murahashi, fnr. Fuel Cell Conf. Proc., p. 223, MITI, Tokyo (1992). K. Hoshino and T. Kohno, Inr. Fuel Cell Conf, Proc., p, 169, MITI, Tokyo (1992). Y. Yamamasu, T. Kakihari, E. Kasai, and T. Morita, Inr, Fuel Cell Conf. Proc., p. 235. MITI, Tokyo (1992). Y. Aoyagi, A. Saial. S. Sakurada. N. Nishioka, T. Saitoh. N. Furukawa, and T. Sakamoto, Exr. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p, 183, National Fuel Cell Coordinating Group, Washington, DC (1990). Y. Miyake, T. Nakajima, K. Harima, N. Nakanishi, M. Nishioka, T. Saitoh, and N. Furukawa. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 101, National Fuel Cell Coordinating Group, Washington. DC (1992). Y. Miyake, K. Harima, T. Nakajima, N. Nakanishi, T. Saitoh, Y. Aoyagi. J. Tanaka, A. Saiai, H. Yanura, M. Sasaki, and M. Okada, Proc. Third Symp. on Molren Carbonate Fuel Cell Technology, PV 93-3, p. 63, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Saitoh, A. Saiai, S. Sakurada, T. Saitoh, and M. Okada, Exr. Abs. 1992 Fuel Cell Seminar, Tucson. AZ, November 1992, p. 77, National Fuel Cell Coordinating Group, Washington, DC (1992).

Fuel cell technology 307. 308. 309. 310. 311. 312. 313. 314. 315. 316. 317. 318. 319. 320. 321. 322. 323. 324. 325. 326. 327. 328.

329.

330. 331. 332. 333. 334. 335. 336. 337. 338. 339. 340. 341. 342.

645

J. Tanaka, A. Saiai. S. Sakurada, T. Nakajima. Y. Miyake. T. Saitoh, M. Sasaki. and H. Yanaru. Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 37, The Electrochemical Society, Inc., Pennington. NJ (1993). M. Iijima. 1. Tanaka, A. Saiai, T. Nakajima, K. Harima, Y. Miyake. and H. Yanaru, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p. 226. Fuel Cell Seminar Organizing Committee, Washington, DC (1994). S. Sam. Y. Yanaru, A. Saiai, and Y. Miyake. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 408, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). T. Segawa, Y. Uchiyama. and N. Horiuchi, Int. Fuel Cell Conf. Proc.. p. 153, MITI, Tokyo (1992). T. Yoshida. K. Itoh, K. Mochizuki. J. Hashiguchi, T. Inoue. F. Hashimoto, and A. Ishikawa, Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 309, National Fuel Cell Coordinating Group, Washi.ngton, DC (1992). N. Kaiimoto. K. Takahashi. and N. Horiuchi. Ext. Abs. 1992 Fuel Cell Seminar. Tucson, AZ, November 1992. p. 179. National Fuel Cell Coordiiting Group, Washington, DC (1992). T. Mori and N. Horiuchi. Proc. Third Svmv. on Molten Carbonate Fuel Cell Technolonv. I_ PV 93-3, D. . 11. The Electrochemical Society, Inc., Penning& NJ (1993). N. Nakaoka, H. Andou, T. Yoshida. H. Yasue, H. Uematsu, and M. Abe, Exf. Abs. 15% Fuel Cell Seminar, San Diego, CA, November 1994, p. 458, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). H. Ayada, H. Totuka, Y. Yamazaki, Y. Kurihara, and M. Yanagida. Exl. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 2.09, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Kc&ma. Y. Miyazaki. A. Fukutome, and K. Honjo, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 106. The Electrochemical Society, Inc., Pennington, NJ (1993). Y. Mugikura. Y. Izaki. T. Watanabe, E. Kouda, H. Kinoshita, and T. Abe, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 109, National Fuel Cell Coordinating Group, Washington, DC (1992). T. Kahara, K. Ohtsuka. S. Takashima, M. Takeuchi, Y. Fukui, and S. Nakamura, Err. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 95, National Fuel Cell Coordinating Group, Washington, DC (1990). I. Some, M. Takeuchi. T. Yoshida. T. Kahara, and K. Ohtsuka. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 302, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Kahara, K. Ohtsuka, S. Takashima, M. Takeuchi, Y. Fukui, and H. Fujimura, EXI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 13. National Fuel Cell Coordinating Group, Washington, DC (1992). T. Karaha, M. Kunikata, M. Takeuchi, S. Takashima, T. Kamo, and H. Fujimura, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p, 222, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). T. Watanabe, T. Abe, Y. Izaki, Y. Mugikura, and E. Koda, Ext. Abs. 1994 Fuel Cell Seminar, San Diego. CA, November 1994, p. 446, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). K. Uematsu. T. Hasegawa, T. Okano, T. Tsuchitori, and T. Mori, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 269, Fuel Cell Seminar Organizing Committee., Washington, DC (1994). M. Takeuchi, H. Okada. K. Iwamoto, Y. Iwase, S. Kuroe. T. Kahara, and K. Ohtsuka, Ext. Abs. 195’0 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 231, National Fuel Cell Coordinating Group, Washington, DC (1990). S. Kuroe, M. Takeuchi, S. Nishimura, and K. Ohtsuka, Int. Fuel Cell Conf. Proc., p.207, MITI. Tokyo (1992). M. Takeuchi, S. Mitsushima. Y. Iwase, H. Okada, S. Kuroe, S. Nishimura, T. Kahara, and K. Ohtsuka. Exf. Abs. 1992 Fuel Cell Seminar, Tucson. AZ, November 1992. p. 105. National Fuel Cell Coordinating Group, ‘Washington, DC (1992). M. Hosaka, Y. Yamamasu, Y. Kate, A. Suzuki, and S. Sate, EXI. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990. p. 99, National Fuel Cell Coordinating Group, Washington, DC (1990). Y. Mugikura. T. Watanabe, Y. Izaki, H. Saitoh, K. Shimazu, T. Abe, T. Matsuyama, T. Shimazu, S. Sate, and M. Ogoshi, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 103, National Fuel Cell Coordinating Group, Washington, DC (1990). Y. Izaki, T. Watanabe, Y. Mugikura. H. Konoshita, E. Kouda, T. Ahe, T. Matsuyama, T. Shimizu, and S. Sate, Int. Fuel Cell Co@ Proc., p.243, MITI. Tokyo (1992). Y. Izaki, Y. Mugikura, E. Koda, T. Watanabe, H. Kinashita, T. Abe., T. Matsuyama, T. Shimizu, and S. Sate, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 119, The Electrochemical S,ociety, Inc., Pennington, NJ (1993). K. Kobayashi, N. Kinoshita, and M. Koga, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 87, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Hiiata. S. Kawakami, M. Mizusawa, T. Watanabe, and M. Koga, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 81, National Fuel Cell Coordinating Group, Washington, DC (1992). A. Suzuki, M. Tooi. M. Hosaka, T. Matsuyama, Y. Masuda, T. Nakane, and T. Osato, In!. Fuel Cell Conf. Proc.. p.273, MU-I, Tokyo (1992). M. Tooi, T. Mauuyama, M. Hosaka, A. Suzuki, and S. Sate, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 25, National Fuel Cell Coordinating Group, Washington, DC (1992). S. Sate, Proc. Third Symp. on Molten Carbonale Fuel Cell Technology, PV 93-3, p. 131, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Kakihara, T. Morita, A. Suzuki, and Y. Yamamasu, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 450, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). N. Kinoshita, EXI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 89, National Fuel Cell Coordinating Group, Washington, DC (1992). Y. Yamamasu. T. Kakihara. E. Kasai, and T. Morita, Inr. Fuel Cell Conf. Proc.. p. 161, MITI, Tokyo (1992). H. Masai and A. Suzuki, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 240, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Oh& S. Mitsushima, S. Kate, S. Asano, H. Yoshitake, and N. Kamiya, J. Elecrrochem. Sot. 139,667 (1992). S. Washoi. T. Hikita, S. Nakagawa, and S. Hatori, Int. Fuel Cell Conf. Proc.. p.239. MITI. Tokyo (1992). T. Terayama, K. Murata. M. Yamamoto, M. Hori. and M. Sasaki, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ. November 1990, p. 91, National Fuel Cell Coordinating Group, Washington, DC (1990).

646

343. 344. 345. 346. 347. 348. 349. 350. 351. 352. 353. 354. 355. 356. 357. 358. 359. 360. 361. 362. 363. 364. 365. 366. 367. 368. 369. 370. 371. 372. 373. 374. 375. 376. 377. 378.

A. J. Appleby M. Hori. S. Takeshita. and M. Shintani. .&I. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 368. Fuel Cell Seminar Organizing Commiuee. Washington, DC (1994). H. Ozo, Y. Akasaka, K. Nakagawa. H. Tateishi, and K. Tada, ht. Fuel Cell Conf. Proc., p, 199, MITI, Tokyo (1992). (a) K. Yamashita and K. Murata. Int. Fuel Cell Co@. Proc.. p. 203. MITI, Tokyo (1992): (b) T. Ggawa, H. Niasawa. and K. Murata, Proc. 30th. IECEC Meeting, Orlando, FL, August 1995. p. 3-221, American Society of Mechanical Engineers, New York, NY, 1995. T. Shimada, V. Kuriki, N. Yamanouchi, and M. Tamura, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 171, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Yoshii. K. Hoshino, N. Ariga, M. Yamamoto, and Y. Horii. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p, 140, Fuel Cell Seminar Organizing Commit&, Washington, DC (1994). M. Yamamoto and S. Takahashi. Int. Fuel Cell Con& Proc.. p. 181, MITI, Tokyo (1992). M. Yamamoto and Y. Kato. Ext. Abs. 1994 Fuel Cell Seminar. San Dieno, CA. November 1994. ._D. 144, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). J. Nikura. K. Hatoh. E. Yasumoto. and T. Gamo. Ext. Abs. 1992 Fuel Cell Seminar. Tucson. AZ. November 1992. p. 93, National Fuel.Cell Coordinating Group, Washington, DC (1992). K. Hatoh, J. Niiiura, E. Yasumoto. and T. Game, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 136. Fuel Cell Seminar Organizing Committee, Washington, DC (1994). C. Nagai, K. Morimoto, T. Nagashima. S. Terada, and H. Itoh. Int. Fuel Cell Conf. Proc., p, 173, MITI, Tokyo (1992). S. Terada. C. Nagai, I. Nagashima, and K. Morimoto, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 128, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). Y. Miyazaki, M. Yanagida. S. Tanase, K. Tanimoto, T. Kojima, H. Okuyama, T. Kodama, H. Itoh, C. Nagai, and S. Terada, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 179, National Fuel Cell Coordinating Group, Washington, DC (1990). K. Tanimoto, Y. Miyazaki. M. Tanagida, H. Okuyama, and T. Kodama, Int. Fuel Cell Co& Proc., p. 185, MITI, Tokyo (1992). Y. Miyazaki. M. Yanagida, S. Tanese, K. Tanimoto. T. Kojima, N. Ohtori, H. Okuyama, and T. Kodama, Ext. Abs. 1992 Fuel Cell Seminor, Tucson, AZ, November 1992, p. 97, National Fuel Cell Coordinating Group, Washington, DC (1992). Y. Miyzaki, M. Yanagida, S. Tanese, K. Tanimoto, T. Kojima, N. Ohtori, and T. Kodama,, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 444, The Electrochemical Society, Inc., Pennington, NJ (1993). Y. Miiyaki, M. Yanagida, K. Tanimoto, T. Kojima, N. Ohtori, and T. Asai, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 120, Fuel Cell Seminar Organizing Committee. Washington, DC (1994). M. Yam&da, Y. Miyazaki, S. Tanase, K. Tanimoto, T. Kojima, N. Ohtori, H. Okuyama, and T. Kodama, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 85, National Fuel Cell Coordinating Group, Washington, DC (1992). H. Yokokawa, N. Sakai, T. Kawada, and M. Dokiya, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix. AZ, November 1990, p. 152, National Fuel Cell Coordinating Group, Washington, DC (1990). K. Ota, B. Kim, S. Asano, H. Yoshitake, and N. Kamiya, Int. Fuel Cell Co& Proc., p. 203, MITI, Tokyo (1992). T. Nishina. G. Lindbergh, T. Kudo, and I. Uchida, Int. Fuel Cell Confi Proc., p. 203, MITI, Tokyo (1992). I. Uchida and T. Nishina, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 550, National Fuel Cell Coordinating Group, Washington, DC (1992). I. Uchida, S. Ohuchi, and T. Nishina. Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 292, The Electrochemical Society, Inc., Pennington, NJ (1993). M. Yanagida. Y. Miyazaki, S. Tanese, K. Tanimoto. T. Kojima, N. Ohtori, and T. Kodama, Proc. Third Symp. on Molten Carbotwte Fuel Cell Technology, PV 93-3, p. 230, The Elcctrochcmical Society, Inc., Pcnnington, NJ (1993). K. Ota, B. Kim, Y. Abe, H. Yoshitake, and N. Kamiya, Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 252, The Electrochemical Society, Inc., Pennington, NJ (1993). I. Uchida. S. Ohuchi, and T. Nishina. Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 292, The Electrochemical Society, Inc., Pennington, NJ (1993). I. H. Oh, T. H. Lim, S. W. Nam, S. A. Hong, H. C. Lim, and C. W. Lee, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 372, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). S. W. Nam. T. H. Lim. I. H. Oh, and S. A. Hong, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 109, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). H. S. Chun, J., H. Lim, K. P. Park, J. K. Lee, and K. Kim, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 571, National Fuel Cell Coordinating Group, Washington, DC (1992). H. S. Chun, G. P. Park, J. H. Lim, K. Kim, J. K. Lee, K. H. Moon, and J. H. Youn, J. Power Sources 49,245 (1994). D. Rho. H. Kim, J. Kim, and E. Kim, Int. Fuel Cell Conf Proc.. p. 117, MITI, Tokyo (1992). M. Kuki and S. Koike. Ext. Abs. 1992 Fuel Cell Seminar. Tucson. AZ. November 1992. .D. 592. National Fuel Cell Coordinating Group, Washington, DC (1992). S. Koike. M. Kuki. T. Ichihashi, and K. Hasimoto, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 519. Fuel Cell Seminar Organizing Committee, Washington, DC (1994). N. Hanimoto, J. Power Sources 49,103 (1994). D. T. Hooie, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 3, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Krist. M. E. Karpuk, and J. D. Wright, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 624, National Fuel Cell Coordinating Group, Washington, DC (1992). W. L. Lundberg, Solid Oxide Fuel Cell Cogeneration System Concepttual Design, Final Report, Westinghouse Electric Corporation, GRI-89-0162, Gas Research Institute, Chicago, IL (1989).

Fuel cell technology 379. 380. 381. 382.

383. ::: 386. 387. 388. 389. 390. 391. 392. 393. 394. 395. 396. 397. 398. 399. 400. 401. 402. 403. 404. 405. 406. 407.

408. 409. 410. 411. 412. 413. 414.

647

K. Krist, Gas Research Institute, Chicago, IL, Private communication (October 1992). H. U. Anderson and M. M. NasraBah. Characmrixation of Oxides for Low Temperature Solid Oxide Fuel Cells, Annual Repott, Contract No. 5090-260-2069, Gas Research Institute, Chicago, IL (I991). K. Krist and J. D. Wright, Proc. Third Ink Symp. Sol&iOxide Fuel Cells, PV 934. p. 782, The Electrochemical Society, Inc., Pennington. NJ (1993). U. Bessel. PerformoncePotentialsof Solid OxideFuel Cell Confguradons. EPRI TR-10119. Electric Power Research Institute, Palo Alto, CA (1992): Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 261. National Fuel Ceil Coordinating Group. Washington, DC (1992); Proc. Third Int. Symp. Solid OxideFuel Cells, PV 934. p. 833, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Krist and J. D. Wright, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 45, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). W. J. Dollard, lnt. Fuel Cell Co@ Proc., p. 313, MITI, Tokyo (1992). E. R. Ray, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 415, National Fuel Cell Coordinating Group, Washington, DC (1992). J. M. Makiil, L. A. ShockIing, and T. R. Fabii, ELI. Abs, 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 523, National Fuel Cell Coordinating Group, Washington, DC (1992). S. E. Veyo, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 527. National Fuel Cell Coordinating Group, Washington, DC (1992). S. C. Singhal. Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 665. The Electrochemical Society, Inc., Pennington, NJ (1993). J. D. Leeper. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p. 265, Fuel Cell Seminar Organizing Committee. Washington, DC (1994). E. R. Ray, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 670. Fuel Ccl1 Seminar Organizing Committee, Washington, DC (1994). J. B. G’Sullivan, Electric Power Research Institute, Palo Alto. CA, Information provided for Ref. 83 (June 1994). S. C. Singhal. Westinghouse Electric Corporation, Pittsburgh, PA, Information provided for Ref. 83 (January 1994). A. Khar&ar, Cemmatec, Inc., Salt Lake City, UT, Information provided for Ref. 83 (March 1994). N. Q. Mirth, T. R. Armstrong, J. V. Guiheen, C. R. Home, F. S. Liu, D. M. Moffatt, T. L. Stillwagon, and J. J. Van Akeren, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990. p. 524. National Fuel Cell Coordinating Group, Washington, DC (1990). N. Q. Minh. A. Amiro, T. R. Armstrong, J. R. Esopa. J. V. Guiheen. C. R. Home, and J. Van Akeren, Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November1992, p. 607. National Fuel Cell Coordinating Group, Washington, DC (1992). G. M. Christie, P. H. Middleton. and B. C. H. Steele, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 315. The Electrochemical Society, Inc., Pennington, NJ (1993). N. Q. Minh, T. R. Armstrong, J. R. Esopa. J. V. Guiheen, C. R. Home, and J.J. Van Ackeren, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 934, p. 801. The Electrochemical Society, Inc., Pennington, NJ (1993). N. Q. Minh, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 577, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). M. Liu, A. Khandkar, and M. Timper, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 527, National Fuel Cell Coordinating Group, Washington, DC (1990). C. Milliken, D. Tucker, S. Elangovan, and A. Khandkar, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix,Ai?.November 1990, p. 218. National Fuel Cell Coordinating Group, Washington, DC (1990). A. Khandkar. S. Elangovan, J. Hartvigsen, C. Milliken, and M. Timper. Exf. Abs. 1992 Fuel Cell Sembmr, Tucson, AZ. November 1992, p. 596. National Fuel Cell Coordinating Group, Washington, DC (1992). C. Milliien, S. Elangovan, and A. Khandkar, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 801, The Electrochemical Society, Inc., Pennington, NJ (1993). M. HSU and H. Tai. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 115, National Fuel Cell Coordinating Group, Washington, DC (1990). M. Hsu, Int. Fuel Cell Conf Proc.. p. 337, MITI, Tokyo (1992). M. Hsu and R. Phillips, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ. November 1992, p. 345, National Fuel Cell Coordinating Group, Washington, DC (1992). M. Hsu and D. Nathanson, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 510, National Fuel Cell Coordinating Group, Washington, DC (1992). (a) M. Hsu, D. Nathanson, and E. Hoag. Proc. 29th. IECEC Meeting, Motuerey, CA, August 1994, p. 847, American Institute of Aeronautics and Astronautics, Washington, DC, 1994, (b) M. Hsu, D. Nathanson, and D. Diem. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 53, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). E. A. Barringer, D. P. Heitxenrater, and M. R. Tharp, Proc. Third Inf. Symp. Solid Oxide Fuel Cells, PV 934. p. 771. The Electrochemical Society, Inc., Pennington, NJ (1993). I. Bloom, M. C. Hash, J. P. Zebrowski, D. Zurawski. M. Krumpelt, and K. M. Myles, Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November1992, p. 628, National Fuel Cell Coordinating Group, Washington, DC (1992). I. Bloom. K. L. Ley, and R. Kumar, Ext. Abs. 1994 Fuel Cell Seminar. San Diego, CA, November 1994, p. 597, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). L. A. Chiik and J. L. Bates, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 563, National Fuel Cell Coordinating Group, Washington, DC (1992). L. A. Chick, C. R. Armstrong, D. E. McCready, G. W. Coffey, G. D. Maupin, and J. L. Bates, Proc. Third Int. Symp. Solid OxideFuel Cells, PV 93-4, p. 374. The ElectrochemicaJ Society, Inc., Pennington, NJ (1993). T. R. Armstrong, L. A. Chick, and J. L. Bates, Proc. Third ht. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 632, The Electrochemical Society, Inc., Pennington. NJ (1993). G. E. Youngblood. A. S. Rupaal, L. R. Pederson, and J. L. Bates. Proc. Third Inl. Symp. Solid Oxiae Fuel Cells, PV 93-4. p. 585, The Electrochemical Society, Inc., Pennington, NJ (1993).

648

415. 416. 417. 418. 419. 420. 421. 422. 423. 424. 425. 426. 427. 428. 429. 430. 431. 432. 433. 434. 435. 436. 437. 438. 439. 440. 441. 442.

A. J. Appleby T. R. Armstrong, J. W. Stevenson, P. E. Raney, and L. R. Pederson, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, Nowmber 1994, p. 105, Fuel Cell Seminar Grganizing Committee, Washington, DC (1994). H. U. Andason, D. Carter, R. Koc. and M. Nasrallah. Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 141, National Fuel Cell Coordinating Group, Washington, DC (1990). C. C. Chen. M. M. Nasrallah, and H. U. Anderson, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 515. National Fuel Cell Coordinating Group. Washington, DC (1992). C. C. Chen, M. M. Nanallah, and H. U. Anderson, Proc. Thirdlru. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 252, The Electrochemical Society, Inc., Pennington, NJ (1993). C. C. Chem, M. M. Nasrallah, and H. U. Anderson, Proc. Third Inl. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 598. The Electrochemical Society, Inc., Pennington, NJ (1993). L.-W. Tai, M. M. Nasrallah, and H. U. Anderson, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4. p. 241, The Electrochemical Society, Inc., Pennington, NJ (1993). J. D. Carter, V. Sprenlcle. M. M. Nasrallah, and H. U. Anderson, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 934. p. 344. The Electrochemical Society, Inc., Pennington, NJ (1993). B. Fu. W. Huebner, M. F. Trubelja, and V. S. Stubican. Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 276. The Electrochemical Society, Inc., Pennington, NJ (1993). H. U. Anderson, W. Heubner. D. M. Reed, C. C. Chen, X. Deng, and M. M. Nasrallah, Exr. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p. 49, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). A. F. Sammells, R. L. Cook, D. J. Kuchynka, and K. Krist, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990. p. 119, National Fuel Cell Coordinating Group, Washington, DC (1990); A. F. Sammells. Inr. Fuel Cell Conf. Proc., p. 277, MIT& Tokyo (1992). S. Kramer. M. Spears, and H. L. Tuller, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 119. The Electrochemical Society, Inc., Pennington, NJ (1993). K. Mehta, S. J. Hong, J.-F. Jue, and A. N. Vi&r. Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 92, The Electrochemical Society, Inc., Penninaton. NJ (1993). Q.-H. Gao, R. E. Rocheleau, and B. Y. Gaw, Proc. Third Inf. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 38, The Elcctnxhemical Society, Inc., Pennington, NJ (1993). K. C. Chou, S. Yuan, and U. Pal, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 431, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Nisancioalu and T. M. Glir. Proc. Third Int. Svmp. Solid Oxide Fuel Cells, PV 93-4. p. _ 267, The Electrochemi&I Society, Inc., Pennington, NJ (1993). - . L. S. Wane and S. A. Bamett. Proc. Third Int. Svmo. Solid Oxide Fuel Cells. PV 93-4.. D. . 649. The Electrochemical Society, I&., Pennington, NJ.(1993). - ’ H. Alqahtany. D. Eng, and M. Stoukides. Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 938, The Electrochemical Society, Inc., Pennington, NJ (1993). N. F. Bessette and W. J. Wepfer, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 519, National Fuel Cell Coordinating Group, Washington, DC (1992). N. F. Bessette and W. J. Wepfer, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p. 148. Fuel Cell Seminar Organizing Committee, Washington, DC (1994). Y. C. Hsiao and J. R. Selman. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 546, National Fuel CeII Coordinating Group.Washington, DC (1992). Y. C. H&O and J. R. Selman, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 895, The Electrochemical Society, Inc., Pennington, NJ (1993). T. M. Maloney and G. A. Coulman, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 239, National Fuel Cell Coordinating Grouo, Washington. DC (1990). P. Zegers, Proc. Third Int. Simp. Solid Oxid; Fuel Cells. PV 93-4, p. 16, The Electrochemical Society, Inc., Pennington, NJ (1993). J. P. P. Huijsmans. E. J. Siewers, and S. B. van der Molen, Exr. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 512, National Fuel Cell Coordinating Group, Washington, DC (1990). J. P. P. Huijsmans, E. J. Siewers, F. H. van Heuveln. and J. P. de Jong, Proc. Second Inc. Symp. on Solid Oxide Fuel Cells, Athens, Greece, p. 113, Report No. EUR 13546 EN, DG XII, Commission of the European Communities, (1991). L. G. J. de Haart, R. A. Kuipers. K. J. de Vries, and A. J. Burggraaf, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 131, National Fuel CelI Coordinating Group, Washington, DC (1990). S. B. van der Molen, J. P. P. Huijsmans. and L. Plomp, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 623, National Fuel Cell Coordinating Group, Washington, DC (1992). J. P. P. Huijsmans, F. H. van Heuveln, J. P. der Jong, and D. Bos, Inf. Fuel Cell Conf Proc., p. 353, MITI, Tokyo (1992). F. P. F. van Berkel, F. H. van Heuveln, and J. P. P. Huijsmans, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 744, The Electrochemical Society, Inc., Pennington, NJ (1993). J. P. P. Huijsmans, F. P. F. Van Bakel, and J. P. de Jong, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 499, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). M. J. Scholten. J. Schoonman, J. C. van Miltenburg, and H. A. J. Oonk, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 934, D. 146. The Electrochemical Society. Inc., Penninaton. NJ (1993). R. F. Singer, J. R. Rohr, and A. Belzner, Exr. Abs. %O Fuel Cei Seminar, Phoenix, AZ, November 1990, p. 111, National Fuel Cell Coordinating Group, Washington, DC (1990). E. Ivers-Tiff& W. Wasing, and B. Reichelt, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 137, National Fuel Cell Coordinating Group, Washington, DC (1990). H. Landes and K. Mund, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p, 135, National Fuel Cell Coordinating Group, Washington, DC (1990). W. Drenckhahn and H.-E. Vollmar, Exf. Abs. 1992 Fuel Cell Seminar, Tucson. AZ, November 1992, p. 419, National Fuel Cell Coordinating Group, Washington, DC (1992). .----I-

443. 444. 445. 446. 447. 448. 449.

Fuel cell technology 450. 451. 452. 453. 454. 455. 456. 451. 458. 459. 460. 461. 462. 463. 464. 465.

466. 461. 468. 469. 470. 471. 472. 413. 414. 415. 416. 411. 418. 419. 480. 481. 482. 483. 484. 485. 486. 487.

649

B. BrtIckner, H. Landes, and B. Ratbjen, Proc. Third InI. Symp. Solid Oxide Fuel Cells. PV 93-4. p. 641, The Electrochemical Society, Inc., Pennington, NJ (1993). E. lvers-Tiff& M. Schiessl, H. J. Oel, and W. Wasing, Proc. Third Inf. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 613, The Electrochemical Society, Inc.. Pennington, NJ (1993). E. Erdler. W. D&&z. H. G. MUller. and R. Scbmidberger, Int. Fuel Cell Con& Proc.. p. 361, MIT& Tokyo (1992). E. Erdle, W. Dcmitz, W. Schafer. and R. Schamm. ELI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 403, National Fuel Cell Coordinating Group, Washington, DC (1992). D. Stolten, E. Monreal. and W. MUller, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 253. National Fuel Cell Coordiiting Group, Washington, DC (1992). R. J. Spilh. K. Znrell, and A. Koch, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 19!)2, p. 257, National Fuel Cell Coordinating Group, Washington. DC (1992). E. K. Erdler, EXI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 666, Fuel Ceil Seminar Organizing Committee, Washington, DC (1994). D. Stolten, E. MONW~,and W. SchItfer, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 303, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). A. Koch and U. Hemld-Schmitt. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 307, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). Z. Li, M. Behrtui. L. Fuerst, and D. St&er, Proc. Third Inl. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 171, The Electrochemical Society, Inc., Pennington. NJ (1993). H. Jansen, H.-P. Buchkremer, D. Stover, and K. Wippexmann, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 752, The Electrochemical Society, Inc., Pennington. NJ (1993). K. Wippermann, U. Stimming, H. Jansen, and D. St(lver. Proc. Third Im. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 180, The Electrochemical Society, Inc., Pennington, NJ (1993). M. R. F. Kuntz, Proc. Third Ink Symp. Solid Oxide Fuel Cells, PV 93-4, p. 301, The Electrochemical Society, Inc.. Pennington. NJ (1993). C. Bleise, J. Divisek, B. Steffen, U. Konig, and J. W. Schultz. Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 861, The ElectmchemicaI Society, Inc., Pennington, NJ (1993). R. Diethelm, K. Honegger, and B. Barp, In?. Fuel Cell Conf. Proc., p. 329, MITI, Tokyo (1992). R. Diethelm and K. Honegger. Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 822, The Electrochemical Society, Inc., Pennington, NJ (1993). A. R. Nicoll. G. Barbezat, and A. Salito, Int. Fuel Cell Conf Proc., p. 285. MITI, Tokyo (1992). K. Sasaki, P. Bohac, and L. J. Gauckler, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 288, The Electrochemical Society, Inc., Pennington, NJ (1993). A. J. McEvoy, K. R. Thampi, and J. Van herle, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 623, The Electrochemical Society, Inc., Pennington. NJ (1993). U. Bossel, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 285, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). M. Morgensen, C. Bagger, and B. Kindl, Ext. Abs. 1992 Fuel Cell Seminar. Tucson, AZ, November 1!)92, p. 399, National Fuel Cell Coordinating Group, Washington, DC (1992). C. Bagger, EXI. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 241, National Fuel Cell Coordinating Group, Washington, DC (1992). M. Morgensen, B. Kindl. and B. Malmgren-Hansen, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 195, National Fuel Cell Coordinating Group, Washington, DC (1990). A. Holt, E. Ahlgren, and F. W. Poulsen, Proc. Third Im. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 562, The Electrochemical Society, Inc., Pennington. NJ (1993). M. Morgensen and T. Lindegaard, Proc. Third Inl. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 484, The Electrochemical Society, Inc.. Pennington. NJ (1993). C. Bagger, E. Henneso, M. Morgensen, Proc. Third Inl. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 756, The Electrochemical Society, Inc., Pennington, NJ (1993). B. Zachau-Christiansen, T. Jacobsen, K. West, and S. Skaarup, Proc. Third Int. Symp. Solid Oxide Furl Cells, PV 93-4, p. 104, The Electrochemical Society, Inc.. Pennington. NJ (1993). N. Christiansen and P. Gordes, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 401, The Electrochemical Society, Inc., Pennington, NJ (1993). P. Gordes and N. Christiansen, Proc. Third Inf. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 414, The Electrochemical Society. Inc., Pennington, NJ (1993). P. Knudsen, C. Bagger, and M. Morgensen, J. Power Sources 49,291 (1994). M. Morgansen, C. Bagger, and P. Knudsen, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 543, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). K. Kendall, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 813, The Electrochemical Society, Inc., Pennington, NJ (1993). R. Odegtid. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 658, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). T. Norby, 0. J. Velle, H. Leth-Olsen, and R. Tunold. Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 473, The Electrochemical Society, Inc., Pennington. NJ (1993). A. Solheim, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 841, The Electrcchemical Society, Inc., Pennington, NJ (1993). T. Sira and M. Ostenstad, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 851, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Koraliussen, K. Nisancioglu, A. Solheim, and R. OdergSrd, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 868, The Electrochemical Society, Inc., Pennington, NJ (1993). D. P. Sutija, T. Norby, P. E. Osborg. and P. Kofstad, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 552, The Electrochemical Society, Inc., Pennington, NJ (1993).

650

488. 489. 490.

491. 492. 493.

494. 495. 496. 497. 498. 499.

500. 501. 502. 503. 504. 505. 506. 507. 508. 509. 510. 511. 512. 513. 514. 515. 516. 517. 518. 519. 520. 521. 522. 523. 524. 525.

A. J. Appleby A. N. Pettov and P. Kofstad, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 220 The Electrochemical Society, Inc., Pennington, NJ (1993). B. Zhu and B.-E. Mellander, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 934, p. 156 The Electrochemical Society, Inc.. Pennington, NJ (1993). B. C. H. Steele, C. A. Leach. R. A. Rudkin, N. Khan, and M. H. Huang. Ext. Abs. 1996 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 123, National Fuel Cell Coordinating Group, Washington, DC (1990). G. M. Christie, P. H. Middleton, and B. C. H. Steele, Proc. Third ht. Symp. Solid Oxide Fuel Cells, PV 934. p. 315, The Electrochemical Society, Inc., Pennington. NJ (1993). P. H. Middleton. H. J. Steiner, G. M. Christie, R. Baker, I. S. Metcalfe, and B. C. H. Steele, Proc. Thirdfnr. Symp. Solid Oxide Fuel Cells, PV 934, p. 542, The Electrochemical Society, Inc., Pennington, NJ (1993). B. C. H. Steele, J. Power Sources 49. 1 (1994). K. Kendall, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 145, National Fuel Cell Coordinating Group, Washington, DC (1990). K. Kendall, Exr. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 265, National Fuel Cell Coordinating Group, Washington, DC (1992). L. Zanibelli, C. Perego, C. Flego. G. Piro, and F. Gagliardi, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 567, National Fuel Cell Coordinating Group, Washington, DC (1992). C. Perego, L. Zanibelli, M. Catrullo, and G. Piro, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 934, p. 454, The Electrochemical Society, Inc., Pennington. NJ (1993). A. Malandrino and M. Chindemi, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 885. The Electrochemical Society, Inc., Pennington. NJ (1993). E. Arato. 0. Paladino. B. Marcenaro. and P. Costa, fnr. Fuel Cell Co& Proc., p. 285. MITI. Tokyo (1992). V. Antonucci, N. Giordano. A. K. Demin, G. Rocchini, F. Padova& and P.-Salvadori. Ext. Abs. 1992 Fuel Cell Seminar. Tucson. AZ. November 1992. D. 332, National Fuel Cell Coordinatina Group, Washington. DC (1992). T. Pagnier, B. Gharbage, and A. Hammou, Proc. Third In& Symp. Solid Ox& Fuel Cells. PV $34. i. 575, The Electrochemical Society, Inc., Pennington, NJ (1993). A. Hammou, E. Djurado, C. Roux, and C. Micheau. Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 934, p. 48, The Electrochemical Society, Inc., Pennington, NJ (1993). M. I. Osendi and J. R. Jurado, Proc. Third Ink Symp. Solid Oxide Fuel Cells, PV 93-4, p. 82, The Electrochemical Society, Inc.. Pennington, NJ (1993). M. T.Colomer. J. RI Jurado, R. M. C Marques. and F. M. B. Marques, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 934, D. 523, The Electrochemical Society, Inc.. Pennington. NJ (1993). R. M. C. Marques, J. R. Frade, and F. M. B. Marques, Proc. Third In;. Syt&. Solid Oxide Fuel Cells, PV 93-4. p. 513, The Electrochemical Society, Inc., Pennington, NJ (1993). I. V. Yentekakis, S. g. Neophytides, A. C. Kaloyiannis, and C. G. Vayanes, Proc. Third lnt. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 904, The Electrochemical Society, Inc., Pennington, NJ (1993). S. Bebelis. I. V. Yentekakis, S. Neonhvtides, P. Tsiakara, H. Karalasi. and C. G. Vavenas, Proc. Third Inf. Symp. _ _ Solid Oxide Fuel Cells, PV 93-4, p. 926, The Electrochemical Society,~Inc., Penning& NJ (1993). S. P. S. Badwal and K. Forcer. Proc. Third Int. &no. . . Solid Oxide Fuel Cells, PV 93-4.._D. 21, The Electrochemical Society, Inc., Pennington, NJ (1993). N. M. Sammes and M. B. Phillipps, Ext. Abs. J994 Fuel Cell Seminar, San Diego, CA. November 1994, p. 57, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). Y. Denos, F. Morin, and G. Trudel, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 231, The Electrochemical Society, Inc., Pennington, NJ (1993). 0. J. Gross, S. J. Thorpe, and S. Das Guvta. Proc. Third Int. Svmp. Solid Oxide Fuel Cells, PV 93-4, p. 112, The Electrochemical Society, Inc., Penning&. NJ (1993). _ _ H. S. Maiti. A. Chakrabortv. and M. K. Paris. Proc. Third Int. Svmo. Solid Oxide Fuel Cells. PV 93-4. D. . 190, The Electrochemical Society, I&. Pennington, NJ.(1993). - . H. Tagawa, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 6, The Electrochemical Society, Inc., Pennington, NJ (1993). N. Hashimoto, J. Power Sources, 49, 103 (1994). K. Shinozaki and S. Kaneko, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 205, National Fuel Cell Coordinating Group, Washington, DC (1990). K. Shinozaki and T. Satomi, Inf. Fuel Cell Conf Proc.. p. 317. MITI, Tokyo (1992). S. Takeuchi, A. Kusunoki. H. Matsubara, Y. Kikuoka, H. Yokoyama, and S. Kaneko, EXI. Abs. 1994 Fuel Cell Seminar, Son Diego, CA, November 1994, p. 466, Fuel Ceil Seminar Organizing Committee, Washington, DC (1994). S. Takeuchi, A. Kusunoki. H. Matsubara, Y. Kikuoka, J. Ohsuki, T. Satomi, and K. Shinozaki, Proc. Third Inf. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 678, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Shinozaki S. Washio, T. Satomi, and S. Koike, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 684, The Electrochemical Society, Inc., Pennington, NJ (1993). M. Ippommatsu, H. Sasaki. A. Hirano, S. Otoshi, M. Suzuki, and A. Kajimura, Inr. Fuel Cell Conf. Proc., p. 349, MITI, Tokyo (1992). M. Ippommatsu. H. Saasaki, A, Hirano, S. Otoshi, M. Suzuki, A. Kajimura, N. Sugiura, Ext. Abs. 1992 Fuel Cell Seminur, Tucson, AZ, November 1992, p. 249, National Fuel Cell Coordinating Group, Washington, DC (1992). A. Kajimura, H. Sasaki. S. Ohtoshi. M. Suzuki, C. Kurusu. N. Sugiura. and M. Ippommatsu&oc. Third ht. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 395, The Electrochemical Society, Inc., Pennington, NJ (1993). M. Suzuki, H. Sasaki, T. Sogi, A. Kajimura, and E. Yagasaki, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 81, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). M. Suzuki, H. Sasaki. S. Otoshi. A. Kajimura, N. Sugiura. and M. Ippommatsu, Ext. Abs. 1992 Fuel Cell Seminor, Tucson, AZ, November 1992, p. 297, National Fuel Cell Coordinating Group, Washington, DC (1992). M. Ippommatsu, H. Sasaki, S. Otoshi, M. Suzuki, C. Kurusu, A. Kajimura, and N. Sugiura, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 200, The Electrochemical Society, Inc., Pennington, NJ (1993).

Fuel cell technology 526.

A. Shiratori, M. Iha, 0. Chiigawa, H. Takagi. K. Tomono, and K. Agaki. Ext. Abs. 1994 Fuel Cell Seminar, San CA, November 1994. p. 37, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). I. Yasuda. T. Kawashima, T. Koyama, Y. Matauzaki. and T. Hikata. ht. Fuel Cell Co@ Proc., p. 357, MITI, Tokyo (1992). T. Hikita, N. Hishinuma, T. Kawashima. I. Yaauda, T. Koyama, and Y. Matauzaki. Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4. p. 714. The Electrochemical Society, Inc., Pennington, NJ (1993). Y. Matsuzaki. M. Hishinuma, T. Kawashima. I. Yasuda, T. Koyama. and T. Hikita, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 2992, p. 237. National Fuel Cell Coordinating Group, Washington, DC (1992). T. Kawashima, I. Yasuda. Y. Matauzaki, K. Ogasawara. and M. Hishhinuma, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 662, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). T. Hikita, M. Hishimuma, T. Kawashima, I. Yasuda. T. Koyama. and Y. Matsuzaki, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 364, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Kawashiia and M. Hishinuma, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 124, Fuel Cell Seminar Organizing Committee. Washington, DC (1994). K. Eguchi, T. Setoguchi, H. Arai. R. Yamaguchi. and K. Hashimoto. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 269. National Fuel Cell Coordinating Group, Washington, DC (1992). R. Yamaguchi. K. Hashimoto, H. Sakata, H. Kajiwara, K. Watanabe, T. Setoguchi, K. Eguchi. and H. Arai, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4. p. 704, The Electrochemical Society, Inc., Pennington, NJ (1993). K. Eguchi, T. Setoguchi, K. Okamoto, and H. Arai, Int. Fuel Cell Conf. Proc., p. 373, MITI; Tokyo (1992). K. Eguchi, T. Setoguchi, K. Okamoto, and H. Anti, Proc. Third fnt. Symp. Solid Oxide Fuel Cells. PV 93-4, p.494, The Electrochemical Society, Inc., Pennington. NJ (1993). F. Umemura, H. Ohta, K. Amano, T. Saishoji. S. Kaneko, N. Murakami, T. Gengo, and S. Uchida, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 127. National Fuel Cell Coordinating Group, Washington, DC (1990). T. Inoue, H. Yoshida, Y. Esaki. H. Miyamoto. M. Ishibashi, H. Hanada, and K. Takenobu, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 520, National Fuel Cell Coordinating Group, Washington, DC (1990). A. Iwanaga. Yamauchi. N. Hisatome. F. Umemura, and Y. Gchiai. Int. Fuel Cell Conf. Proc., p. 321. MITI, Tokyo (1992). S. Kaneko, N. Hisatome, T. Kabata, K. Nagata, F. Umemura, and T. Saishoji, Ext. Abs. 1992 Fuel Cell Seminar. Tucson, AZ, November 1992, p. 599. National Fuel Cell Coordinating Group, Washington, DC (1992). Y. Yamauchi, Y. Yoshida, N. Hisatome. and F Nanjyo. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 639, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). F. Umemura, K. Amano, H. Michibata, S. Kaneko, Y. Inoue, and K. Kabata, Int. Fuel Cell Conf Proc.. p. 369, MITI, Tokyo (1992). M. Hattori, A. Kate, Y. Esaki, H. Miyamoto, M. Irinoo. S. Naito, F. Nanjo, and K. Takenobu, Int. Fuel’ Cell Conf Proc., p. 325, MITI, Tokyo (1992). M. Hattori, A Kato, Y. Esaki, H. Miyamoto, M. Irino, S. Naito, F. Nanjo, and M. Funatsu, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 411, National Fuel Cell Coordinating Group, Washington, DC (1992). A. Kate, Y. E&i, M. Hattori, S. Naito, F, Nanjo, and M. Nishiura, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 809, The Electrochemical Society, Inc., Pennington, NJ (1993). S. Miyamoto, M. Sumi, K. Mori, I. Koshiro, F. Nanio, and F. Funatsu, Proc. Third Int. Symp. Solid Oxide Fuel Cells.- PV 93-4, p. 504, The Electrochemical Society:Inc., Pennington, NJ (1993). _ _ K. Okumura. Y. Yamamoto. T.. Fukui. S. Hanvu. Y. Kubo, Y. E&i. M. Hattori.A. Kusunoki. and S. Takeuchi. Proc. Third int. Symp. Solid Oxide Fuel Cells, k 93-4, p. 444, The Ehectrochemical Society, Inc., Pennington, NJ (1993). K. Koseki, N. Kusunose, K. Shim& H. Shundo, T. Iwata, S. Maruyama, and T. Nakanishi, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p, 107, National Fuel Cell Coordinating Group, Washington, DC (1990). T. Iwata and H. Shundo, Int. Fuel Cell Conf, Proc., p. 289, MITI, Tokyo (1992). T. Nakanishi, S. Maruyama, and N. Kusunose, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 407, National Fuel Celi Coordinating Group, Washington, DC (1992). T. Iwata and N. Kusunose, Proc. Third fnt. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 792, The Electrochemical Society, Inc., Pennington, NJ (1993). M. Nagata, I. Kaji, S. Yoshida, N. Kobayashi, Y. Seino, and T. Nakjima, Int. Fuel Cell Conf Proc., p. 305, MITI, Tokyo (1992). T. Nakjima, M. Ono, M. Nagata, C. Iwasawa. S. Yamaoka. and Y. Seino, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 697, The&ctrochemical Society, Inc., Pennington. NJ (1993). _ . T. Shirakawa. S. Matsuda. and A. Fukushima. Proc. Thirdlnt. Svmo. Solid Oxide Fuel Cells. PV 93-4. .D. 464. The Electrochemical Society, Inc., Pennington, NJ (1993). * ‘ M. Shimotsu, M. Izumi, and K. Murata, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 732, The Electrochemical Society, Inc., Pennington. NJ (1993). A. Shiratori, S. Kobayashi. K. Taira, Y. Sugimoto, S. Sakamoto. H. Takagi. and Y. Sakabe, fnt. Fuel Cell Conf. Proc., p. 297, MITI, Tokyo (1992). H. Takagi, H. Taira, A. Shiratori, S. Kobayashi, Y. Sugimoto, S. Sakimoto, and K. Tomono, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 738, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Takagi, H. Taira. S. Kobayashi. S. Sakamoto. and K. Tomono. Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 392, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). A. Shiratori, M. Iha, 0. Chikagawa, H. Takagi, and K. Tomono, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 37, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). M. Dokiya, N. Sakai, T. Kawada, and H. Yokokawa, ht. Fuel Cell Co& Proc., p. 309, MITI, Tokyo (1992). N. Sakai. T. Kawada, H. Yokokawa, and M. Dokiya, Int. Fuel Cell Conf Proc., p. 365, MITI, Tokyo (1992).

Diego,

527. 528. 529. 530. 531. 532. 533. 534. 535. 536. 537. 538. 539. 540. 541. 542. 543. 544. 545. 546. 547. 548. 549.

550. 551. 552. 553. 554. 555. 556. 557. 558. 559.

651

652

562. 563. 564. 565. 566. 561. 568. 569. 570. 571. 512. 573. 574. 575. 516. 571. 518. 579. 580. 581. 582. 583. 584. 585. 586. 58-i. 588. 589. 590. 591. 592. 593. 594. 595. 596. 597. 598.

A. J. Appleby H. Yokokawa, T. Ho&a, N. Sakai. B. A. van Hassel. T. Kawada. and M. Dokiya, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4. p. 364. The Electrochemical Society, Inc., Pennington. NJ (1993). S. Kawasaki. Y. Aihara, K. Yoshioka, T. Takahashi. and T. Soma, Proc. Third lnr. Symp. Solid Oxide Fuel Cells. PV 93-4, p. 385, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Tsmteizumi. E. Mat&a, K. Kadowaki. T. Shiomitsu. H. Nakagawa, Y. Watanabe, and T. Yokosuka, Inf. Fuel Cell Co@. Proc.. p. 293, MITI, Tokyo (1992). T. Matsushima. M. Takahashi. and T. Oaata. Ext. Abs. 1994 Fuel Cell Seminar, San Dieno. CA, November 1994, p. 132. Fuel CeB Seminar Organizing Committee, Washington, DC (1994). T. Ishii, T. Iwata, and Y. Tajima, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 59, The Electrochemical Society, Inc., Pennington, NJ (1993). S. Murakami, Y. Akiyama. N. Ishida. T. Yasuo, S. Taniguchi, T. Saito, and N. Furukawa, Int. Fuel Cell Co@ Proc., p. 301, MITI, Tokyo (1992). Y. Akiyama, N. Ishida, T. Yasuo. S. Taniguchi. S. Murakami, T. Saito, and N. Furukawa, Exf. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 603. National Fuel Cell Coordinating Group, Washington, DC (1992). S. Taniguchi, M. Kadowaki, H. Kawamura, T. Yasuo. Y. Akiyama, Y. Miyake, T. Saitoh, and M I-Ian&, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 41, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). Y. Aki$ma. T. Yasuo; N. Ishida, S. Taniguchi. and T. Saito, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4. D. 724. The Electrochemical Societv. Inc.. Penninaton. NJ (1993). T. H&ina,T. Yoshida, and S. Sukurud&Ex~. Abs. I990 Fuel dell Seminar, Phoenix, AZ, November 1990, p. 516, National Fuel Cell Coordinating Group, Washington, DC (1990). Y. Someya, T. Yoshida, and S. Sakurada, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 611, National Fuel Cell Coordinating Group, Washington, DC (1992). T. Yoshida, H. Seto. Y. Someya, H. Koide, A. Tsunkoda, and S. Sakurada, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 934, p. 766, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Koide, Y. Someya, and T. Yoshida, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 33, Fuel Cell Seminar Organizing Committee, Washington. DC (1994). H. &to, T. Miyam. A. Tsunoda. T. Yoshida, and S. Sakurada, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 934, p. 421, The Electrochemical Society, Inc., Pennington, NJ (1993). M. Aizawa, H. Nishiyama. A. Ueno. M. Ku&hi. K. Eguchi, and H. Arai, Proc. Third Inf. Symp. Solid Oxide Fuel Cells, PV 934, p. 690, The Electrochemical Society, I& Pennington. NJ (1993). T. Tachibana. N. Nakashima, A. Sakamoto. A. Ueno. M. Kuroishi. M. Aizawa, K. Eguchi. and H. Arai, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 511, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). A. Momma, Y. Kaga, F. Uchiyama, K. Tsukamoto. and T. Okuo, Inf. Fuel Cell Co@ Proc., p. 381, MITI, Tokyo (1992). S. Nagata and Y. Kasuga, Inr. Fuel Cell Conf. Proc.. p. 345, MITI, Tokyo (1992). F. Uchiyama. K. Tsukamoto. Y. Kaga. T. Okuo,_A. Monma. Y. Ohno, S. Yamaoka, Y. Takahagi, and T.Kamosida, Int. Fuel Cell Conf Proc., p. 281, MITI, Tokyo (1992). M. Mori. H. Itoh. N. Mori, and T. Abe, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 325, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Itoh. M. Mori, N. Mori, and T. Abe.. J. Power Sources 49,315 (1994). H. Taimatsu, K. Wada. and H. Kaneko, Int. Fuel Cell Co& Proc., p. 377. MITI. Tokyo (1992). H. Kaneko, J. Fuxue, and H. Taimatsu, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 934, p. 31, The Electrochemical Society, Inc., Pennington, NJ (1993). Z. Takehara and K. Kanamura, Int. Fuel Cell Conf Proc., p. 341, MITI, Tokyo (1992). T. Ogawa, T. Ioroi, Y. Uchimoto, Z. Ogumi, and Z. Takehara, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 479, ‘Ihe Electrochemical Society, Inc., Pennington, NJ (1993). 0. Yamamoto. Y. Taskeda, N. Imanishi. K. Kohno. and T. Kawahara, Inr. Fuel Cell Conf. Proc., p. 385, MITI, Tokyo (1992). 0. Yamamoto, Y. Takeda, N. Imanishi, and Y. Sakaki, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 205. The Electrochemical Society, Inc., Pennington, NJ (1993). H. Iwahara, T. Hibino, and M. Yamada, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 131, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Ishihara, T. Kudo, H. Mat&a, Y. Mizuhara. and Y. Takita. Proc. Third Inl. Symp. Solid Oxide Fuel Cells, PV 93-4, pM 65, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Mats& T. Ishihara, Y. Mizuhara, and Y. Takita, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 934, p. 129. The Electrochemical Society, Inc., Pennington, NJ (1993). K. Tomida, T. Namikawa, and Y. Yamazaki, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4. p. 14, The Electrochemical Society, Inc., Pennington, NJ (1993). N. Tomita, T. Namikawa, and Y. Yamazaki, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 656, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Yamada, and H. Nagamoto, Proc. Third Im. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 213, The Electrochemical Society, Inc., Pennington, NJ (1993). H. Kamata. J. Misusaki, and H. Tagawa. Int. Fuel Cell Co& Proc., p. 389, MITI. Tokyo (1992). J. Mizusaki. H. Tagawa;T. Saito, K. Kamitani. T. Yamamura. K. Hirano, S. Ehara, T. Takagi, T. Hikita. M. Ippommatsu, S. Nakagawa, and K. Hashimoto, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 533, The Electrochemical Society, Inc., Pennington, NJ (1993). M. C. Williams and D. A. Berry, Ext. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 306, National Fuel Cell Coordinating Group, Washington, DC (1990). D. M. Rastler, G. Devon, R. Castle, and C. Chi. Ext. Abs. I992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 186. National Fuel Cell Coordinating Group, Washington. DC (1992).

Fuel cell technology 599. 600. 601. 602. 603. 605. 606.

Z: 609.

610. 611. 612. 613. 614. 615. 616. 617. 618. 619. 620. 621. 622. 623. 624. 625. 626. 627. 628. 629. 630. 631. 632. 633. 634. 635. 636. 637. 638. 639. 640.

653

G. Steinfeld. S. J. Mevers. and W. B. Hauserman. Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ. Nove,mber 1992, p. 113, Nati&aI Fuel Cell~Coordinating Group. Washington, DC (1992). J. H. Hirschenhofer. D. B. Stauffer. and J. S. White, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992. p. 317. National Fuel Cell Coordinating Group, Washington, DC (1992). D. B. Stauffer, J. H. Hirschenhofer. and J. S. white, Eti. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994. p. 562. Fuel Cell Seminar Organizing Committee, Washington, DC (1994). D. B. Stauffer, J. H. Hirschenhofer, and J. S. White, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 321, National Fuel Cell Coordinating Group, Washington, DC (1992). W. R. Dunbar, R. A. Gaggioli. and A. Khandkar, Int. Fuel Cell Conf. Proc., p. 333. MITI, Tokyo (1992). J. Hartvigsen, S. Elangovan. and A. Khandkar. Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 878, The Electrochemical Society, Inc., Pennington, NJ (1993). R. Gibson, N. Mirth, and L. Schipper, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 528, National Fuel Cell Coordinatina Group, Washington, DC (1992). R. Kumar, M. Krumpelt, and i<. M. Myles, Pr& Third in?. Syrup. Solid Oxide Fuel Cells, PV 93-4, p. 948. The Electrochemical Society, Inc., Pennington. NJ (1993). M. Krumpelt. R. Kumar, and K. M. Myles. J. Power Sources, 49,37 (1994). J. L. Carson, Proc. 30th. IECEC Meeting, Orlando, FL, August 1995, p. 3-229, American Society of Mechanical Engineers, New York, NY, 1995. D. Jansen. A. B. J. Oudhuis. and J. S. Ribberink, Ext. Abs. 1992 Fuel Cell Seminar, Tucson. AZ, November 1992, p. 344. National Fuel Cell Coordinating Group, Washington, DC (1992). D. Jansen, P. C. van der Laag, A. B. J. Oudhuis. and J. S. Ribherink, J. Power Sources 49, 151 (1994). R. Hendriks, Heron Turbine Proforype Test Resulfs, 20th International Congress on Combustion Engines, CIMAC, London. 1993. L. J. M.. J. Blomen, , Private Communication (October 1993). A. de Groot. M. G. Mever. and N. Woudstra. Ext. Abs. 1994 Fuel Cell Seminar, San Diego. CA, Novemlper 1994. D. 619, Fuel Cell Seminar~Organizing Committee, Washington, DC (1994). W. He, J. Power Sources 49,283 (1994). E. Reinsche and H. Fedders, Proc. Third Int. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 913, ‘Ihe Electrochemical Society, Inc., Pennington, NJ (1993). P. Kraus, J. Power Sources 49, 53 (1994). C. L. Laursen, L. J. Christiansen, and N. R. Udergaard, EXL Abs. 1990 Fuel Cell Seminar, Phoenix. AZ. November 1990, p. 44, National Fuel Cell Coordinating Group, Washington, DC (1990). A. RamskOld. N.-E. Carlstedt. and L. Spante, Ext. Abs. 1992 Fuel Cell Seminar, Tucson, AZ, November 1992, p. 585, National Fuel Cell Coordinating Group, Washington, DC (1992). J. P. Shoesmith, R. D. Collins, M. J. Oakley, and D. K. Stevenson, J. Power Sources 49, 129 (1994). 0. Togari. EXI. Abs. 1990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 199, National Fuel Cell Coordinating Group, Washington, DC (1990). Y. Morita, N. Morita, M. Hayasaka, and T. Horie, EXI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 112, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). E. Koda. Proc. Third Symp. on Molten Carbonate Fuel Cell Technology, PV 93-3, p. 75, The Electrochemical Society, Inc., Pennington. NJ (1993). M. Dokiya, T. Horita, N. Sakai, T. Kawada, H. Yokokawa, B. A. van Hassel, and C. S. Monross, Proc. Third Inr. Symp. Solid Oxide Fuel Cells, PV 93-4, p. 918, The Electrochemical Society, Inc., Pennington, NJ (1993). T. Take, M. A&chi, and T. Kyashiki, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1!)94, p. 277, Fuel Cell Seminar Organizing Committee, Washington, DC (1994). M. Ippommauu, H. Sasaki, A. Hirano, and K. Ishimaru, Ext. Abs. I990 Fuel Cell Seminar, Phoenix, AZ, November 1990, p. 168, National Fuel Cell Coordinating Group, Washington, DC (1990). S. S. Penner, ed., Assessment of Research Needs for Advanced Fuel Cells, Pergamon, New York (1986); Energy 11. l-230 (1986). J. GM. Bockris and A. J. Appleby, Energy 11.95 (1986). A. J. Appleby and E. B. Yeager, Energy 11, 137 (1986). J. T. Brown, Energy 11,209 (1986). S. B. Sanders and R. W. Merkle, Proc. 30th. IECEC Meeting, Orlando, FL, August 1995, p. 3-187, American Society of Mechanical Engineers, New York, NY, 1995. W. P. Teagan and A. L. Marge, Proc. 30lh. IECEC Meeting, Orlando, FL, August 1995, p. 3-191, American Society of Mechanical Engineers, New York, NY, 1995. R. R. Muller and J. H. Hirschenhofer, Proc. 30fh. IECEC Meeting, Orlando, FL, Augusr 1995, p. 3-199, American Society of Mechanical Engineers, New York, NY, 1995. Electric Power Research Institute (EPRI), Distributed Generalion Assessmem Guidelines - A Market-Based Framwork for Evaluating High-Value ADDhli0ft.T. TR-102532. EPRI Palo Alto. CA. 1993. i<. B. Prater, j. Power Sources 51, 129 (1994). D. S. Watkins and B. C. Peters, Ext. Abs. 1994 Fuel Cell Seminar, San Diego, CA, p. 250, Fuel Cell Seminar Organizing Committee, Washington, DC, 1994. R. B. Fleming and J. A. Gunscher, Proc. 30th. IECEC Meeting, Orlando, FL, August 1995, p. 3-183, American Society of Mechanical Engineers, New York, NY, 1995. K. B. Prater. Presentation at the Fourth Grove Fuel Cell Symposium. London, September 1995. D. P. Wilkinson, H. H. Voss, and K. Prater, J. Power Sources 49, 117 (1994). H. H. Voss, D. P. Wilsinson, P. G. Pickup, M. C. Johnson, and V. Basura, Elecrrochim. Acfa 40. 321 (Y1994). R. Fiskum and F. Chen, EXI. Abs. 1994 Fuel Cell Seminar, San Diego, CA, November 1994, p. 246, Fuel Cell Seminar Organizing Committee, Washington, DC (1994).