An off-peak energy storage concept for electric utilities: Part I—Electric utility requirements

AN OFF-PEAK ENERGY STORAGE CONCEPT FOR ELECTRIC UTILITIES: PART I--ELECTRIC UTILITY REQUIREMENTS V. T. SULZBERGERtand Y. Z. EL-BADRY+ +

Public ServiceElectricand Gas Company,tt Newark. New Jersey 07101 (USA) and J. E. CLIFFORD and E. W. BROOMAN

Battelle's Columbus Laboratories, Columbus, Ohio 43201 (USA) SUMMARY The water battery, a reversible water electrolyser device being developed in a longterm research effort at Battelle's Columbus Laboratories, was evaluated in an analytical and conceptual design study as a load-levelling system Jor an electric utifity. During periods when off-peak electrical power was available, the water battery would produce hydrogen and oxygen by electrolysis of water," during peak demand periods the water battery would be operated in the reverse mode,Junctioning as ajuel cell by producing electrical power through the recombination of the o.r,ygen and hydrogen held in its storage vessels. The analysis involved characterisation o/the PSE&G system demand requirements n o : and in the filture, its current off-peak energy availability, the typical sizing and placement of energy storage units and the approximate break even economics and potential advantages to the utility of a water battery energy storage system. In the economic analysis, the water batter), was compared with the gas turbine and the Juel cell Jor cost effectiveness in meeting peak and intermediate power demands, respectively. Compared with a 'rejormer-type' Juel cell (costed at $300/k WJbr intermediate duty) the break even capital cost oJa 50 % ejficient water batter), would be $100/k W plus about $200/k W jbr each increase of $1/106 Btu above the rejbrence cost of $1 / 106 BtuJbr Jbssilfuel. The available margin would increase about $50/k WJbr each t Present address: Exxon Enterprises, Inc., New York (USA). ++Present address: Stanley Consultants, Inc,, Iowa (USA). *t PSE&G, as a co-sponsor of this study, neither takes a position for or against nor endorses the water battery storage concept over other energy storage systems currently being developed for possible future utility application. No technical evaluation of the water battery conceptual design was made by PSE&G as the laboratory results were not made available to PSE&G on the operation of the reversible electrolyser/fuel cell used as a basis for the water battery system conceptual design. It should also be noted that the results of this study are based on 1973 data. 167 Applied Energy (3) (1977)--',()~ Applied Science Publishers Ltd, England, 1977 Printed in Great Britain

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decrease of l m i l l / k W h in off-peak energy cost below the rejerence cost of 8 mills/k Wh. In a similar comparison with the gas turbine (costed at $135/k W) jor peaking duty, the break even cost oja 50 ~o efficient water batter)' would be $100/k W. The break even cost could rise about $100/k WJbr each increase in Jossiljuel cost oj ~ $1/106 Btu and about $ 2 0 / k W jor each decrease in off'peak energy cost of I mill/k Wh.

INTRODUCTION

The water battery (reversible water electrolyser or regenerative hydrogen/oxygen fuel cell), as envisioned by Battelle's Columbus Laboratories, is a single energy storage device with long operational life and high storage efficiency suitable for use on an electric utility system at dispersed locations (e.g. substations). Available offpeak electric energy could be used to electrolyse water, thereby generating hydrogen and oxygen which can be stored externally to the device. These gases in turn could be recycled, as necessary, through the same device, operating in reverse, to generate direct-current electricity to meet utility system peak load demands. To evaluate the economic and technical merits of a water battery as an energy storage device on an electric utility system, an analytical and design study was performed during 1974 as a joint effort by Battelle's Columbus Laboratories and Public Service Electric and Gas Company. The specific objectives of the joint BCL/PSE&G study were twofold: (1) (2)

To determine the technical and economic impact of the water battery concept on an electric utility system. To develop a conceptual water battery design based on the requirements of an electric utility system.

Utility system electric loads vary from hour to hour, day to day and season to season. These load variations result in typical annual system load factors ranging from about 40-80 ~o. System generating capacity is installed to meet the annual peak daily load requirements with a certain degree of reliability, Therefore, the amount of total installed generating capacity is generally in the range of 15-25 ~o higher than the system's peak demand. Because of the difference between the variations in the system load profile and the reserve margin of generation capacity at any time, a portion of a system's base-load capacity may be unused during off-peak (or light load) periods. This availability of off-peak base-load generating capacity makes energy storage concepts attractive to utilities because of the potential savings which could result from storing the low cost off-peak energy for use in supplying later peakload requirements. 1 The benefits of electrochemical energy storage devices are expected to be realised more fully in conjunction with nuclear base-load power

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plants, which offer optimal economy of operation, rather than with fossil fuel baseload plants where, because of the need for lower sulphur content fuel to meet air pollution control requirements, the fuel supply is limited, unstable and increasing in cost. Peak-shaving requirements have been met to some extent in the past by use of pumped hydrostorage on electric utility systems. 2 Lack of acceptable sites for future pumped storage systems has increased the desirability of developing alternative offpeak energy storage concepts. Electrochemical energy storage systems are potentially attractive for use by electric utilities. 3 The two general types of electrochemical systems being considered are: rechargeable chemical batteries 4'5 (e.g. lithium-sulphur batteries ° and lead-acid batteries 7) and hydrogen systems, s'9 One type of hydrogen system is based on a water electrolysis subsystem, which generates the hydrogen, 1° a metal hydride subsystem, which stores the hydrogen 11.~2 and a hydrogen/air (oxygen) fuel cell subsystem, which produces electricity. The electrolyser/fuel cell combination (two separate devices), with hydrogen (and possibly oxygen) storage facilities, constitutes a viable off-peak energy storage system. (This use of a fuel cell is distinguished from a 'reformer-type" fuel cell operating on fossil fuels--as a source of hydrogen--to generate intermediate power. 13) The water battery (or reversible electrolyser) is different from the hydrogen system described above in that the water battery uses the same hardware or device to perform both the water electrolysis and the fuel cell function within a closed system, recycling the water and gases between the device and its storage facilities. The general concept of using a single device for off-peak energy storage is not new. 14 The term "regenerative (hydrogen/oxygen) fuel cell" has been used to describe several different concepts that were variations of fuel cell technology developed for space applications. These include a single electrolyser/fuel cell device with internal gas storage15 17 and separate electrolyser and fuel cell devices in a common unit with internal gas storage,1 ~ and separate water electrolysis and fuel cell subsystems with external gas storage.~ ~ The term "reversible water electrolyser' would distinguish the BCL concept as a single device that is an outgrowth of research on water electrolysis cells with long operating life. 2°-24 Since the reversible electrolyser is a type of rechargeable electrochemical storage battery device, the term "water battery" may be a more descriptive title, as battery terminology (i.e. lithium sulphur, lead-acid) usually denotes one or more of the active materials in the electrical/chemical conversion. Therefore, the term "water battery" is the common nomenclature used for the reversible electrolyser throughout this paper. The use of a single device to perform two functions, water electrolysis and fuel cell power generation, could prove to be an attractive energy storage and generation concept for use on electric utility systems. The technical discussion of this study is divided into two major parts. In this first

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part, economic analyses compare the water battery with gas turbine units and ~reformer-type' fuel cell units for serving peak and intermediate electric load requirements. Approximate break even capital costs for the water battery compared with these generation alternatives are detailed. The effects of water battery efficiency on the break even capital costs are also discussed. Typical daily and weekly duty cycles for use on a utility system are defined and related to the water battery power and energy capacity requirements. In Part II of this paper, detailed conceptual water battery (10 MW) designs are developed on the basis of system requirements for daily and weekly energy storage operating cycles, the presentation of these detailed modular designs include water battery costs in relation to associated hydrogen, oxygen and water storage facilities, and electric power conditioning requirements. Finally, water battery performance characteristics are described for a near-term (1980) baseline 10 MW system in terms of total water battery system cost, efficiency, life, reliability, and environmental impact. Economic and technical targets for future development are discussed, and uncertainties and major problem areas are defined.

ELECTRIC UTILITY REQUIREMENTS

DESCRIPTION OF PSE&G ELECTRIC SYSTEM

Present system Public Service Electric and Gas Company is the third largest combination electric and gas utility in the US both in terms of consumers served and total revenues. The PSE&G electric system territory can be described as basically an urban area located in a 1400-mile 2 strip of New Jersey lying between New York City and Philadelphia. The PSE&G 1973 system summer peak load was recorded as 6816 MW. The projected peak electric loads for PSE&G are about 9200 MW in 1980, 15,700 MW in 1990 and 25,000 MW in the year AD2000. In 1973 PSE&G installed generation capacityconsisted primarily of fossil fuel fired steam units (62'/',,), gas turbine units (35 %0) and some pumped storage (2 ~o) and combined cycle units (1)0). The first and second jointly owned nuclear units (1065 MW each) went into commercial operation in July and December of 1974, respectively. The 1973 PSE&G transmission system consisted primarily of 500 kV, 230 kV and 138 kV overhead facilities totalling about 780 circuit miles. In addition, present 138 kV and 345 kV pipe-type cable installations total approximately 150 miles. This bulk power system supplies about 30 major switching stations which generally step down transmission voltages to 13 or 26kV for serving loads in the range of 100-400 MVA. From these lower voltages the electrical energy is then fed into the subtransmission and distribution systems. In the late 1950s, PSE&G initiated a programme of increasing its distribution

ENERGY

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PART 1 - UTILITY REQUIREMENTS

I71

voltage from 4 kV to 13 kV. The 13 kV substations are served directly from either 230/13 kV or 138/13 kV step-down transformers. More recently, in areas where transmission supply is not feasible, the subtransmission system voltage is being increased from 26 to 69 kV to serve 13 kV substations via 69/13 kV transformers. In total, about 40 transmission supplied 13 kV substations are in service with loads ranging up to 150--180 MVA per station. Long-range (year AD 2000) LU'stem

The long-range generation and transmission expansion plan through to AD 2000 developed for the PSE&G electric system provides an outline to guide shorter-term plans, policy decisions and R&D directions. The generation portion of this longrange expansion plan forecasts an optimum generation capacity mix based on the new types of generation which can reasonably be expected to become available for commercial service by AD2000. The most economic long-range forecast of generation capacity mix for the PSE&G system was found to be the following approximate combination by AD2000: (1) (2)

50 ~'o base-load generating capacity consisting primarily of remote location central stations of nuclear units. 50') 0 peaking and intermediate duty generating capacity consisting primarily of gas turbines, fuel cells, chemical energy storage devices, and some older existing fossil steam units relegated from base-load to intermediate and peaking duty.

Fuel cells and chemical energy storage devices, depending on their costs, size and performance characteristics, could be economically competitive and environmentally attractive for use on electric utility systems. Such smaller capacity modular-sized units, of the order of 10 50 MW could be installed at various dispersed switching station and substation locations throughout a system closer to the load than central station nuclear, fossil or gas turbine units. This dispersed location for generation capacity could result in transmission and distribution plant savings. The transmission portion of the PSE&G long-range expansion plan is greatly affected by the choice of future generating plant types and locations. The transmission plans were developed on the basis of installation of two general types of generating capacity: (1) central base-load nuclear generating stations and (2) dispersed generation plants at various switching station and substation locations throughout the PSE&G territory. In addition, optimum use of existing rights of way was made to minimise the amount of new rights of way required because of environmental constraints and limited amounts of property available in New Jersey. Both UHV A.C. and EHV D.C. were considered as alternatives to 550 kV A.C. for delivering base-load generation. It was concluded that an A,C. transmission system

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V T. SULZBERGER, Y. Z. EL-BADRY, J. E. C L I F F O R D , E. W. B R O O M A N

consisting of a 500kV A.C. network of overhead and underground circuits supported by an underlying 230 kV A.C. network was economic and adequate to meet generation-delivery and load-supply requirements through to AD2000. In addition, 765 kW or UHV voltages may be required for future interregional ties in the 1985 period and beyond.

ELECTRIC UTILITY ENERGY STORAGE REQUIREMENTS

For peaking or intermediate duty generation, chemical energy storage devices could have potential economic and environmental advantages for use on electric utility systems. These units can use relatively low cost base-load off-peak energy for charging, thereby more effectively using base-load generating facilities. The relatively small modular size of these units (10 to 50 MW) could permit installation at dispersed locations, such as switching stations and substations; throughout the utility service area. If such energy storage units can be installed at a capital cost comparable with that of other intermediate or peaking duty generating units, then these units can offer potential overall savings in energy and transmission and distribution plant costs. The attractiveness of energy storage devices is dependent on overall system economics, environmental impact and reliability. The amount of energy storage capacity an electric system can support depends on several factors, including the amount of available base-load off-peak energy for charging, the incremental cost of this off-peak energy, the anticipated duty cycle for the energy storage device, the efficiency and expected life of the device and its capital, operating and maintenance costs.

Base-load off-peak energy Availability: a load and capacity analysis of the PSE&G electric system for a typical year determined the amount of base-load off-peak energy available for charging batteries. This analysis compared average weekday and weekend load shapes for each season with the average (installed capacity modified for maintenance and forced outage) available total seasonal capacity and base-load capacity. For this analysis, the following capacity assumptions were made: 20 ~0 installed generation reserve, 50 ~o of the installed capacity as nuclear base-load generation, a maintenance cycle of 4 weeks per year, and 10 ~o forced outage rate for the base-load generating units. For the peaking and intermediate generating units, a maintenance cycle of 2 weeks per year and a 15 ~0 forced outage rate were assumed. Consistent with generation production cost calculations and scheduling of generation maintenance cycles, the following number of weeks were assumed in each season: spring 6; summer, 20; autumn, 6; and winter 20.

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ENERGY STORAGE PART I--UTILITY REQUIREMENTS

TABLE 1 AVAILABLE

Year

BASE-LOAD OFF-PEAK ENERGY a FOR THE SYSTEM

Peak load Jbrecast h (MW)

Energy [brecast h (106kWh)

PSE&G

Available base-load off:peak energy.lbrevast Amount

1985 1990 1995 2000

12150 15700 19900 25000

ELECTRIC

( 10~ k Wh)

% q[ energy lbreeast

4100 5200 6700 8400

7"5 7.6 7.7 7.8

54240 68600 87100 109500

Based on 50 % base-load generating capacity, 20 ",, installed generation reserve and 53 % system load factor. b Extension of January, 1974, load forecast.

Table 1 shows that a significant quantity of base-load off-peak energy is expected to be available for the years 1985, 1990, 1995 and 2000, if the present system load factor (53 ~ ) is maintained for these years. This energy amounts to about 8 °Jo of the forecasted total annual electric energy and is expected to increase to about 10 ')o if the system load factor decreases to 50 ~o. Assuming a 75 ~,, battery conversion efficiency, the available base-load off-peak energy of Table 1 would be adequate to supply approximately 6'~ 0 of the forecasted total annual electric energy requirements. The above analysis was based only on current system load shapes. The impact of increased use of electric heat, or new consumer devices, such as electric cars, could affect the amount of energy storage capacity the PSE&G system could economically support. Table 2 shows the distribution of the available base-load off-peak energy on a seasonal basis as a percentage of the total available base-load off-peak energy. Also shown are the relative contributions from the average weekdays, Saturdays and Sundays for each season. This energy is relatively evenly divided between weekends TABLE 2 DIS1 R I B U T I O N O[" A~cAILABLE B A S E - L O A D O F F - P E A K E N E R G Y F O R A T Y P I C A L YEAR F O R T H E PSE&G ELECTRIC SYSTEM

Season

Calendar week

Seasonal duration (weeks)

Week o[ Week Ol start termination Spring Summer Autumn Winter

14th

19th

20th 40th 46th

39th 45th 13th

Yearly totals

Available base-load offpeak energy (% o[yearly total) Season total

6 20 6 20

Weekends

Average week

Weekdays

16 39 9 36

10 21 5 21

100

57

Saturday

Sunday

2 4 1 4

4 14 3 11 43

2.7 2.0 1.5 1.8

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v. T. SULZBERGER, Y. Z. EL-BADRY, J. E. C L I F F O R D , E. W. B R O O M A N

(43 ~0) and weekdays (57 %) and is available during all the seasons of the year with the largest percentage available in the summer (39 %). It should be noted that the amount of off-peak energy available during an average week in each season varies from 1.5 to 2.7, the average being about 2 % of the total available off-peak energy. Figure 1 shows in per unit of peak load (MW) the amount of base-load off-peak energy (MWh) available for a typical average full summer week on a daily basis. Also shown is the amount of peak-shaving energy obtainable from this off-peak energy, on the basis of a battery conversion elficiency of 75 ~o- Note that the off-peak energy becomes available for charging on Saturday morning. The off-peak energy stored

o

I0

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E

0.6

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Base-load off-peak energy charging

Available baseload capacity

C

75% efficiency (discharge/charge) Sat [ Sun I Man T ue Wed I The Fri O--Hr--24 Fig. 1. Base-loadoff-peakenergyand correspondingpeak-shavingenergyfor a typicalsummerweekfor the PSE&G system. 0 __1

over the weekend together with the off-peak energy available during the weekdays could be dispatched as needed for shaving peak loads occurring Monday through Friday (weekly cycle) as shown in Fig. 1. Optimum scheduling could be based on a daily cycle, weekly cycle or a combination of the two, depending on the amount of battery capacity installed in the system. Present-day computer models which have been developed to optimise the economic scheduling of pumped hydro-energy storage could be used for scheduling rechargeable battery capacity. The amount of off-peak energy available for charging energy storage devices would increase beyond the estimated 8-10 ~/oof the forecasted annual electric energy requirements if other than base-load generating capacity were used for charging. The optimum economic amount of generating capacity which should be used for this

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175

purpose on a particular system involves an overall long-range system economic analysis. For. this paper only base-load generating capacity is being used for charging. This assumption leads to a conservative estimate of the available off-peak energy. Cost." estimates of the average incremental cost of base-load off-peak energy for charging on the PSE&G system based on the generation mix as described earlier were in the order of 7-8 mills/kWh in 1973. As the cost of fossil fuel increases, the cost of incremental off-peak energy will also increase. However, future base-load generation installations on the PSE&G system are expected to be nuclear. As the amount of nuclear unit capacity increases, it is anticipated that average system incremental base-load off-peak energy costs will decrease with the lower operating and fuel costs which are associated with nuclear units. Further, as the PSE&G base-load generation mix approaches the long-range objective of 50~o nuclear capacity, estimates of the average incremental cost of base-load off-peak energy are anticipated to be in the order of 4 to (optimistically) 2 mills/kWh. Therefore, the potential savings and benefits of energy storage devices are expected to be realised more fully in conjunction with nuclear power plants rather than with base-load fossil fuel plants.

Duty cycles Energy storage devices on electric utility systems will be used to store electric energy during the off-peak (or light-load) periods (charging) for use (discharging) during the periods of intermediate and peak electric load demand. The period of charging followed by a period of discharging is called a cycle. A cycle usually starts (charging) when the storage system is free of energy and ends (discharging) at the same initial condition. In general, these are the three possible duty cycles: ( 1) (2)

(3)

The daily cycle in which the storage system is charged at night and during the early morning hours and discharged during the day's peak-load period. The weekly cycle in which the storage system is charged on the weekend and ~lso during the off-peak periods of the weekdays and discharged during the peak-load periods of the weekdays. The seasonal cycle in which the storage system is charged during weekends and weekdays over several weeks or months and discharged only when system peak-loads occur, which is usually during the summer (and possibly winter) season.

Since it is anticipated that the first application of chemical energy storage devices on the PSE&G system will be at the transmission-supplied 13 kV substations, a broad-brush analysis was made to determine the specifications of the duty cycles for energy storage devices at such locations. A transmission-supplied 13 kV substation having a load profile regarded as being typical or representative of the PSE&G

176

V.T. SULZBERGER, Y. Z. EL-BADRY, J. E. CLIFFORD, E. W. BROOMAN

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I.O

(/3

(33

0.8 r-

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co -~ 04 I1) c

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0.0

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Mon

Tue

I Wed

Thu

Fri

L o a d profile of a typical t r a n s m i s s i o n supplied 13 kV s u b s t a t i o n on the P S E & G electric system.

system load profile was chosen for this analysis. Figure 2 shows the substation's average weekly load profile for the summer season. The ordinate in Fig. 2 is in per unit of peak load or power delivered (i.e., kW or MW) and the area under the load curve is energy delivered (i.e., kWh or MWh). If an energy storage system were installed at this substation, it would operate to shave the peak load and to level the demand (to one level if possible). Figures 3 and 4 show for the 13 kV substation a typical simulation for the operation of an energy storage system with a 50 ~o efficiency on a daily and weekly cycle, respectively. As shown in Fig. 3, for a daily cycle, the characteristics of this particular substation load profile indicate that about 8-10 h are available for charging on Monday through to Friday. Each charging period would be followed by a discharge for 12 h. As shown in Fig. 4, for a weekly cycle, additional charging can be accomplished over the weekend, for example, 8 h of charging on Saturday morning and 18 h on Sunday. An intervening discharge at half rated power (5 MW) on Saturday, might be required. Each substation would have a slightly different load requirement. The daily cycle would require the minimum energy storage capacity (kWh), the weekly cycle would require more than twice ( ~ 2.3 times) the energy storage capacity required by the daily cycle, and the seasonal cycle would require as much as 50 times the energy storage capacity of the daily cycle. The weekly and seasonal cycles have the potential of utilising most of the available base-load off-peak energy. However, the seasonal cycle was excluded as a viable cycle

177

ENERGY STORAGE PART I--UTILITY REQUIREMENTS

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Mon

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)--Hr--24 Base-load off-peak energy and corresponding peak-shaving energy for a typical 13 kV PSE&G substation based on the daily cycle (50 % efficiency).

Fig. 3.

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Base.load off-peak energy and corresponding peak-shaving energy for a typical 13 kV PSE&G substation based on the weekly cycle (50 % et~ciency).

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V.T. SULZBERGER, Y. Z. EL-BADRY, J. E. CLIFFORD, E. W. BROOMAN

because of the prohibitive energy storage capacity required. The daily cycle is limited to only the base-load off-peak energy available on weekdays or about 60 % of the base-load off-peak energy available on an annual basis. The power capacity (kW) that can be economically supported by the PSE&G system depends, amongst other factors, on the type of duty cycle utilised. The weekly cycle would allow the installation of almost twice the power capacity of the daily cycle. This is because the weekly cycle uses the base-load off-peak energy available on the weekends in addition to that available during the weekdays.

E

0 A::

I0 MW

=

20 MW

(.o

30 MW

75 % efficiency 50% efficiency

Fig. 5.

Daily duty cycle specification for an energy storage device ( 10 MW) at a typical 13 kV substation on the PSE&G electric system.

Daily: Fig. 5 shows the specifications for an energy storage device operating on a daily cycle at a typical substation. These specifications are sized for a 10 MW (discharging) energy storage device with an efficiency of either 50 or 75 %. This device would operate in the discharging mode at rated output capacity for about 12 h every weekday and in the charging mode for about 8 h. The required charging power capacity is about three times the rated output power capacity for a 50 % efficient device and about twice the rated output power capacity for a 75 ~o efficient device. The energy storage capacity requirement is defined with reference to the energy to be provided on discharge. For the daily power output of 10 MW for 12 h, the energy storage capacity required is 120MWh. An energy storage system with a 50% efficiency would require an energy input of 240 MWh. For charging to be completed in 8 h, the charging power requirement would be 30 MW. An energy storage system with a 75 '~',;efficiency would require an energy input of 160 MWh. For charging to be completed in 8 h, the charging power requirement would be 20 MW. Thus, the input power and input energy depend on the efficiency of the device. For the same energy storage capacity of 120 MWh and the same discharge time, the energy storage device with 50 % efficiency discharging at a lower voltage per cell

179

ENERGY STORAGE PART I--UTILITY REQUIREMENTS

will require more hydrogen and oxygen gas storage capacity than a device with 75 ~o efficiency (e.g., about 25 ~o more gas storage capacity). Weekly." Fig. 6 shows the specifications for an energy storage device operating on a weekly cycle at a typical substation. These specifications are sized for a 10 MW (discharging) energy storage device with an efficiency of either 50 or 75 ~. This device would operate in the discharging mode at rated output capacity for about 12 h every weekday and in the charging mode for about 8 h every day except Sunday, when it would operate for about 18 h. The required charging power capacity is about twice the rated output power capacity for a 50 ~o efficient device and about 1.3 times the rated output power capacity for a 75 ~o efficient device. The lower charge-todischarge rate and power ratio for the weekly cycle compared with the daily cycle are advantageous in achieving a slightly higher efficiency or reduction in water battery size.

Weekly Cycle .~

Sot

I sun !

Tue .i_ w.

Thu

5

--]

I0 MW a

l--

15.3 MW

20 MW efficiency ~ - - 50% efficiency Fig. 6.

Weekly duty cycle specification for an energy storage device (10MW) at a typical 13kV substation on the PSE&G electric system.

For either a 50 o or 75 '!~oefficient device, the energy storage capacity requirement is estimated to be about 280 MWh for a weekly cycle. However, the hydrogen and oxygen gas storage capacity requirement of a 50 '~.~,efficient device based on a weekly cycle will again be about 25'~o more than the 75 ,~,, efficient device. Sizing o/ energy storage systems at substations The load profile of the typical 13 kV substation (Fig. 2)was also used to provide a rough estimate for the maximum energy storage device power (MW) and energy storage capacity (MWh) requirements that could be installed at such locations. The capacity that can be installed at the substation depends on the load profile, the efficiency of the energy storage system and the duty cycle. For a daily cycle, the power capacity (MW) of the energy storage system (50 ~Jo efficiency) that can be installed at substations is estimated to be about 10 ?,/oof the

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V . T . SULZBERGER, Y. Z. EL-BADRY, J. E. C L I F F O R D , E. W. B R O O M A N

station peak load, i.e. about 15-20 MW for PSE&G transmission-supplied 13 kV substations. For a weekly cycle, the power capacity of an energy-storage system (50 ~o efficiency) that can be installed at substations is about 15 ~ of the station peak load, i.e. about 25-30 MW for a PSE&G transmission-supplied substation. Because of these power capacity sizes, a 10 M W module water battery was selected as the size for the detailed water battery conceptual design work. In addition to considering the power capacity (MW) that can be installed, it is important to estimate the required corresponding energy storage capacity when evaluating an energy storage system. In this case, the energy storage capacity (MWh) is estimated to be about 28 and 12 MWh per each MW of installed power capacity for the weekly and daily cycles, respectively. This means that, for a 10 MW energy storage device having 50-75 ~o efficiency, the energy storage requirements are about 280 and 120 MWh for weekly and daily cycles, respectively. TABLE 3 ELECTRIC ENERGY STORAGE DEVICE POWER AND ENERGY CAPAClTY REQUIREMENTS AT A TYPICAL 13-kV SUBSTATION ON THE PSE&G ELECTRIC SYSTEM

Type of duty cycle

Weekly Daily

Typical power capacity requirements at indicated device eJficiency (MW)

Typical energy storage capacity requirement at indicated device efficiency (MWh)

50 ~o

75 °/o

50 ')o

75 ~o

25 15

35 20

700 180

980 240

Table 3 summarises these power and energy capacity requirements for a typical electric energy storage device installation at 13 kV substations for devices with efficiencies of 50 and 75 ~o based on both the daily and weekly duty cycles. Estimates for modular construction of a water battery indicated that the unit cost (dollar/kW) does not vary much with power capacity. Thus, for this economic study, a 10 MW power capacity was selected with an energy storage capacity of 120 MWh (daily cycle) or 280 MWh (weekly cycle) based on a 12 h daily discharge. B r e a k even e c o n o m i c s

The broad-brush economic analysis of the water battery system consisted primarily of determining break even capital costs for the water battery system compared with other non-storage generation capacity alternatives for supplying peaking and intermediate load requirements. This analysis is consistent with and based on the results of the PSE&G long-range generation projection to AD2000. Break even capital costs were developed comparing rechargeable water batteries with other peaking and intermediate duty generating capacity alternatives using assumed unit capital and operating costs and operating characteristics as shown in Table 4.

ENERGY STORAGE PART I--UTILITY REQUIREMENTS

181

TABLE 4 ADVANCEDDESIGNPEAKINGAND INTERMEDIATEGENERATOR UNITCHARACTERISTICS

Type of unit

Gas turbine Fuel cell Water battery

Life (years)

30 30 20

Annual fixed charges~ (%)

Full-load heat rate ( Btu/k Wh )

12-7 12.7 13.1 b

12000 8500 ,

O&M Costs Fixed ($/k W/year)

Variable (mills/k Wh)

--

4.0 2.0 1.0

5.4 a

Based on an 8.5 ~o rate of return. b Based on a 30 ~o salvage value for the overall water battery system. ' Water battery round-trip efficiency of 50-75 ~o, including charge and discharge. a Includes cell refabrication every 5 years for baseline system and every 10 years for future system.

The carrying charges for the water battery reflect the fact that about 45-55 ~o of the water battery cell or about 20-30 ~o of the overall water battery system cost is recoverable as salvage because of the noble metals used in the cells. In addition, costs for required cell refabrication about every 5 years are included for the water battery system as operation and maintenance costs. The water battery was assumed to have a shorter life (20 years) than the fuel cell unit (30 years) which resulted in higher carrying charges for the water battery. The alternative methods of providing peak power such as gas turbines or fuel cells would use fossil fuels (e.g. oil or other liquid fuel, natural gas or synthetic gas). The water battery would be charged with off-peak electric energy generated by efficient base-load plants using mainly fossil fuels (oil or coal) in the near term, and predominantly nuclear fuel in the future. Fossil fuel costs for the gas turbine and fuel cell and off-peak energy costs for the water battery were varied over reasonable expected ranges to demonstrate their effect on the battery break even costs. Fossil fuel costs were assumed to increase from about $1/106 Btu to $3/106 Btu as a result of increased demand for low sulphur fossil fuel and diminishing supply. Off-peak energy costs were assumed to decrease from the 1973 incremental costs of about 8 mills/kWh to a future optimistic estimate of 2 mills/kWh, which reflects the effect of an increasing amount of nuclear base-load capacity. If the water battery operated every weekday of the year, on the basis of the duty cycles described previously, the average total time of operation would be 3120 h per year. At this utilisation level the water battery would have to compete with the fuel cell operating on fossil fuels. However, if the water battery is assumed to operate by the duty cycles described previously, but only on selective days of the year, the summer and/or winter season for example, the average total time of operation would have to compete with the gas turbine operating on fossil fuels. Water battery versusjuel cell: an economic analysis compared the rechargeable water battery with the more advanced "reformer-type' fuel cell units, A water battery system having an overall efficiency of 50 ~o was compared with a fuel cell consuming 8500 Btu/kWh of electrical power produced.

182

v.T. SULZBERGER, Y. Z. EL-BADRY, J. E. CLIFFORD, E. W. BROOMAN

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Fig. 7. Break even capital cost for the water battery versus a 'reformer-type' fuel cell (no escalation assumed: levelised costs).

Figure 7 summarises the results of the economic analysis comparing the water battery with the fuel cell alternative. The graph shows in a generalised way the break even capital costs of the water battery system as a direct function of the fuel cell capital costs for cases in which various combinations of fossil fuel and off-peak energy costs were assumed. Figure 7 represents break even costs if no escalation is assumed. It can be viewed as representing levelised break even costs if all capital, fuel and energy costs are levelised. At an assumed capital cost for fuel cells of $300/kW, and estimated costs for fossil fuel of $1/106Btu (1973) and off-peak incremental energy costs of about 8mills/kWh, only a capital cost of about $100/kW could be justified for 50% efficient water batteries. However, for each increase in fossil fuel cost of $1/106 Btu beyond the 1973 cost, an incremental capital cost of approximately $200/kW could be justified for 50 % et~cient water batteries over the fuel cell. Similarly, for each decrease in off-peak energy costs of 1 mill/kWh from the 1973 cost of 8 mills/kWh, an incremental capital cost of approximately $45 to $50/kW could be justified for

ENERGY STORAGE PART I--UTILITY REQUIREMENTS

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water batteries over fuel cells. In the future, at projected fossil fuel costs of $2 to $3/106 Btu and off-peak incremental energy costs of about 2 mills/kWh, capital costs up to about $650/kW could be justified for water batteries. Water battery versus gas turbine." similarly, a water battery system having an overall efficiency of 50% was compared with a gas turbine consuming 12,000 Btu/kWh of electrical power produced. The water battery was again assumed to have a shorter life than the gas turbine unit, which resulted in higher carrying charges for the water battery. A network saving of $25/kW was assumed for water battery installation at substation locations. Figure 8 summarises the results of this economic analysis. As in Fig. 7, Fig. 8 can represent break even costs directly if no escalation is assumed or levelised break even costs if all other costs in Fig. 8 are levelised. At an assumed $135/kW capital cost for the gas turbines, estimated costs (1973) for fossil fuel of about $1/106 Btu and off-peak incremental energy costs of about 8 mills/kWh, only about $100/kW could be justified as the capital cost for a 50 % efficient water battery. For each increase of $1 / 106 Btu in fossil fuel cost beyond the 1973 cost, an incremental capital cost of approximately $100/kW could be justified

184

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for the 50 % efficient water battery over the gas turbine. Similarly, for each decrease in off-peak energy costs of 1 mill/kWh from the 1973 cost, an incremental capital cost of approximately $15/kW to $20/kW could be justified for water batteries over gas turbines. In the future, at projected fossil fuel costs of $2 to $3/106 Btu and offpeak incremental energy costs of about 2 mills/kWh, capital costs of as much as about $350/kW could be justified for water batteries. Sensitivity to ejficiency: Fig. 9 shows the break even capital cost differential for the water battery over the fuel cell as a function of battery efficiency. An improvement in the initial anticipated efficiency of 50 % to the 75 % expected for more advanced water batteries would result in a break even capital cost differential for water batteries over fuel cells of about $125/kW at the 1973 incremental off-peak energy cost of about 8 mills/kWh. With increased amounts of installed base-load nuclear capacity and future optimistic estimates of base-load off-peak energy at about 2 mills/kWh, improvement in water battery efficiency from 50 to 75 ~o results in only a $25/kWh capital cost differential for the water battery over the fuel cell.

ENERGY STORAGE PART 1--UTILITY REQUIREMENTS

185

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Similarly, Fig. 10 shows the water battery gas turbine capital cost differential as a function of water battery efficiency. For base-load off-peak energy costed at 8 mills/kWh, improvements in water battery efficiency from 50 to 75 ~o are worth about $30/kW over the capital cost of a gas turbine unit. For base-load off-peak energy valued at 2 mills/kWh, similar improvements in efficiency can justify only about $10/kW more in capital cost for the water battery over the gas turbine. In the future with anticipated decreasing incremental base-load off-peak energy costs, substantial improvements in water battery efficiency, although desirable, may not be economically justified beyond a certain point in that the capital costs associated with attaining maximum efficiency cannot be amortised over the battery module lifetime. As shown later in Part II of this paper, the maximum potential savings with a water battery do not occur at the highest efficiency attainable. Utility network savings." in addition to the potential generation savings, transmission, station, and subtransmission savings could be realised over the gas turbine units by locating water batteries close to the load at switching stations and substations, as shown in Fig. 11. Credits for transmission and stepdown savings were included in the economic analyses described in the previous sections. Such network savings, however, would not apply in the case of the fuel cell alternative as it is anticipated that fuel cells, like the water battery, will be installed at dispersed switching station and substation locations.

186

V.T. SULZBERGER, Y. Z. EL-BADRY, J. E. CLIFFORD, E. W. BROOMAN

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Table 5 summarises the anticipated utility network savings which may be realised from the installation of generation facilities at dispersed station locations. These network savings result from possibly either reducing and/or delaying the need for new transmission, subtransmission and associated station facilities. Average system savings associated with switching station and substation locations have been estimated to be in the order of $40/kW and $50/kW, respectively. These estimates are based on a mix of overhead and underground transmission and subtransmission facilities.

DI SCUSSION

The results described in this paper are based on a brief economic evaluation of the water battery concept as conceived by BCL for electric utility application. As the study was performed in early 1974 during the initial impact of the so called 'energy crisis', the estimated fuel cost values used in the report are optimistically low. However, the range of results encompass more current and realistic levelised costs.

ENERGY STORAGE PART 1--UTILITY REQUIREMENTS

187

TABLE 5 ESTIMATED UTILITY NETWORK SAVINGS FOR GENERATION INSTALLATIONS AT DISPERSED STATION LOCATIONS

Location

Connection t'~oltage (k IS)

Capacity size ( M W)

Estimated transmission, station and subtransmission savings ($/k W)

Switching station Substation

2(~230 4~34-5

10-200 10 100

Up to 40 Up to 50"

" The network savings depends on the type of dispersed generation, its location and the type of generating capacity the dispersed generation replaces. In the case of the water battery versus the gas turbine with water batteries installed at substation locations, the estimated additional network savings for the water battery are about $25/kW ($15/kW for transmission and about $10/kW for station facilities). These network savings are included in the calculation of break-even costs.

CONCLUSIONS

The results of the analytical and design studies performed indicate that, assuming appropriate research and development work is undertaken, the water battery possesses excellent potential for application as an electric utility load-levelling device during the period 1980-2000. Two factors favouring the water battery energy storage system are (1) the forecasted increase in the use of nuclear energy (50 ~o of capacity by AD2000 in baseload nuclear units) which will decrease off-peak power costs from 8 mills/kWh (1973) to possibly 2mills/kWh, and (2) the projected increase in costs from $1/106 Btu (1973) to $3/106 Btu for fossil fuels consumed in alternative systems employed to meet peak power demand. Compared with the alternative of a 'reformer-type' fuel cell (i.e. $300/kW) for intermediate duty, the break even capital cost of a 50 ~o efficient water battery would be $100/kW plus about $200/kW for each increase of $1/106 Btu above the reference (1973) cost of$1/106 Btu for fossil fuel and plus about $50/kW for each decrease in off-peak energy cost of I mill/kWh below the reference (1973) cost of 8 mills/kWh. In a similar comparison to the alternative of a gas turbine ($135/kW) for peaking duty, the break even cost of a 50 ~o efficient water battery would be $100/kW plus about $100/kW for each increase of $1/106 Btu in fossil fuel cost and about $20/kW for each decrease of 1 mill/kWh in off-peak energy cost.

ACKNOWLEDGEMENTS

In view of the interest which Public Service Electric and Gas Company (PSE&G) and Battelle Columbus share in energy storage, this study was carried out as a joint effort. The Battelle Energy Program Office funded the portion of the study carried out by Battelle Columbus.

188

v.T. SULZBERGER, Y. Z. EL-BADRY, J. E. CLIFFORD, E. W. BROOMAN REFERENCES

1. W. S. Ku and V. T. SULZBERGER,Year 2000 generation and transmission plan, Proceedings of the American Power Conference, Vol. 35 (1973), 485-94. 2. W. S. Ku and C. L. SULZBERGER,Determination of pumped storage requirements and limitations on a long-range system basis, Paper 31, Presented at IEEE Summer Power Meeting, New Orleans, Louisiana (July 10-15), 1966. 3. P. A. LEWIS and J. ZEMKOSKI, Prospects for applying electrochemical energy storage in future electric power systems, Presented at IEEE International Convention, New York, New York (Mar. 26-30, 1973). 4. Y. Z. EL-BADRYand J. ZEMKOSKI,The potential for rechargeable storage batteries in electric power systems, Presented at 9th lntersociety Energy Conversion Engineering Conference (IECEC), San Francisco, California (Aug. 26-30, 1974). 5. W. E. ROSENGARTEN, JR, A. J. KELLEHER and O. D. GILDERSLEEVE, JR, Wanted: load-leveling storage batteries, Presented at Electrochemical Society Meeting, Miami Beach, Florida (Oct. 8-13, 1972). 6. L. A. HEREDY and W. E. PARKINS, Lithium-sulfur battery plant for power peaking, Presented at IEEE Winter Power Meeting, New York (Jan. 30-Feb. 4, 1972). IEEE Conference Paper C 72 234-8. 7. J. T. BROWN and J. H. CRONIN, Battery systems for peaking power generation, Presented at 9th Intersociety Energy Conversion Engineering ConJerence ( IECEC), San Francisco, California (Aug. 26-30, 1974). 8. J. A, CASAZZA,R. A. HUSE, V. T. SULZBERGERand F. J. SALZANO, Possibilities for integration of electric, gas and hydrogen energy systems, Presented at 1974 CIGRE Meeting, Paris, France. 9. J.M. BURGER,P. A. LEWIS,R. J. ISLER,F. J. SALZANOand J. M. KING, JR, Energy storage for utilities via hydrogen systems, Presented at 9th Intersociety Energy Conversion Engineering Conference (1ECEC), San Francisco, California (Aug. 26-30, 1974). 10. W. C. KINCAIDEand C. F. WILLIAMS,Storage of electrical energy through electrolysis, Presented at 8th Intersociety Energy Conversion Engineering Conference ( IECEC), Philadelphia, Pennsylvania (Aug. 12 15, 1973). l 1. G. STRICKLAND,J. J. REILLYand R. H. WISWALL,JR, An engineering scale energy storage reservoir of iron-titanium hydride, Proceedings of the THEME Conference, Miami (1974), Paper $4-9. 12. R. H. WISWALL,JR, and J. J. REILLY,Metal hydrides for energy storage, Presentedat 7th lntersociety Energy Conversion Engineering ConJerence (IECEC), San Diego, California (Sept. 25-29, 1972), Paper 72910. 13. W. J. LUECKEL, L. G. EKLUND and S. H. LAW, Fuel cells for dispersed power generation, IEEE Transactions of Power Apparatus and Systems, 92(1), 230-5 (Jan./Feb., 1973). 14. A. M. ADAMS, F. T. BACON and R. G. H. WATSON, The high pressure hydrogen oxygen cell, Chemical Technology, Vol. 1, Edited by Will Mitchell, Jr, Academic Press, New York (1963). 15. R. F. ASTRIN and M. G. KLEIN, Hydrogen-oxygen electrolytic regenerativeJuel cells, NASA Lewis Research Center, Contract NAS3-10948 (Jan. 1970). 16. L. S. HAROOTYAN and 1, F. LUKE, Cylindrical regenerative Juel cell evaluation, Air Force Aero Propulsion Laboratory, Report AFAPL-TR-71-31 (May 1971). 17. R. L. COSTA and S. S. TOMTER, 20 Watt-hour per pound regenerative fuel cell, Air Force Aero Propulsion Laboratory, Report AFAPL-TR-72-18 (Mar. 1972). 18. J. K. STEDMANand D. B. BAILLIEUL,Dual cell regenerativeJi~el cell investigation, Air Force Aero Propulsion Laboratory, Report AFAPL-TR-72-19 (Apr. 1972). 19. R. A. WVNVEEN and F. H. SCHUBERT, Regenerativefi~el cell subsystem design handbook, NASA, Manned Spacecraft Center, Contract NAS9-12509 (Dec. 1972). 20. E.S. KoLIcand J. E. CLIFFORD, Waterelectrolysiscellsusinghydrogendiffusioncathodes, ContractF 33615-67-C-1515, Technical Report AMRL-TR-68-157 (Feb. 1969). 21. J. E. CLIFFORD, Water vapor electrolysis cell with phosphoric acid electrolyte, Presented at the Aeronautic and Space Engineering and Manufacturing Meeting, Los Angeles, California (Oct. 1967), SAE Paper 670851. 22. B. C. KIM and J. E. CLIFFORD, Carbon dioxide reduction and water vapor electrolysis system, Presented at the Aeronautic and Space Engineering and Manufacturing Meeting, Los Angeles, California, Oct. 1968, SAE Paper 680719. 23. J. E. CLIFFORD,B. C. KIM and E. S. KOLIC, Study of a water vapor electrolysis ujJit, Report NASA CR-1531 (Mar., 1970). 24. J. E. CLIFFORD, A. H. REED and R. H. PRAUSE, Water vapor electrolysis package, Final Report on Contract NAS2-6870 to NASA, Ames Research Center, Moffett Field, California (June, 1973).