IAEA-TECDOC-1584

Advanced Applications of Water

Cooled Nuclear Power Plants

July 2007

IAEA-TECDOC-1584

Advanced Applications of Water

Cooled Nuclear Power Plants

July 2007

The originating Section of this publication in the IAEA was:

Nuclear Power Technology Development Section

International Atomic Energy Agency

Wagramer Strasse 5

P.O. Box 100

A-1400 Vienna, Austria

ADVANCED APPLICATIONS OF

WATER COOLED NUCLEAR POWER PLANTS

IAEA, VIENNA, 2008

IAEA-TECDOC-1584

ISBN 978–92–0–105808–9

ISSN 1011–4289

Printed by the IAEA in Austria

July 2008

FOREWORD

By August 2007, there were 438 nuclear power plants (NPPs) in operation worldwide, with a total

capacity of 371.7 GW(e). Further, 31 units, totaling 24.1 GW(e), were under construction. During

2006 nuclear power produced 2659.7 billion kWh of electricity, which was 15.2% of the world’s total.

The vast majority of these plants use water-cooled reactors. Based on information provided by its

Member States, the IAEA projects that nuclear power will grow significantly, producing between

2760 and 2810 billion kWh annually by 2010, between 3120 and 3840 billion kWh annually by 2020,

and between 3325 and 5040 billion kWh annually by 2030.

There are several reasons for these rising expectations for nuclear power:

• Nuclear power’s lengthening experience and good performance: The industry now has more

than 12 000 reactor years of experience, and the global average nuclear plant availability during

2006 reached 83%;

• Growing energy needs: All forecasts project increases in world energy demand, especially as

population and economic productivity grow. The strategies are country dependent, but usually

involve a mix of energy sources;

• Interest in advanced applications of nuclear energy, such as seawater desalination, steam for

heavy oil recovery and heat and electricity for hydrogen production;

• Environmental concerns and constraints: The Kyoto Protocol has been in force since February

2005, and for many countries (most OECD countries, the Russian Federation, the Baltics and

some countries of the Former Soviet Union and Eastern Europe) greenhouse gas emission limits

are imposed;

• Security of energy supply is a national priority in essentially every country; and

• Nuclear power is economically competitive and provides stability of electricity price.

In the near term most new nuclear plants will be evolutionary water cooled reactors (Light Water

Reactors (LWRs) and Heavy Water Reactors (HWRs), often pursuing economies of scale. In the

longer term, innovative designs that promise shorter construction times and lower capital costs could

help to promote a new era of nuclear power.

About one-fifth of the world’s energy consumption is used for electricity generation. Most of the

world’s energy consumption is for heat and transportation. Nuclear energy has considerable potential

to penetrate these energy sectors now served by fossil fuels that are characterized by price volatility

and finite supply. Advanced applications of nuclear energy include seawater desalination, district

heating, heat for industrial processes, and electricity and heat for hydrogen production. In addition,

since nuclear electricity is generally produced in a base load mode at stable prices, there is

considerable near-term potential for nuclear power to contribute to the transportation sector as a

carbon-free source of electricity for charging electric and plug-in hybrid vehicles.

This collaborative assessment was recommended by the IAEA Nuclear Energy Department’s

Technical Working Groups on Advanced Technologies for LWRs and HWRs (the TWG-LWR and

TWG-HWR). The objective has been to identify opportunities and challenges for water cooled

reactors to capture a substantial share of the above mentioned advanced applications. For each

application, the opportunities, market context, challenges and potential solutions are addressed.

The IAEA appreciates the work of all contributors, listed at the end of this report. The special

contribution of M. Petri from Argonne National Laboratory, United States of America, as Chairman of

this activity is gratefully acknowledged. The IAEA Officers responsible for this report are J. Cleveland

and A. McDonald of the Department of Nuclear Energy.

EDITORIAL NOTE

The use of particular designations of countries or territories does not imply any judgement by the

publisher, the IAEA, as to the legal status of such countries or territories, of their authorities and

institutions or of the delimitation of their boundaries.

The mention of names of specific companies or products (whether or not indicated as registered) does

not imply any intention to infringe proprietary rights, nor should it be construed as an endorsement

or recommendation on the part of the IAEA.

CONTENTS

SUMMARY ............................................................................................................................................ 1

CHAPTER 1. PRESENT STATUS AND OVERVIEW OF ADVANCED APPLICATIONS

OF NUCLEAR REACTORS .........................................................................................9

1.1. Nuclear power reactors in the world.............................................................................10

1.2. Non-electric applications of nuclear power..................................................................11

1.3. Past experience with non-electric applications.............................................................18

1.4. Market potential of advanced non-electric applications ..............................................23

1.4.1. 2003 IAEA study: Market potential for non-electric application

of nuclear energy...............................................................................................23

1.4.2. 2004 NEA study: Non-electricity products of nuclear energy .........................27

1.5. Impact of externalities on cost of power from fossil/ nuclear/

renewable sources .....................................................................................................................28

1.6. Conclusion....................................................................................................................31

References for Chapter 1...........................................................................................................32

CHAPTER 2. NUCLEAR DESALINATION.....................................................................................33

.1. Opportunities ................................................................................................................33

2.2. Market context .............................................................................................................34

2.2.1. Nuclear desalination market - past experiences and plans ...............................34

2.2.2. Economics

........................................................................................................36

2.3. Challenges ....................................................................................................................39

2.3.1. Economics .........................................................................................................39

2.3.2. Infrastructure development................................................................................39

2.3.3. Public perception...............................................................................................39

2.3.4. Socio-environmental

aspects............................................................................40

2.4. Solutions.......................................................................................................................40

2.4.1. Utilization of waste heat from nuclear reactors.................................................40

2.4.2. Waste heat utilization from Indian PHWRs for thermal desalination ...............41

2.4.3. Utilization

of hybrid systems..........................................................................43

2.5. Conclusion....................................................................................................................45

References for Chapter 2...........................................................................................................45

CHAPTER 3. DISTRICT HEATING .................................................................................................46

3.1. Opportunities ................................................................................................................46

3.2. Market context..............................................................................................................47

3.2.1. Early history of nuclear district heating markets [4] .........................................47

3.2.2. Summary of some specific district heating systems of interest.........................50

3.2.3. Economics .........................................................................................................52

3.3. Challenges ....................................................................................................................53

3.4. Solutions.......................................................................................................................54

References for Chapter 3...........................................................................................................56

CHAPTER 4. INDUSTRIAL PROCESS STEAM .............................................................................57

4.1. Opportunities ................................................................................................................57

4.2. Market

context.............................................................................................................58

4.2.1. Past experience..................................................................................................58

4.2.2. Near-term potential............................................................................................61

4.2.3. Economics .........................................................................................................62

4.3. Challenges ....................................................................................................................63

4.4. Solutions.......................................................................................................................64

4.4.1. Oil extraction from Canadian oil sands.............................................................64

4.4.2. Massachusetts Institute of Technology (MIT) study.........................................67

4.4.3. Long

-term possibilities...................................................................................68

References for Chapter 4...........................................................................................................69

CHAPTER 5. NUCLEAR ELECTRICITY FOR TRANSPORTATION:

HYBRID-ELECTRIC VEHICLES ..............................................................................70

5.1. Opportunities ................................................................................................................70

5.1.1. Opportunities in the United States of America..................................................71

5.1.2. Opportunities in Japan.......................................................................................75

5.1.3. Opportunities

in other countries............................................................... 76

5.2. Market context..............................................................................................................78

5.2.1. Market context in the United States of America ...............................................78

5.2.2. Opportunities in Japan.......................................................................................82

5.2.3. Energy utilization efficiencies of various power trains.....................................85

5.2.4. Greenhouse

gas emissions in Japan......................................................... 87

5.3. Challenges ....................................................................................................................88

5.3.1. Barriers to be overcome in the United States of America .................................88

5.3.2.

Barriers to be overcome in Japan..................................................................91

5.4. Solutions.......................................................................................................................90

5.4.1. Solutions in the United States of America ........................................................90

5.4.2.

Solutions in Japan...........................................................................................90

References for Chapter 5...........................................................................................................92

Bibliography for Chapter 5 .......................................................................................................93

CHAPTER 6. ELECTRICITY AND HEAT FOR HYDROGEN PRODUCTION...............................94

6.1. Opportunities ................................................................................................................96

6.2. Market context..............................................................................................................98

6.2.1. Hydrogen as a raw material in chemical processes...........................................99

6.2.2. Hydrogen

as a fuel .........................................................................................102

References for Section 6.2 ......................................................................................................106

Bibliography for Section 6.2...................................................................................................110

6.3. Challenges ..................................................................................................................106

6.4. Solutions.....................................................................................................................111

6.4.1. Hydrogen production technologies..................................................................111

6.4.2. Hydrogen production economics.....................................................................122

6.4.3. Hydrogen production with a combination of nuclear electricity

and wind electricity .........................................................................................127

6.4.4. The environmental benefits of fuel cell vehicles supplied by

nuclear-generated

hydrogen...........................................................................128

References for Chapter 6.........................................................................................................129

ANNEX I. RECENT NUCLEAR DESALINATION DEMONSTRATION PROJECTS .......132

ANNEX II. NUCLEAR DISTRICT HEAT IN SWEDEN AND ROMANIA............................137

ANNEX III. CANDU ENERGY FOR STEAM ASSISTED GRAVITY DRAINAGE...............140

ANNEX IV. LARGE SCALE PROCESS STEAM SUPPLY FROM GÖSGEN-DÄNIKEN

NUCLEAR POWER STATION IN SWITZERLAND ...........................................145

ANNEX V. EVALUATION OF BATTERY COST COMPETITIVENESS OF

ALTERNATIVE TRANSPORTATION TECHNOLOGIES..................................147

CONTRIBUTORS TO DRAFTING AND REVIEW......................................................................... 149

SUMMARY

About one-fifth of the world’s energy consumption is used for electricity generation, and today

nuclear energy contributes approximately 15.2% of the world’s electricity. Most of the world’s energy

consumption is for heat and transportation. Through advanced applications, nuclear energy has

considerable potential to penetrate these energy sectors now served by fossil fuels that are

characterized by price volatility, finite supply, and environmental concerns.

Advanced applications of nuclear energy include seawater desalination, district heating, heat for

industrial processes, and electricity and heat for hydrogen production. In addition, in the transportation

sector, since nuclear electricity is generally produced in a base load mode at stable prices, there is

considerable near-term potential for nuclear power to contribute as a carbon-free source of electricity

for charging electric and plug-in hybrid vehicles.

The applications highlighted in this publication rely on a source of heat and electricity. Nuclear energy

from water-cooled reactors, of course, is not unique in this sense. Indeed, higher temperature heat can

be produced by burning natural gas and coal or through the use of other nuclear technologies such as

gas-cooled or liquid-metal-cooled reactors. Water-cooled reactors have advantages, however. Unlike

fossil-fuel-based plants, water-cooled reactors do not release greenhouse gases. Water-cooled reactors

are being deployed today. Other reactor types have had considerably less operational and regulatory

experience and will take still some time to be widely accepted in the market.

This document examines the potential of nuclear energy to expand into these markets by presenting an

overview of example applications, their opportunities, challenges and solutions. Its scope is limited to

applications that can be served by water cooled reactors, as these represent more than 90% of the

current fleet, and because in the near term most new nuclear plants will be evolutionary water cooled

reactors [(Light Water Reactors (LWRs) and Heavy Water Reactors (HWRs)]. In the longer term,

innovative designs that promise shorter construction times and lower capital costs could help to

promote a new era of nuclear power, especially as non-electricity markets grow. This document does

not address design safety aspects of the coupling of heat utilization systems to nuclear reactors.

The advantage of nuclear energy in alleviating the risk of climate change will not favour market

penetration of advanced applications of nuclear power as long as energy policies internalising the

value of carbon and other pollutants are not implemented. National policies on climate change vary

from country to country, but the entry into force of the Kyoto Protocol in February 2005 does create

incentives that can benefit nuclear power, depending on how they are translated into national policies.

Nuclear energy for seawater desalination

Water is essential for the sustainable development of society. Water scarcity is a global issue, and

every year new countries are affected by growing water problems. Climate change is likely to further

stress regions already facing dire water shortages.

Large-scale commercially available desalination processes can generally be classified into two

categories: (a) distillation processes that require mainly heat plus some electricity for ancillary

equipment, and (b) membrane processes that require only electricity to provide pumping power.

The energy for these plants is generally supplied in the form of either steam or electricity using fossil

fuels. The intensive use of fossil fuels raises environmental concerns, and many countries are therefore

considering the introduction of a nuclear power program or expansion of their existing nuclear power

program.

The desalination of seawater using nuclear energy is a feasible and demonstrated option to meet the

growing demand for potable water. Over 200 reactor-years of operating experience on nuclear

desalination have been accumulated worldwide, and demonstration projects for nuclear desalination

are also in progress to confirm its technical and economical viability. However, today nuclear

desalination contributes only 0.1 % of total desalting capacity worldwide.

Economic feasibility studies generally indicate that water costs (and associated electricity generation

costs) from nuclear seawater desalination are in the same range as costs associated with fossil-fuelled

desalination at their current costs. Therefore, future investment decisions will depend on site-specific

cost factors and on the values of key parameters (capital cost, fuel price, interest rate, construction

time, etc.) at the time of investment.

Those countries suffering from scarcity of water are, generally, not the holders of nuclear technology,

do not generally have nuclear power plants, and do not have a nuclear power infrastructure. The

utilization of nuclear energy in those countries will require infrastructure building and institutional

arrangements for such things as financing, liability, safeguards, safety, and security and will also

require addressing the acquisition of fresh fuel and the management of spent fuel.

The socio-environmental aspects of nuclear desalination need attention for its large-scale adoption.

Setting up a desalination plant at nuclear reactors for providing much-needed fresh water to the public

will no doubt add to social acceptance of nuclear desalination, if the quantity and quality of the fresh

water are consistently assured. Also, nuclear desalination plants must be designed to assure the

continued use of areas for fishing and other socio-cultural activities. Protection of the marine

environment near the desalination plant site needs to be assured. The environmental impact assessment

of nuclear-powered desalination systems further indicates advantages over fossil-based energy

sources. These would result in enhanced economic competitiveness of nuclear desalination plants.

In summary, use of energy from nuclear reactors for seawater desalination is a demonstrated option; it

is environmentally friendly and can be a sustainable energy source. Feasibility studies indicate that

current costs of water produced from nuclear desalination plants are similar to those of fossil fuel

based desalination plants. Thus nuclear desalination is an important option for safe, economic and

sustainable supply of large amounts of fresh water to meet the ever-increasing worldwide water

demand.

Nuclear energy for district heating

District heat involves the supply of space heating and hot water through a district heating system,

which consists of heat plants (usually producing electricity simultaneously) and a network of

distribution and return pipes. Potential applications of district heating are in climatic zones with

relatively long and cold winters. In many countries, such as central and northern European countries

and countries in transition economies, district heat has been widely used for decades.

District heating has the following technical requirements:

• It requires a heat distribution network to transport steam or hot water in a typical temperature

range of 80-150°C;

• Owing to higher losses over longer transmission distances, the heat source must be relatively

close to the customer, typically within 10–15 km;

• The district heat generation capacities are determined by the collective demands of the

customers. In large cities a capacity of 600–1200 MWth is normal. The demand is much lower

in small communities;

• The annual load factor is normally not higher than 50%, since heat is supplied only in the colder

part of the year;

• To assure a reliable supply of heat, a backup capacity is required.

Coal and gas dominate the fuels used for district heating. Various other heat sources are also used for

district heating, including biomass materials, waste incineration, and waste heat from industrial

processes. Usually district heating is produced in a cogeneration mode in which waste heat from

power production is used as the source of district heat.

Several countries (Bulgaria, China, Czech Republic, Hungary, Romania, the Russian Federation,

Slovakia, Sweden, Switzerland and Ukraine) already have experience in nuclear district heating, so the

technical aspects can be considered well proven.

In the past, the low prices of fossil fuels have stunted the introduction of single-purpose nuclear

district heating plants. Although many concepts of small-scale heat-producing nuclear plants have

been presented during the years, very few have been built. However, as environmental concerns mount

over the use of fossil fuels, nuclear-based district heating systems have potential.

In order to be able to compete with fossil-fuel-fired heat boilers, the capital cost per installed MW of

heat production capacity for a nuclear-based system must be such that the production costs are

competitive. Dedicated reactors providing district heat can potentially achieve acceptable costs, due to

their lower temperature operating conditions, simple design, modularization and standardization, and

advanced safety systems.

Economic studies generally indicate that district heating costs from nuclear power are in the same

range as costs associated with fossil-fuelled plants. Therefore, as with nuclear desalination, future

investment decisions will depend on site-specific cost factors and on the values of key parameters

(capital cost, fuel price, interest rate, construction time, etc.) at the time of investment.

New nuclear heat-producing plants must, of course, meet the user’s requirements on availability and

reliability, including alternative heat-producing capacity that could serve as backup. For this purpose,

heat storage allows a matching of the heat supply to the heat demand. Today there are many examples

of short-term storage, for instance, on the daily scale that relies on hot water accumulator tanks. In the

future, more long-term storage facilities may be realized.

The design features of nuclear district heating plants to prevent the transfer of radioactivity into the

district heating grid network have proven to be effective. These features include one or more barriers

to radioactive cross contamination, e.g. in the form of a leak-tight intermediate heat transfer loop at a

pressure higher than that of the steam extracted from the turbine side of the nuclear plant. These loops

are continuously monitored, and isolation devices are provided to separate potentially contaminated

areas.

For nuclear district heating plants, proximity to population centres implies the need for a high degree

of safety including the lowering of core damage frequencies and enhancing mitigation systems in the

case of an accident.

Nuclear energy for industrial process heat

Process heat involves the supply of heat required for industrial processes from one or more centralized

heat generation sites through a steam transportation network. Within the industrial sector, process heat

is used for a large variety of applications with different heat requirements and with temperature ranges

covering a wide spectrum. Examples of industries that consume considerable amounts of heat are:

• food,

• paper,

• chemicals and fertilizers,

• petroleum and coal processing, and

• metal processing industries.

The breakdown of the total industrial heat varies from country to country, but the chemical and

petroleum industries are the major consumers worldwide. These would be key target clients for

possible applications of nuclear energy.

The supply of energy for industrial processes has an essential character: all industrial users need the

assurance of energy supply with a high reliability, and the heat should be produced close to the point

of use. Industrial process heat users do not have to be located within highly populated areas. Many of

the process heat users, in particular the large ones, can be (and usually are) located outside urban

areas, often at considerable distances. This makes joint siting of nuclear reactors and industrial users

of process heat not only viable, but also desirable in order to drastically reduce the heat transport costs.

The nuclear process heat supply has to be reliable. As an example, the average adequate steam supply

availabilities for chemical processing, oil refineries and primary metals are respectively 98%, 92% and

near 100%. Such high levels can be ensured only by the combination of a highly reliable heat source

and the availability of reserve capacity.

There is experience in providing process heat for industrial purposes with nuclear energy in Canada,

Germany, Norway, Switzerland, and India. New plant designs that can provide heat, or both heat and

electricity, are being designed in Russia, the Republic of Korea, Canada, and other countries.

Current water cooled reactors can provide process heat up to about 300ºC, and some future innovative

water cooled reactor designs

have potential to provide heat up to approximately 550ºC.

Although nuclear industrial process heat applications have significant potential, it has not been

realized to a large extent. In fact, currently only the Goesgen reactor in Switzerland and the RAPS–2

reactor in India continue to provide industrial process heat, whereas other process heat systems have

been discontinued after successful use. Among the reasons cited for closure of these units, one is

availability of cheaper alternate energy sources, including waste heat near the industrial complexes.

For potential future application of nuclear process heat, the main example presented in this document

is the use of nuclear energy for oil sand open-pit mining and deep-deposit extraction in Canada.

Alberta’s oil sand deposits are the second largest oil reserves in the world, and have emerged as the

fastest growing, soon to be dominant, source of crude oil in Canada. Currently, the majority of oil sand

production is through open-pit mining, which is suitable for bitumen extraction when the oil sand

deposits are close to the surface. The ore, a mixture of bitumen and sand, is removed from the surface

by truck and shovel operation. The ore is then mixed with hot water to form a slurry that eventually

undergoes a separation process to remove bitumen from the sand.

The thermal energy required for the open-pit mining process is in the form of hot water at a relatively

low temperature (around 70°C), and the rest is dry process steam at around 1.0 to 2.0 MPa. The oil

extraction facilities require electrical power as well. These heat requirements, as well as the electricity,

can be met by water cooled reactors.

To increase production capacity, the industry is developing new technologies to extract bitumen from

deep deposits. Among them, Steam-Assisted Gravity Drainage (SAGD), which uses steam to remove

bitumen from underground reservoirs, appears to be the most promising approach. Recently, the in-

situ recovery process has been put into commercial operation by major oil companies.

Overall, for both extraction methodologies (open pit mining and SAGD), a significant amount of

energy is required to extract bitumen and upgrade it to synthetic crude oil as the feedstock for oil

refineries. Currently, the industry uses natural gas as the prime energy source. As oil sand production

Specifically Super-critical Water Cooled Reactors, being developed within the Generation-IV International Forum,

could be deployed by around 2025-2030.

continues to expand, the energy required for production becomes a great challenge with regard to

economic sustainability, environmental impact and security of supply. Therefore, the opportunity for

nuclear reactors to provide an economical, reliable and virtually zero-emission source of energy for

the oil sands becomes a realistic option.

Contribution of nuclear energy to transportation

Transportation represents approximately 20% of the world’s energy consumption. In the United States

of America, transportation is the fastest growing energy sector and in the past few years has become

the nation’s largest energy sector. The Organization for Economic Co-operation and Development

International Energy Agency projects that global primary energy demand will grow by 50% by 2030,

with 70% of that growth coming from developing countries, especially China. Half of that increase

will be for electricity production and 20% for transportation. The expectation is that fossil fuels will

account for 83% of this increased energy consumption.

It is clear that if nuclear energy finds a way to power a significant part of the transportation sector, it

will have a major impact on global environmental sustainability. Two ways this could occur would be

through the advancement of electric and plug-in hybrid electric vehicles and of vehicles fuelled with

hydrogen produced by nuclear energy. This present study addressed electricity for plug-in hybrid

vehicles and hydrogen for transportation.

A) Electricity for plug-in hybrid electric vehicles

Hybrid electric vehicles of various classes are now commercially available. Almost all use

regenerative braking to charge an on-board battery for locomotive power. With these battery systems,

vehicles can be designed to allow the gasoline engine to turn off when the vehicle is stopped or during

cruising. Moreover, the smaller engines used can run at a higher percentage of their full power, which

is more efficient and more economical for a given load than larger, heavier gasoline engines operating

at a lower percentage of their maximum power.

Overall energy use for hybrids has been shown to be about 40% less than that for conventional

vehicles, with an equivalent reduction in fossil energy use and greenhouse gas emissions (CO

, CH

and N

O).

Plug-in hybrid electric vehicles extend this technology a step further by allowing a drive battery to be

charged externally. In this way, the vehicle can be driven in an all-electric mode for a certain distance

with no power from the gasoline engine. This can provide significant savings in terms of petroleum

usage and emissions, especially since the majority of miles driven are for short commutes. These

emission reductions materialize only if the source of external electricity is clean and carbon free, of

course.

The potentially large market demand for electricity for powering plug-in hybrid electric vehicles is

eminently suited to current and evolutionary water-cooled nuclear power plants. The analysis provided

in Chapter 5, for instance, shows that plug-in hybrid electric vehicles produce only 42% of the carbon

dioxide produced by conventional vehicles and that over 11,000 lb/vehicle-year of carbon dioxide can

be saved if nuclear power is used to generate plug-in hybrid electric vehicle electricity rather than

coal.

Under a simplified model of potential growth in plug-in hybrid electric vehicle usage, perhaps

250 GW of electricity may be needed for overnight charging in the U.S. by 2035. New generation

capacity at this scale would also require new transmission and distribution lines and substations. A

similar analysis for Japan suggests the need for 35 GW of electricity for overnight charging, which is

within the capacity of spare power at night.

Aside from the need for increases in generating and transmission capacity, other barriers will need to

be overcome before there is widespread adoption of plug-in hybrid electric vehicles:

• Conversion of automobile technology from conventional gasoline-powered vehicles to electric

and plug-in hybrid vehicles;

• Public acceptance of plug-in hybrid vehicles;

• Structuring of electricity pricing mechanisms to provide low-price electricity during off-peak

demand periods to encourage use of nuclear power plants for base load generation;

• Provision of other incentives (e.g., tax benefits) for adoption of vehicles that produce less

greenhouse gases and reduce reliance on petroleum fuels.

A key technical barrier is the development of lighter, less expensive, reliable batteries having a factor

of 5 to 10 greater energy storage capacity that would boost all-electric distances to twenty miles or

greater. Lithium-ion batteries as a substitute for nickel-metal hydride batteries are the main focus of

current research and development.

Despite these barriers, automobile manufacturers are spending significant effort on developing plug-in

hybrid electric vehicles. In fact, one auto manufacturer has recently announced road testing for its

plug-in hybrid vehicle, which can travel eight miles on a full charge before it needs to draw power

from the gasoline engine, and other plug-in hybrid manufacturers have announced targets of 20 to 40

miles on a single charge.

B) Hydrogen for transportation

Hydrogen for transportation is receiving significant attention around the world because of high

petroleum prices and unreliable oil supplies. Two ways of hydrogen utilization in transportation are

currently being taken into consideration – internal combustion engine (ICE) vehicles and fuel cell (FC)

vehicles. While ICE vehicles represent current technology with modest modifications, fuel cell

vehicles are in a stage of intensive R&D and prototype testing.

Car manufacturers are focusing more effort on fuel cell vehicles than on hydrogen ICE vehicles. Many

prototypes have been introduced, some of them in small series (tens of cars). Most of the

manufacturers have opted for proton exchange membrane (PEM) fuel cells because of their low-

temperature operation and relatively (compared to other fuel cell types) easy manufacturing and

maintenance. Current trends are mainly focused on hybridization, such as combining fuel cells with

NiMH batteries, ultra capacitors, or other types of electric storage. Although this increases the

complexity of the vehicle, thus increasing the cost, it brings significant advantages. The main one is

covering power peaks during acceleration, when the electric motor draws high current from the Fuel

Cell. A second advantage in electrical storage is increasing the driving range, because hybrid vehicles

optimize fuel consumption, and also the use of braking recuperation.

It is not only important to have technical problems solved, public acceptance is also important. For this

purpose, hydrogen fuelled buses have been successful. Currently there are about 60 of them serving on

a daily basis in different cities including London, Hamburg, Madrid, Stuttgart, Stockholm, Porto,

Amsterdam, Barcelona, Luxembourg, Reykjavik and Perth.

The lack of the hydrogen infrastructure makes fleet customers important for early hydrogen

transportation markets. It is much easier to build one centralized filling station near a city bus operator

or dispatch service than to service the distributed market for personal cars.

Motorcycles, scooters and electric bikes represent a smaller, but interesting, market opportunity. Such

means of transportation are significant in many Asian countries, where the pollution is growing and

causing health problems. Switching from fossil-based fuels to hydrogen would improve the local

environment.

Nuclear energy for hydrogen production

As an alternative path to the current fossil fuel economy, a hydrogen economy is envisaged in which

hydrogen would play a major role in energy systems and serve all sectors of the economy, substituting

for fossil fuels. Hydrogen as an energy carrier can be stored in large quantities, unlike electricity, and

converted into electricity in fuel cells, with only heat and water as by-products. It is also compatible

with combustion turbines and reciprocating engines to produce power with near-zero emission of

pollutants. Furthermore, hydrogen can be obtained from various primary energy sources that are

domestically available in most countries. Consequently, the hydrogen economy could enhance both

the security of energy supply and global environmental quality.

The current worldwide hydrogen production is roughly 50 million tonnes per year. Although current

use of hydrogen in energy systems is very limited, its future use could become enormous, especially if

fuel-cell vehicles would be deployed on a large commercial scale. The hydrogen economy is getting

higher visibility and stronger political support in several parts of the world.

Today, hydrogen is used in limited quantities, and mainly in petroleum refineries and the chemical

industry. In the United States, for example, these uses represented 93% of hydrogen consumption in

2003. However, hydrogen is an attractive energy carrier that might play a major role in energy systems

for many economic sectors in the long term. In the medium term, the most promising area for

hydrogen is in producing synthetic fuel as a substitute for gasoline in transportation. Hydrogen

produced from non-fossil fuels may be a key option as the prices of hydrocarbon resources soar or

their consumption becomes restricted for environmental reasons.

Hydrogen currently finds many applications as a chemical product for:

• Ammonia synthesis;

• Methanol synthesis;

• Direct reduction of iron ore;

• Fossil fuel processing (hydro cracking);

• Fischer-Tropsch hydrocarbon synthesis;

• Methanation in long-distance energy transportation; and

• Hydro-gasification.

In addition, there may be hydrogen markets for heating, stationary fuel cells, combined heat and

power, and stationary gas turbines. Potentially hydrogen could be used for ground transport, aviation,

marine applications, and railroad transport.

The mass utilization of fuel cells for transportation and decentralized power production will not

materialize until at least 2020. Currently research focuses on catalysts, materials, equipment,

production costs, durability, cold-start capability, power density, and water management.

Nuclear-generated hydrogen has important potential advantages over other sources that will be

considered for a growing hydrogen economy. Nuclear hydrogen requires no fossil fuels, results in

lower greenhouse-gas emissions and other pollutants, and lends itself to large-scale production. These

advantages do not ensure that nuclear hydrogen will prevail, however, especially given strong

competition from other hydrogen sources. There are technical uncertainties in nuclear hydrogen

processes, certainly, which need to be addressed through a vigorous research and development effort.

As a greenhouse-gas-free alternative, the U.S., Japan, and other nations are exploring ways to produce

hydrogen from water by means of electrolytic, thermochemical, and hybrid processes. Most of the

work has concentrated on high-temperature processes such as high-temperature steam electrolysis and

the sulphur–iodine and calcium-bromine cycles. These processes require higher temperatures

(>750

C) than can be achieved by water-cooled reactors. Advanced reactors such as the very high

temperature gas cooled reactor (VHTGR) can generate heat at these temperatures, but will require

several years before they are commercial deployed.

Water-cooled reactors are likely to be the nuclear power technology of choice for many years. Their

outlet temperature limitation of ~350

C leaves only one current option for hydrogen production: low-

temperature water electrolysis. Because they require no heat input, water electrolyzers can be

decoupled from the power plant. Therefore, electrolysers can be attractive as remote and decentralized

hydrogen production methods. Because of the high electrical demands for the process, though,

electrolysis of water is attractive only when cheap electricity is available or when particularly high-

purity hydrogen is required. The use of nuclear generated electricity in off-peak periods from existing

water-cooled reactors may be economically competitive, but the stranded capital costs of the

electrolyzers during periods of peak electricity prices may be prohibitive.

Other hydrogen production options require higher temperatures. Short of the temperatures achievable

by liquid-metal-cooled or gas-cooled reactors, few hydrogen production methods are known.

Supercritical water cooled reactors have the potential to deliver heat at 550

C. At this temperature,

hydrogen production methods include membrane-assisted steam methane reforming and a limited

number of thermo-electrochemical cycles. Experimentation has been limited on these systems. None

are close to having demonstrated commercial viability. Nonetheless, process flowsheets suggest that

system efficiencies can be higher than for low-temperature water electrolysis. This makes laboratory

research on potential hydrogen production technologies worth pursuing.

A study has shown that significant reductions in fossil energy use and greenhouse gas emissions come

from nuclear-based hydrogen production compared to natural-gas-based hydrogen production through

steam methane reforming. The reductions amount to 73 – 96% in greenhouse gas emissions (CO

, and N

O) and 81 – 97% in fossil energy use. Furthermore, fuel cell vehicles powered by nuclear

hydrogen have substantial reductions in greenhouse gas emissions (87 – 98%) and fossil energy use

(89 – 98%) compared with internal combustion engine vehicles using reformulated gasoline. Nuclear

hydrogen is not completely emission-free, however, since a small amount of fossil fuel is consumed in

the upstream feedstock and fuel stages.

Conclusion

In considering the deployment of nuclear energy into advanced applications, challenges and

difficulties should not be overlooked; in particular, it should be acknowledged that a scientific

potential is not a technical reality and that competition will drive the choice of energy sources for each

application. Moving from their potential to realities is undoubtedly feasible, but will need time,

investments, and policy measures to address a wide range of techno-economic and socio-political

challenges. Public acceptance is a major issue for nuclear energy. Advanced applications of nuclear

energy can play an important role in enhancing public acceptance.

CHAPTER 1

PRESENT STATUS AND OVERVIEW OF

ADVANCED APPLICATIONS OF NUCLEAR REACTORS

Introduction

Today, nuclear power plants provide about 15.2% of the world’s electricity consumption. Because

electricity represents less than one third of the primary energy uses, nuclear energy provides only

about 6% of total energy consumption in the world. If nuclear energy were used for purposes other

than electricity generation, it could play a more significant role in global energy supply. This could

have a significant impact on global goals for reduced greenhouse gas emissions, for a cleaner

environment, and for less reliance on uncertain supplies of fossil fuels.

Nuclear reactors, which produce energy in the form of heat, can supply energy products other than

electricity, including district and process heat, desalinated water, hydrogen, and heat for other

industrial products. Although not covered in this report, nuclear reactors are unique in their ability to

produce high radiation fields for medical isotope production and the conversion of plutonium and

other transuranic elements to shorter-lived radioactive waste. While these applications of nuclear

energy have been considered since the very beginning of nuclear energy development, they have for

various reasons yet to be deployed at a significant industrial scale.

In recent years, various agencies involved in nuclear energy development programmes worldwide

have carried out studies on advanced applications of nuclear power and useful reports have been

published [1-4]:

• The IAEA launched a programme on co-generation applications and has published two

TECDOCs (IAEA-TECDC-923 and IAEA-TECDOC-1184) and a Guidebook on Introduction

of Nuclear Desalination (TRS-400) in 2000. IAEA also published a report in 2002 on the

Market Potential for Non-electric Applications of Nuclear Energy (TRS-410).

• The Organization for Economic Cooperation and Development (OECD) Nuclear Energy

Agency, under the guidance of the Committee for Technical and Economic Studies on Nuclear

Energy Development and the Fuel Cycle (NDC), carried out a comprehensive survey of

published literature on the subject matter, including reports from international organizations,

national institutes and other parts of NEA and published a report summarizing the findings and

recommendations [5].

• The Generation IV International Forum (GIF) project aims at development of innovative

reactors with temperatures up to 1000

C. The GIF road map recommends necessary R&D. One

of the selected systems is the super-critical water cooled reactor SCWR [6].

• The Michelangelo Network (MICANET) was started within the 5

EUROATOM Framework

Programme (FP5) with the objective to elaborate a general European R&D strategy for further

development of the nuclear industry in the short, medium and long term. MICANET has been

examining the role of nuclear energy in near and medium term missions; i.e. the transition phase

from the present fossil era to CO

emission-free technologies in the future. The programme

results were reported in November 2005 as a work package on “Non-electric application of

nuclear energy”. The network examined the possible orientation of future EURATOM R&D

programmes including new aspects of nuclear energy such as combined heat and power (CHP),

desalination, and hydrogen production or other fuel production as a complement to other CO

free energy sources [7].

The present IAEA document focuses on the potential of water-cooled nuclear reactor technology to

penetrate non-electricity sectors. Nuclear power is the only large-scale carbon-free energy source that,

in the near and medium term, has the potential to significantly displace limited and uncertain fossil

fuels. To do this, however, nuclear power must move beyond its historical role as solely a producer of

electricity. The sampling of non-electric applications in this report is not exhaustive. For instance, the

use of nuclear reactors for medical therapy and radioactive isotopes is not covered. Instead, the

document is intended to begin a dialogue that considers the value of water-cooled reactor technology

for a broad range of non-traditional applications.

1.1. Nuclear power reactors in the world

The number of nuclear power reactors in operation and under construction in the world, as of August

2007, as reported by the IAEA Power Reactor Information System, are reproduced in Table 1.1.

Table 1.1. Distribution of reactor types

Light water reactors

In operation 359

Under construction 23

Number of countries with LWRs

Generating capacity, GW(e)

328.2

Heavy water moderated reactors

In operation 43

Under construction 5

Number of countries with HWRs 7

Generating capacity, GW(e) 21.7

Reactors cooled and moderated by light water

Reactors moderated by heavy water

Light water cooled graphite moderated reactors:

In operation 16

Under construction 1

Number of countries 2

Generating capacity, GW(e) 11.4

Liquid metal cooled fast reactors:

In operation 2

Under construction 2

Number of countries with FRs

Generating capacity, GW(e) 1.0

Operating Experience, reactor years 171

In France, Russia and Japan, where the Monju reactor, under long term

shutdown, is planned to be re-started.

Gas cooled reactors:

Power reactors in operation 18

Under construction 0

Test reactors in operation 2

Number of countries with GCRs 3

Generating capacity, GW(e) 9.0

Table 1.1 shows that water cooled reactors are the work-horse of nuclear power generation. Up to

now, nuclear energy has served almost exclusively as a generator of electricity. In decades to come,

nuclear may be called upon to play a significant role in other energy sectors, especially as there is a

drive to reduce greenhouse gas emissions in sectors traditionally served by fossil fuels. Some of the

most promising applications are hydrogen production, high temperature process heat, desalination to

produce fresh water, and district heating. In addition, the advent of plug-in hybrid electric vehicles

may allow nuclear electricity generation to enter the transportation sector. Some experience is already

available with these applications, particularly for seawater desalination and district heating.

1.2. Non-electric applications of nuclear power

Figure 1.1 shows various reactor types and their possible non-electric applications. It can be seen that

most of the present day non-electric applications can be met with water cooled reactors. Some of the

industrial heat requirements, however, require higher temperature heat and would need other types of

reactors.

FIG. 1.1. Temperature ranges in production and use of nuclear heat.

Of the 438 nuclear power reactors operating worldwide in August 2007, those reactors which were

being used for co-generation of hot water or steam for district heating, seawater desalination or

industrial processes are shown in Table 1.2 (based on the IAEA Power Reactor Information System).

Table 1.3 shows the energy generated by each reactor for district heating, process heating, or

desalination. Salient details of these applications will be found in the succeeding chapters. Other

advanced applications, such as nuclear hydrogen production, have yet to be realized.

TABLE 1.2. Reactors having non-electric applications

Capacity

Reactor

MW(e)

Country

Code Name

Type

Net Gross Thermal

Operator

NSSS

Supplier

Construction

Start

Grid

Connection

Commercial

Operation

Load Factor %

(1)

to 2005

Unit Capacity

Factor % (1)

to 2005

Non-electric

Applications

(2)

BULGARIA BG -5 KOZLODUY-5 PWR 953 1000 3000 KOZNPP AEE 1980-7 1987-11 1988-12 50.0 64.0 DH

BG -6 KOZLODUY-6 PWR 953 1000 3000 KOZNPP AEE 1982-4 1991-8 1993-12 58.0 72.0 DH

CZECH REP. CZ -23 TEMELIN-1 PWR 930 975 3000 CEZ SKODA 1987-2 2000-12 2002-6 70.0 72.0 DH

CZ -24 TEMELIN-2 PWR 930 975 3000 CEZ SKODA 1987-2 2002-12 2003-4 69.0 68.0 DH

HUNGARY HU -2 PAKS-2 PWR 441 468 1375 PAKS RT. AEE 1974-8 1984-9 1984-11 79.0 78.0 DH

HU -3 PAKS-3 PWR 433 460 1375 PAKS RT. AEE 1979-10 1986-9 1986-12 87.0 86.0 DH

HU -4 PAKS-4 PWR 444 471 1375 PAKS RT. AEE 1979-10 1987-8 1987-11 89.0 87.0 DH

INDIA IN -5 MADRAS-1 PHWR 202 220 801 NPCIL NPCIL 1971-1 1983-7 1984-1 49.0 58.0 DS

IN -6 MADRAS-2 PHWR 202 220 801 NPCIL NPCIL 1972-10 1985-9 1986-3 55.0 62.0 DS

IN -3 RAJASTHAN-1 PHWR 90 100 693 NPCIL AECL 1965-8 1972-11 1973-12 21.0 28.0 PH

IN -4 RAJASTHAN-2 PHWR 187 200 693 NPCIL AECL/DAE 1968-4 1980-11 1981-4 53.0 60.0 PH

IN -11 RAJASTHAN-3 PHWR 202 220 801 NPCIL NPCIL 1990-2 2000-3 2000-6 77.0 88.0 PH

IN -12 RAJASTHAN-4 PHWR 202 220 801 NPCIL NPCIL 1990-10 2000-11 2000-12 77.0 91.0 PH

JAPAN JP -45 GENKAI-3 PWR 1127 1180 3423 KYUSHU MHI 1988-6 1993-6 1994-3 86.0 85.0 DS

JP -46 GENKAI-4 PWR 1127 1180 3423 KYUSHU MHI 1992-7 1996-11 1997-7 86.0 85.0 DS

JP -23 IKATA-1 PWR 538 566 1650 SHIKOKU MHI 1973-6 1977-2 1977-9 77.0 78.0 DS

JP -32 IKATA-2 PWR 538 566 1650 SHIKOKU MHI 1978-2 1981-8 1982-3 81.0 81.0 DS

JP -47 IKATA-3 PWR 846 890 2660 SHIKOKU MHI 1986-11 1994-3 1994-12 87.0 85.0 DS

JP -15 OHI-1 PWR 1120 1175 3423 KEPCO WH 1972-10 1977-12 1979-3 66.0 66.0 DS

JP -19 OHI-2 PWR 1120 1175 3423 KEPCO WH 1972-12 1978-10 1979-12 72.0 72.0 DS

JP -29 TAKAHAMA-3 PWR 830 870 2660 KEPCO MHI 1980-12 1984-5 1985-1 84.0 83.0 DS

JP -30 TAKAHAMA-4 PWR 830 870 2660 KEPCO MHI 1981-3 1984-11 1985-6 86.0 84.0 DS

PAKISTAN PK -1 KANUPP PHWR 125 137 433 PAEC CGE 1966-8 1971-10 1972-12 26.0 43.0 DS

ROMANIA RO -1 CERNAVODA-1 PHWR 655 706 2180 SNN AECL 1982-7 1996-7 1996-12 86.0 87.0 DH

TABLE 1.2. Reactors having non-electric applications (cont’d)

Capacity

Reactor

MW(e)

Country

Code Name

Type

Net Gross Thermal

Operator

NSSS

Supplier

Construction

Start

Grid

Connection

Commercial

Operation

Load Factor %

(1)

to 2005

Unit Capacity

Factor % (1)

to 2005

Non-electric

Applications

(2)

RUSSIAN FEDERATION RU -96 BALAKOVO-1 PWR 950 1000 3000 REA FAEA 1980-12 1985-12 1986-5 62.0 68.0 DH,PH

RU -97 BALAKOVO-2 PWR 950 1000 3000 REA FAEA 1981-8 1987-10 1988-1 61.0 67.0 DH,PH

RU -98 BALAKOVO-3 PWR 950 1000 3000 REA FAEA 1982-11 1988-12 1989-4 66.0 73.0 DH,PH

RU -99 BALAKOVO-4 PWR 950 1000 3200 REA FAEA 1984-4 1993-4 1993-12 71.0 78.0 DH,PH

RU -21

BELOYARSKY-3(BN-

600)

FBR 560 600 1470 REA FAEA 1969-1 1980-4 1981-11 74.0 75.0 DH,PH

RU -141 BILIBINO-1 LWGR 11 12 62 REA FAEA 1970-1 1974-1 1974-4 58.0 80.0 DH

RU -142 BILIBINO-2 LWGR 11 12 62 REA FAEA 1970-1 1974-12 1975-2 57.0 81.0 DH

RU -143 BILIBINO-3 LWGR 11 12 62 REA FAEA 1970-1 1975-12 1976-2 59.0 81.0 DH

RU -144 BILIBINO-4 LWGR 11 12 62 REA FAEA 1970-1 1976-12 1977-1 58.0 78.0 DH

RU -30 KALININ-1 PWR 950 1000 3000 REA FAEA 1977-2 1984-5 1985-6 71.0 71.0 DH,PH

RU -31 KALININ-2 PWR 950 1000 3000 REA FAEA 1982-2 1986-12 1987-3 71.0 73.0 DH,PH

RU -36 KALININ-3 PWR 950 1000 3200 REA FAEA 1985-10 2004-12 2005-11 77.0 77.0 -

RU -12 KOLA-1 PWR 411 440 1375 REA FAEA 1970-5 1973-6 1973-12 65.0 76.0 DH,PH

RU -13 KOLA-2 PWR 411 440 1375 REA FAEA 1973-1 1974-12 1975-2 65.0 76.0 DH,PH

RU -32 KOLA-3 PWR 411 440 1375 REA FAEA 1977-4 1981-3 1982-12 72.0 82.0 DH,PH

RU -33 KOLA-4 PWR 411 440 1375 REA FAEA 1976-8 1984-10 1984-12 71.0 81.0 DH,PH

RU -17 KURSK-1 LWGR 925 1000 3200 REA FAEA 1972-6 1976-12 1977-10 57.0 60.0 DH,PH

RU -22 KURSK-2 LWGR 925 1000 3200 REA FAEA 1973-1 1979-1 1979-8 60.0 63.0 DH,PH

RU -38 KURSK-3 LWGR 925 1000 3200 REA FAEA 1978-4 1983-10 1984-3 71.0 73.0 DH,PH

RU -39 KURSK-4 LWGR 925 1000 3200 REA FAEA 1981-5 1985-12 1986-2 75.0 76.0 DH,PH

RU -15 LENINGRAD-1 LWGR 925 1000 3200 REA FAEA 1970-3 1973-12 1974-11 68.0 69.0 DH,PH

RU -16 LENINGRAD-2 LWGR 925 1000 3200 REA FAEA 1970-6 1975-7 1976-2 68.0 69.0 DH,PH

RU -34 LENINGRAD-3 LWGR 925 1000 3200 REA FAEA 1973-12 1979-12 1980-6 69.0 71.0 DH,PH

RU -35 LENINGRAD-4 LWGR 925 1000 3200 REA FAEA 1975-2 1981-2 1981-8 71.0 73.0 DH,PH

TABLE 1.2. Reactors having non-electric applications (cont’d)

Capacity

Reactor

MW(e)

Country

Code Name

Type

Net Gross Thermal

Operator

NSSS

Supplier

Construction

Start

Grid

Connection

Commercial

Operation

Load Factor %

(1)

to 2005

Unit Capacity

Factor % (1)

to 2005

Non-electric

Applications (2)

RU -23 SMOLENSK-1 LWGR 925 1000 3200 REA FAEA 1975-10 1982-12 1983-9 70.0 73.0 DH,PH

RU -24 SMOLENSK-2 LWGR 925 1000 3200 REA FAEA 1976-6 1985-5 1985-7 73.0 76.0 DH,PH

RU -67 SMOLENSK-3 LWGR 925 1000 3200 REA FAEA 1984-5 1990-1 1990-10 78.0 81.0 DH,PH

SLOVAKIA SK -13 BOHUNICE-3 PWR 408 440 1375 SE,plc SKODA 1976-12 1984-8 1985-2 75.0 80.0 DH

SK -14 BOHUNICE-4 PWR 408 440 1375 SE,plc SKODA 1976-12 1985-8 1985-12 77.0 82.0 DH

SWITZERLAND CH -1 BEZNAU-1 PWR 365 380 1130 NOK WH 1965-9 1969-7 1969-9 82.0 87.0 DH

CH -3 BEZNAU-2 PWR 365 380 1130 NOK WH 1968-1 1971-10 1971-12 87.0 87.0 DH

CH -4 GOESGEN PWR 970 1020 2900 KKG KWU 1973-12 1979-2 1979-11 88.0 89.0 DH

UKRAINE UA -40 KHMELNITSKI-1 PWR 950 1000 3000 NNEGC PAIP 1981-11 1987-12 1988-8 72.0 72.0 DH

UA -27 ROVNO-1 PWR 381 420 1375 NNEGC PAIP 1973-8 1980-12 1981-9 80.0 81.0 DH

UA -28 ROVNO-2 PWR 376 415 1375 NNEGC PAIP 1973-10 1981-12 1982-7 79.0 81.0 DH

UA -29 ROVNO-3 PWR 950 1000 3000 NNEGC PAIP 1980-2 1986-12 1987-5 69.0 73.0 DH

UA -44 SOUTH UKRAINE-1 PWR 950 1000 3000 NNEGC PAA 1977-3 1982-12 1983-10 66.0 66.0 DH

UA -45 SOUTH UKRAINE-2 PWR 950 1000 3000 NNEGC PAA 1979-10 1985-1 1985-4 61.0 62.0 DH

UA -48 SOUTH UKRAINE-3 PWR 950 1000 3000 NNEGC PAA 1985-2 1989-9 1989-12 72.0 73.0 DH

UA -54 ZAPOROZHE-1 PWR 950 1000 3000 NNEGC PAIP 1980-4 1984-12 1985-12 61.0 64.0 DH

UA -56 ZAPOROZHE-2 PWR 950 1000 3000 NNEGC PAIP 1981-1 1985-7 1986-2 64.0 68.0 DH

UA -78 ZAPOROZHE-3 PWR 950 1000 3000 NNEGC PAIP 1982-4 1986-12 1987-3 66.0 70.0 DH

UA -79 ZAPOROZHE-4 PWR 950 1000 3000 NNEGC PAIP 1983-4 1987-12 1988-4 71.0 75.0 DH

UA -126 ZAPOROZHE-5 PWR 950 1000 3000 NNEGC PAIP 1985-11 1989-8 1989-10 72.0 74.0 DH

UA -127 ZAPOROZHE-6 PWR 950 1000 3000 NNEGC PAIP 1986-6 1995-10 1996-9 77.0 80.0 DH

(1) Performance factors Load Factor (LF) and Unit Capacity Factor (UCF) calculated only for period of full commercial operation, and only through 2005.

(2)The column Non-Electrical Applications indicates the use of the facility to provide:- DS desalination, DH district heating, PH process heat.

Table 1.3-a. District heating and process heat in 2006 (1)

Country Reactor District heating [Gcal] Process heat [Gcal] Total heat [Gcal]

Bulgaria Kozloduy-5 121735 N/A 121735

Kozloduy-6 17964 N/A 17964

Czech Republic Temelin-1 42503 N/A 42503

Temelin-2 4757 N/A 4757

Hungary PAKS-2 2187 N/A 2187

PAKS-3 25385 N/A 25385

PAKS-4 214307 N/A 214307

India Rajasthan-1 N/A 0 0

Rajasthan-2 N/A 98952 98952

Rajasthan-3 N/A 112421 112421

Rajasthan-4 N/A 21186 21186

Romania Cernavoda-1 27127 N/A 27127

Russian Federation Balakovo-1 47980 0 47980

Balakovo-2 0 0 0

Balakovo-3 1000 0 1000

Balakovo-4 2837 0 2837

Beloyarsky-3 279279 0 279279

Bilibino-1 45212 N/A 45212

Bilibino-2 41344 N/A 41344

Bilibino-3 50286 N/A 50286

Bilibino-4 49062 N/A 49062

Kalinin-1 337593 3510 341103

Kalinin-2 224460 3084 227544

Kola-1 6628 2064 8692

Kola-2 7962 2066 10028

Kola-3 11234 1744 12978

Kola-4 5624 1828 7452

Kursk-1 60540 62611 123151

Kursk-2 96184 101255 197439

Kursk-3 127776 116201 243977

Kursk-4 217029 168384 385413

Table 1.3-a. District heating and process heat in 2006 (1) cont’d.

Leningrad-1 219273 0 219273

Leningrad-2 26582 0 26582

Leningrad-3 243028 0 243028

Leningrad-4 183123 0 183123

Novovoronezh-3 84240 0 84240

Novovoronezh-4 135657 2680 138337

Novovoronezh-5 0 1637 1637

Smolensk-1 55751 34670 90421

Smolensk-2 278585 22224 300809

Smolensk-3 249082 21803 270885

Slovakia Bohunice-3 224056 0 224056

Bohunice-4 193285 0 193285

Switzerland Beznau-1 129 N/A 129

Beznau-2 12 N/A 12

Goesgen N/A 63005 63005

Ukraine Khemlnitski-1 189517 N/A 189517

Rovno-1 82154 N/A 82154

Rovno-2 66929 N/A 66929

Rovno-3 129006 N/A 129006

South Ukraine-1 98018 N/A 98018

South Ukraine-2 129808 N/A 129808

South Ukraine-3 136978 N/A 136978

Zaporozhe-1 89166 N/A 89166

Zaporozhe-2 91991 N/A 91991

Zaporozhe-3 43534 N/A 43534

Zaporozhe-4 64302 N/A 64302

Zaporozhe-5 125087 N/A 125087

Zaporozhe-6 126772 N/A 126772

(1) 1 Gcal = 1.16 MWh.

Table 1.3-b. Water desalination in 2006 (1)

Country Reactor

Thermal energy

[Gcal]

Electrical energy

for reverse

osmosis

[MWh]

Water produced

]

Madras-1 0 0 0 India

Madras-2 0 0 0

Genkai 3&4 30189 N/A 430050

Ikata 1&2 N/A 331488

Ikata-3 N/A 6002

Ohi 1 and 2 N/A 930269

Japan

Takahama 3&4 N/A 608029

Pakistan KANUPP 0 0 0

(1) 1 Gcal = 1.16 MWh.

1.3. Past experience with non-electric applications

Figure 1.2 shows the reactor years of experience for non-electric applications in Bulgaria, China,

Czech Republic, Hungary, India, Japan, Kazakhstan, Pakistan, Romania, Russian Federation,

Slovakia, Switzerland and the Ukraine.

Experience with non-electrical applications

100

200

300

400

500

600

700

800

900

1000

RU UA JP HU CH IN SK BG KZ CZ RO PK

reactor-years

FIG. 1.2. Reactor-years of experience with non-electric applications in different countries.

A comprehensive list of various non-electric applications worldwide published in the IAEA

Guidebook [3] is reproduced in Tables 1.5 through 1.10 for ready reference.

Table 1.5. Operating nuclear desalination plants in Japan

Plant

name

Location

Application

Start of

operation

reactors /

desalination

Net

Power

(MW(e))

Water

capacity

/d)

Remarks

Ikata-1,2 Ehime Electricity/

desalination

1977-82

1975

566 2000 PWR/MED,

MSF

Ikata-3 Ehime Electricity/

desalination

1994

1992

566 2000 PWR/MSF

(2 x 1000 m

/d)

Ohi-1,2 Fukui Electricity/

desalination

1979

1973-76

1175 3900 PWR/MSF

(3 x 1300 m

/d)

Ohi-3,4 Fukui Electricity/

desalination

1991-93

1990

1180 2600 PWR/RO

(2 x 1300 m

/d)

Genkai-4 Fukuoka Electricity/

desalination

1997

1988

1180 1000 PWR/RO

Genkai-3,4 Fukuoka Electricity/

desalination

1995-97

1992

1180 1000 PWR/MED

Takahama Fukui Electricity/

desalination

1985

1983

870 1000 PWR/RO

Table 1.6. Nuclear desalination projects in India and Pakistan

Plant

name

Location

Application

Start of

Operation

reactor / desal.

Net

Power

(MW(e))

Water

capacity

/day)

Remarks

Kalpakkam

1,2

Tamil

Nadu

Electricity/

Desalination

Reactors:1984-86

RO:2000/2001

MSF: after 2001

2 x 170 6300 Hybrid MSF/

KANUPP Karachi Electricity

Desalination

Reactor: 1972

MED in 2007

1 x 135 4800 MED

Table 1.7. Operating nuclear heating plants

Country

Plant type

or name

Location

Application

Phase

Start of

operation

reactors / heat

Net

Power

(MW(e))

Heat output

capacity

(MW(th))

Temp (°C) at

interface

(feed/return)

Remarks

Bulgaria Kozloduy Kozloduy Electricity/

District heating

Commercial 1974-82

1990

1988-93

4 x 408

2 x 953

20 150/70

China NHR-5 Beijing District heating Experimental 1989

1989

- 5 90/60

Hungary PAKS 1-4

Paks Electricity/

District heating

Commercial 1983-87 3 x 433

1 x 430

30 130/70 4 x V-213

WWER

Romania PHWR

CANDU-6

Cernavoda

Unit 1

Electricity/

District heating

Commercial 1996 1 x 660 40 Gcal/h 150/70

Russia Obninsk District heating Commercial

1954-

- 10 130/70

Russia WWER-1000

Novovoronezh

Electricity/

District heating

Commercial 1972-73

1981

2 x 385

1 x 950

230 130/70

Russia WWER-1000 Balakovo Electricity/

District heating

Commercial

1986-93

4 x 950 230 130/70

Russia WWER-1000 Kalinin Electricity/

District heating

Commercial 1985-87

2 x 950 230 130/70

Russia WWER-440 Kola Electricity/

District heating

Commercial 1973-84

4 x 411 55

Russia EGP-6 Bilibino Electricity/

District heating

Commercial 1974-77

4 x 11 133 150/70

Russia BN-600 Belojarsk Electricity/

District heating

Commercial 1981

2 x 560 220 130/70

Russia RBMK-1000 Petersburg Electricity/

District heating

Commercial 1974-81

4 x 925 ~170 130/70

Russia RBMK-1000 Kursk Electricity/

District heating

Commercial 1977-86

4 x 925 ~170 130/70

Slovakia Bohunice-3,4 Bohunice/Trnava Electricity/

District heating

Commercial 1985 1987 2 x 408 240 150/70 2 x V-213

WWER

Switzerland Beznau 1,2 Beznau Electricity/

District heating

Commercial 1969-71/1983-84 1 x 365

1 x 357

80 128/50

(water)

Table 1.8. Nuclear heating plant projects

Country

Plant

type or site

Location

Application

Phase

Start of

operation

(year)

Power

(MW(e))

Heat

output

(MW(th))

Temperature (°C)

at interface

(Feed/Return)

Bulgaria Belene Belene Electricity/

District heating

Design 2 x 1000 400 150/70

China NHR-200 Daqing City District heating In construction 2000 - 200 90/~60

Japan HTTR O-arai Process heat Operation 1998 30 950/395

Romania PHWR

CANDU-6

Cernavoda -

Unit 2

Electricity/

District heating

commissioning

2007 1 x 660 46 150/70

Russia RUTA Apatity District heating/

Air conditioning

Design - 4 x 55 85/60

Russia ATEC-200 Electricity/

District heating

Design 50-180 70-40 150/70

Russia VGM Process Heat Design - 200 900/~500

Russia KLT-40 Electricity/

District heating

& Desalination

Design 35 110

Russia AST-500 Voronez District heating Construction

suspended

- 500 150/70

Russia AST-500 Tomsk District heating Construction

suspended

- 500 150/70

Table 1.9. Operating nuclear process heat production plants

Country

Plant

name

Location

Application

Start of operation

reactors / heat

Phase

Power

(MW

(e)))

Heat

delivery

(MW(t))

Temperature

(°C) at

interface

(feed/return)

Remarks

Canada Bruce-A

Bruce Process heat 1977-87 / 1981 Commercial 4 x 848

5350

O production

and six industrial

heat customers

Germany Stade Stade Electricity/

process heat

1983 Commercial 640 30 190/100 Salt refinery

Switzerland Goesgen Goesgen Electricity/

process heat

1979 / 1979 Commercial 970 25 220/100 Cardboard factory

India RAPS Kota Electricity/

process heat

1975 / 1980 Commercial 160 85 250 D

Unit 2 was taken out of service in 1995, units 1, 3 and 4 were taken out of service in spring 1998.

Table 1.10. Nuclear Process Heat Production Projects

Country

Plant

name

Location

Application

Start of operation

reactors / heat

Phase

Heat

delivery

(MW(t))

Temperature

(°C) at

interface

(feed/return)

Remarks

China HTGR-10 Beijing Electricity/

process heat

Criticality 1999 Construction 10 700-950/250 Experiments for

HTR technology

development.

Japan HTTR O-arai Process heat Criticality 1998 Construction

completed

30 950/395 Experiments for

HTR technology

development.

Russia VGM Process heat Design

1.4. Market potential of advanced non-electric applications [4]

1.4.1. 2003 IAEA study: Market potential for non-electric application of nuclear energy [4]

An analysis of the market potential for non-electric applications of nuclear energy was carried out by

IAEA and published in IAEA-TRS-410 (2003). The conclusions reached in this report are reproduced

as the following.

(a) For the foreseeable future, power generation will remain the main application of nuclear energy,

the main reasons being the advanced status of nuclear power

production technologies and an

increasing share of electricity in the total

energy demand;

(b) Currently, nuclear power has little penetration in non-electric energy applications. However, a

large demand for non-electric nuclear energy is expected to emerge and grow rapidly.

(c)

Because of the dominance of power generation, nuclear penetration into the

markets for non-

electric services will proceed with cogeneration applications

wherever possible. Dedicated

reactors for heat generation could eventually

emerge for some applications.

(d) Many non-electric applications require energy sources that are relatively small

(100-1000

MW(th)) in comparison with the size of existing power reactors.

The development of nuclear

reactors of small and medium size would therefore facilitate non-electric applications of nuclear

energy.

(e) Some non-electric applications require that the nuclear plant be located close to the customer.

This will require specific safety features appropriate to the location.

(f) Economically, the non-electric applications of nuclear energy are subject to the

same trends as

nuclear power generation. Growing capital costs of nuclear plants have affected the cost

estimations of most non-electric applications.

Evolutionary and innovative design

improvements in nuclear reactor concepts,

coupled with stable nuclear fuel prices, will result

in an improved

competitiveness of non-electric nuclear applications.

(g)

Depending upon the regions and conditions, nuclear energy is already competitive for district

heating, desalination, and certain process heat

applications.

(h)

Using nuclear energy to produce hydrogen is likely to facilitate the indirect

application of

nuclear energy in transportation markets, most of which are not readily amenable to the direct

use of nuclear reactors.

(i) Non-electric applications of nuclear energy are most likely to be implemented

in countries

already having the appropriate nuclear infrastructure and

institutional support.

(j)

The implementation of some non-electric applications (e.g., desalination) is

likely to enhance

the public acceptance of nuclear energy.

The following specific findings for these applications were formulated, in addition to the general

conclusions above.

District heating

Nuclear applications for district heating are technically mature and exist in

several countries. The

future use of nuclear energy will be determined by a

combination of the following factors: the size

and growth of the demand for space

and water heating, competition between heat and non-heat energy

carriers for space

and water heating, and competition between nuclear and non-nuclear heating. The

availability of a heat distribution network plays an important role in the prospects for nuclear district

heating.

Desalination

For desalination, low temperature heat and/or electricity are required.

Consequently, all existing

nuclear designs can be used; the relevant experience is already available. The use of nuclear heat

assumes a close location of the nuclear

plant to the desalination plant; the use of electricity generated

by nuclear energy (for

the RO desalination process) does not differ from any other electricity use —

the

energy source may be located far from the customer with the electricity being provided

through the electricity grid. (It should be noted, however, that a distant location would

not allow the use

of low temperature steam for water preheating, which is an

advantage of co-production plants.)

With regard to the market size, it is expected that freshwater requirements will grow in the future, which

will increase the attractiveness of nuclear desalination.

Process heat supply

For process heat supply there is a wide range of required heat parameters that determine the

applicability of different reactor types. One particular concept, the high-temperature gas-cooled reactor

(HTGR), can produce temperatures above 800

C and perhaps as high as 1000

C. It is, therefore,

considered to be a prime candidate for nuclear process heat supply at high temperatures. The

development and demonstration of such a reactor would provide a strong impetus for the process heat

applications of nuclear energy.

Ship propulsion

Nuclear powered ship propulsion has been tested technically in several

countries, especially for naval

applications. The technology has proven non-economic for commercial applications, however,

and the use of nuclear

powered merchant ship propulsion has been discontinued, with the exception

of the nuclear

powered ships operating off the north coast of the Russian Federation. Although the

market

for large tankers and cargo ships is large, the future of nuclear powered ships will

depend on

their ability to offer competitive service in this highly competitive market.

The need to observe safety

and licensing requirements in receiving ports is an

additional obstacle for the application of nuclear

powered ship propulsion.

Hydrogen production

Two aspects must be distinguished: the penetration of hydrogen into the energy system and the use of

nuclear energy for hydrogen production. In comparison with the use of fossil fuels for hydrogen

production, nuclear energy has the advantages of a

large resource base and the absence of most

emissions, carbon dioxide in

particular. In comparison with the use of renewable energy sources

for hydrogen

production, nuclear energy has the advantage of being a mature, available technology

and

has the important feature of a high energy concentration, which could allow

hydrogen production

to be concentrated in multi product energy centres. The share of nuclear energy in a hydrogen-based

system will depend on its competitiveness with

the other energy options. Successful demonstration

projects, such as the use of

surplus nuclear capacity for hydrogen production using cheap off-peak

electricity, the

operation of the first large HTGR and the creation of local hydrogen markets near

existing NPPs, would help to promote the nuclear-hydrogen link.

Coal gasification

Coal gasification has the following advantages: the reduction of air emissions from coal combustion, an

increased thermal efficiency of combustion, and the use of a large resource base. If coal gasification

becomes widespread, economic and

environmentally benign technologies for the supply of

gasification energy will be

required. Nuclear energy, being an industrially mature and non-polluting

technology, is a valid candidate for this purpose. Such applications would be similar to the other

process heat applications of nuclear energy.

Other synthetic fuels

Transportation accounts for about one quarter of the

world’s total energy demand and will grow

significantly in the future following, in particular, industrial growth and an increase in the standards of

living in developing countries.

The direct use of nuclear energy for transportation is limited to the

use of electric

driven motors and ship and spacecraft propulsion. However, using nuclear energy for

transportation indirectly, through fuel production, is possible. The related fuels, in

addition to

electricity and hydrogen, include alcohol fuels (methanol, ethanol, and

their derivatives), compressed

natural gas, liquefied natural gas, liquefied petroleum gas, and coal-derived liquid fuels. Each fuel has

certain advantages and may have a place in the future fuel economy. The future fuel mix will be

determined primarily by inter fuel economic competition, the availability of infrastructure, and

environmental considerations such as the amount and type of greenhouse gases and other polluting

emissions.

Oil extraction

Nuclear energy can be used for the extraction of unconventional oil resources such as heavy oil, oil

from tar and oil sands, oil shale, and the oil remaining in depleted deposits. These unconventional oil

resources are about two times larger than the resources of conventional oil. However, if the price of

conventional oil is low it is not realistic to expect significant developments in the extraction of

unconventional oil, except in the cases (as, for example, in Canada) in which the resources of

unconventional oil are large and already developed. The case of Canada is especially notable because,

on one hand, the resources of unconventional oil are very large, and, on the other, nuclear technologies

suitable for such applications are available.

Table 1.11 shows the most promising countries for non-electric nuclear applications in the long term.

This table includes countries in which at least two applications are ranked highest in the corresponding

region.

These estimates are based on assessments that assume that applications of nuclear energy, both for

power generation and for non-electric purposes, will continue to

develop. This includes technical

development, infrastructural support and the licensing environment, the latter being particularly

important for certain applications. These estimations also assume, implicitly, that nuclear energy will

remain socially

acceptable

Table 1.11. Most promising countries for the long term prospects of non-electric

applications of nuclear energy

Region/country District

heating

Water desalination Process heat Ship propulsion

NAM

Canada M L M M

USA M L M M

LAM

Argentina L M L L

Brazil L L L M

Mexico L L L L

AFR

South Africa M M M L

MEA

Egypt L H L -

Iran M M M L

Morocco L H L -

WEU

Belgium M M M L

Finland M M M L

France M M M M

Netherlands M M M M

Spain M H M L

Switzerland M M M L

UK M M L M

EEU

Bulgaria M L M L

Czech Republic M M M L

Romania M L L

Slovakia M M M- -

FSU

Belarus M M M -

Lithuania M M M L

Russian

Federation

M L M M

Ukraine M M L M

CPA

China M H H M

Viet Nam L M M -

SAS

India M H M M

Pakistan M H M L

PAS

Indonesia L M M L

Korea, Republic of M M M M

Taiwan, China M L L M

PAO

Japan M M L M

Abbreviations: - = negligible, L= Low, M= medium, H= high; NAM-North America, LAM-Latin

America, AFR-Africa, WEU-Western Europe, EEU-Eastern Europe, FSU-Newly Independent States

of the former Soviet Union, CPA- Centrally planned Asia and China, SAS-South Asia, PAS-Other

Pacific Asia, PAO-Pacific OECD

1.4.2. 2004 NEA study: Non-electricity products of nuclear energy [5]

As shown in the IAEA study, the potential non-electricity product market open to nuclear energy

seems to be large; district heat, process heat, and desalinated water in the near term, and hydrogen in

the long term. For example, assuming that current district heat in the world would be replaced by

nuclear energy, it would mean the addition of 340 1000 MWth reactors. However, the reality does not

match the potential. Even though the high potential needs to be considered in a vision for the future,

realistic demand needs to be assessed, which was the purpose of the OECD-NEA study of 2004 [5].

From the beginning of the project, some basic questions related to the real deployment of nuclear non-

electricity products were raised, including:

• If nuclear energy has such high potential in non-electricity product markets, why has its

deployment been so limited? Can one expect some dramatic changes in this market situation?

• Who will or should initiate actions for the deployment of non-electricity applications of nuclear

energy: the government, R&D institutes, vendors, or suppliers? If necessary, how should

vendors or suppliers be motivated? Would some policy measures (tax reduction, subsidies, or a

carbon tax) really work?

• What are the thoughts of suppliers and vendors (nuclear and non-nuclear) in the current market?

• What is the role of the government? Do governments consider seriously all nuclear options in

their national energy policies for greenhouse gas reduction and energy security?

Common sense provides reasonable-guess answers to the above questions, but more investigations are

required to support an authoritative report. Deeper studies including market analyses are needed for

enhanced understanding of realistic projected demand, which can be carried out only with the support

of national experts providing relevant input data. Also, country-specific information is needed to

analyze the reasons for the limited deployment of non-electrical applications of nuclear energy and to

draw policy recommendations. Since few country reports were received at the time of the NEA report,

that part of the study was not complete.

With its limitations, the NEA study led to the following preliminary findings and recommendations:

• There is a need to understand better the markets and to increase communication with key actors.

Convincing all actors in the market (customers, suppliers, vendors, research institutes, and

government) is critical for the introduction of nuclear non-electricity products in the market. In

this regard, the establishment of some interest groups on nuclear applications in the market

would be valuable. Considering that a large part of non-electricity energy demand is in

developing countries and that developed countries would provide relevant technologies, it

would be better to have some connections between developed countries and developing

countries, especially in the case of nuclear desalination.

• According to the demand pattern in the individual market, the requirements for nuclear systems

will be different. For example, if demand for distributed rather than centralized hydrogen

production prevails, the development of small- and medium-sized reactors would be relevant.

The development of nuclear non-electricity product technologies, in turn, may affect the shaping

of the demand pattern through providing timely attractive options. In this connection, it is

essential for the nuclear energy sector to be involved and participate actively in the discussions

on non-electricity applications including the hydrogen economy.

• For successful penetration in a market, early demonstration is critical. Especially, the long-term

prospects for alternative technology options for hydrogen generation will depend to a certain

extent on early demonstration of feasibility and viability. For instance, nuclear-assisted steam

methane reforming could be pursued as an early nuclear option, which will facilitate further

market penetration of more innovative nuclear hydrogen production technologies (see

Chapter 6).

• In the light of recent trends in energy markets, strong competition is expected between

alternative options to supply non-electricity products. For example, there are many technical

options for hydrogen production and a large number of technologies, such as steam reforming of

methane, steam-coal gasification with sequestration of CO

, and solar photovoltaic processes,

are already available or under development. Nuclear non-electricity production technology

should be ready for deployment and competitive within a deregulated market. Regardless, the

demand for relevant reactors is unlikely to be comparable to the mass reactor orders that

occurred in the 1960s and 1970s.

• The development of nuclear non-electricity product technologies, especially hydrogen

production technologies, requires long-term commitment with many uncertainties. All

stakeholders in government bodies and the industry have a role to play for the eventual success

of relevant technologies. Coordination and joint efforts are essential in organizing R&D

programmes, infrastructure building, and policy making to address the challenges of developing

competitive and efficient technical processes.

• In countries wishing to rely on nuclear energy in the long term, the role of governments for the

emergence of non-electrical applications of nuclear energy is important in terms of basic R&D,

initial technology development and demonstration, and policy making to create a favourable

business environment without interfering with market mechanisms.

• International cooperation is essential to ensure the design and implementation of nuclear

systems efficient for non-electrical applications of nuclear energy such as hydrogen production.

In particular, the efforts required in the field of nuclear R&D and infrastructure building, are

likely to be beyond an individual country’s capabilities. In this context, undertakings such as the

Generation IV International Forum (GIF) and the International Partnership for the Hydrogen

Economy (IPHE), for example, can enhance the synergy between national programmes and the

effectiveness of the overall efforts.

1.5. Impact of externalities on cost of power from fossil/ nuclear/ renewable sources [9]

It is now generally recognized that the production and consumption of energy and related activities is

linked to a wide range of environmental and social problems such as the health effects of pollution of

air, water, and soil; ecological disturbances and species loss; and landscape damage. The costs of such

damages are referred to as external costs or externalities.

An externality arises when the social or economic activities of one group of persons have an impact on

another group and when that impact is not fully accounted or paid for by the main actors causing the

damages. In the particular case of energy production, fuel cycle externalities are the costs imposed on

the society and the environment that are not accounted for (i.e., not integrated in the market pricing

system) by the producers and consumers of energy.

The term fuel cycle refers to the chain of processes linked to the generation of electricity from a given

fuel. A comparative evaluation has been made for the following technologies and fuel cycles [9]:

• Fossil fuels: coal and oil technologies, with varying degrees of flue gas cleaning, natural gas,

centralized systems and CHP etc.;

• Nuclear: a PWR, and associated fuel cycle services, with and without reprocessing;

• Renewables: solar, on-shore and off-shore wind, hydro-electricity, a wide range of biomass

fuels.

Comparisons of damage costs/kWh for various technologies in EU countries are presented in

Table 1.12.

Table 1.12. External costs of electricity production in the EU from

existing technologies [9] (10

-2

$/kW.h*)

Country Coal and

lignite

Oil Gas Nuclear Biomass Hydro Solar PV Wind

Austria

1.3 to 3.8 2.5 to 3.8 0.13

Belgium

5.1 to 19 1.3 to 2.5 0.64

Denmark

5.1 to 8.9 2.5 to 3.8 1.3 0.13

Finland

2.5 to 5.1 1.3

France

8.9 to 12.7 10.2 to 14.0 2.5 to 5.1 0.38 1.3 1.3

Germany

3.8 to 7.6 6.4 to 10.2 1.3 to 2.5 0.25 3.81 0.76 0.063

Greece

6.4 to 10.2 3.8 to 6.4 1.3 0 to 1.01 1.3 0.32

Ireland

7.6 to 10.2

Italy

3.8 to 7.6 3.8 to 7.6 0.38

Netherlands

3.8 to 5.1 1.3 to 2.5 0.89 0.64

Portugal

5.1 to 8.9 1.3 to 2.5 1.3 to 2.5 0.038

Spain

6.4 to 10.2 1.3 to 2.5 3.8 to 6.4** 0.25

Sweden

2.5 to 5.1 0.38 0 to 0.89

United

Kingdom

5.1 to 8.9 3.8 to 6.4 1.3 to 2.5 0.32 1.3 0.19

* Sub-total of quantifiable externalities (global warming, public health, occupational health, and material

damage); on the basis of 1€ = $1.27.

** Biomass co-fired with lignite.

Table 1.12 leads to the following conclusions:

• External costs are extremely site dependent.

• In general, wind technologies are most environmentally friendly with respect to greenhouse gas

pollutants and particles. However, not every site is appropriate for wind power generation,

which has other environmental costs, including noise.

• Nuclear power generates the lowest external costs after wind power, even when low-probability

accidents with high consequences are integrated into the calculation. These results are generated

for 0% discount rates. At a 3% discount rate, the external costs from nuclear are lower.

• Photovoltaic solar power is the cleanest technology regarding its immediate use. It has,

however, considerable life cycle impacts due to the fabrication of solar panels.

• Gas-fired technologies are relatively clean.

• Coal technologies are the worst in view of their high generation of CO

. They appear to have

high impacts due to primary and secondary aerosols.

Figure 1.3 shows an illustrative example of the power costs from various power plants for selected

sites in Germany, with 2010 technologies [9].

FIG. 1.3. External costs of power stations in Germany

(CO

=19 euros/t, 1 year of life lost = 50 000 euros) [9].

It is observed that for the fossil fuelled electricity systems, human health effects, acidification of

ecosystems, and potential global warming impacts are the major sources of external costs. Although

the analysed power plants are all supposed to be equipped with abatement technologies, the emissions

of SO

and NO

due to the subsequent formation of sulphate and nitrate aerosols leads to considerable

health risks.

External costs arising from the nuclear fuel cycle are significantly lower than those estimated for fossil

fuel cycles.

External costs from renewable fuel cycles and hydropower mainly result from the use of fossil fuels

for material supply and during the construction phase. External costs from current PV technologies are

higher than from nuclear and are close to those for gas fired plants.

Impacts from wind and hydropower cycles are the lowest.

Internalization of external costs into power costs

A logical and sustainable way to permit the choice between various technologies is to integrate the

external costs with the production costs of these technologies.

Taking the above external costs and current generating costs of electricity in Germany; one would thus

obtain the results shown in Figure 1.4. [9]

FIG. 1.4. Total costs of various electricity generating technologies in Germany [9].

It is clearly seen that the power generation costs for renewable energies, especially for solar energy,

are much higher than for fossil energies or nuclear energy. It is also obvious that the full integration of

external costs in the nuclear case would render it economically the most attractive option.

1.6. Conclusion

The advantage of nuclear energy in alleviating the risk of climate change will not favour market

penetration of nuclear products through advanced non-electric applications of nuclear power as long as

energy policies internalising the value of carbon and other pollutants are not implemented. National

policies on climate change vary from country to country, but very little has been done to credit nuclear

energy systems for their contribution to reducing green house gas emission. The entry into force of the

Kyoto Protocol in February 2005 does, however, create incentives that can benefit nuclear power,

depending on how they are translated into national policies. The Protocol’s emission trading

provisions effectively give a cash value to unused emission allowances in the Russian Federation, for

example, and the European Trading Scheme (ETS) creates incentives favourable to nuclear power in

at least those European countries where implementation policies are not specifically biased against

nuclear power.

In considering the deployment of nuclear energy for non-electric applications, challenges and

difficulties should not be overlooked; in particular, it should be acknowledged that a scientific

potential is not a technical reality and that competition will drive the choice of energy sources for each

application. Considering the potential requirements and technical capabilities of nuclear energy

systems, their non-electric applications seem rather promising. Moving from their potential to realities

is undoubtedly feasible, but will need time, investments, and policy measures to address a wide range

of techno-economic and socio-potential challenges.

If non-electric products of nuclear energy were to penetrate markets on a significant scale, the role of

nuclear energy in supply systems could change dramatically from a marginal player to a main

contributor. However, such an achievement will materialize only if considerable technical, economic,

social, and political challenges are overcome. This can require a long lead time ― up to several

decades for some applications.

Public acceptance is a major issue for nuclear energy. However, non-electric applications, for example

desalination or district heating, can play an important role in acceptance of the nuclear power by local

communities.

REFERENCES FOR CHAPTER 1

[1] INTERNATIONAL ATOMIC ENERGY AGENCY, Non-electric Applications of Nuclear

Energy, IAEA-TECDOC-923 (1997).

[2] INTERNATIONAL ATOMIC ENERGY AGENCY, Status of Non-electric Nuclear Heat

Applications; Technology and Safety, IAEA-TECDOC-1184 (2000).

[3] INTERNATIONAL ATOMIC ENERGY AGENCY, Introduction of Nuclear Desalination-A

Guidebook, TRS No. 400 (2000).

[4] INTERNATIONAL ATOMIC ENERGY AGENCY, Market Potential for Non-electric

Application of Nuclear Energy, TRS No. 410 (2003).

[5] OECD/NUCLEAR ENERGY AGENCY, Non-electricity Products of Nuclear Energy, OECD-

NEA Report (2004), published on NEA webpage:

http://www.nea.fr/html/ndd/reports/2004/non-electricity-products.pdf

[6] U.S. DOE Nuclear Energy Research Advisory Committee & GIF (2002), Generation IV

Roadmap: GIF-008-00.

[7] VERFONDEN, K. et al., Michelangelo Network recommendations of nuclear hydrogen

production, Int. J. Nuclear Hydrogen Production and Application, Vol 1, No 1, 2006 pp.68-78.

[8] INTERNATIONAL ATOMIC ENERGY AGENCY, Nuclear Power Reactors in the World,

IAEA RDS No. 2 (2006).

[9] INTERNATIONAL ATOMIC ENERGY AGENCY, Economics of Nuclear Desalination - New

Developments and Site-Specific Studies, Final Report of a Coordinated Research Project 2002-

2006, IAEA-TECDOC-1561 (2007).

CHAPTER 2

NUCLEAR DESALINATION

2.1. Opportunities

Water, energy and environment are essential inputs for the sustainable development of society. These

are, therefore, current national and international issues, and have been addressed by many fora. Recent

statistics show that currently 2.3 billion people live in water-stressed areas and, among them, 1.7

billion live in water-scarce areas, where the water availability per person is less than 1000 m

/year.

The situation is going to worsen further; statistics show that by 2025 the number of people suffering

from water stress or scarcity could swell to 3.5 billion, and 2.4 billion of them are expected to live in

water-scarce regions. Water scarcity is a global issue, and every year new countries are affected by

growing water problems [1].

Seventy percent of the earth is covered with water, but only 2.5% of that is fresh water. Nearly 70% of

this fresh water is frozen in the icecaps of Antarctica and Greenland. Most of the rest is in the form of

soil moisture or in deep inaccessible aquifers, or comes in the form of monsoons and floods that are

difficult to contain and exploit. Less than 0.08% of the world’s water is thus readily accessible for

direct human use, and even that is very unevenly distributed.

In the light of this, the Millennium Declaration by the UN General Assembly in 2000 set a target to

halve, by the year 2015, the world population who are unable to reach or to afford safe drinking water.

In Vision 21, the shared vision for Hygiene, Water Supply and Sanitation has a target to provide water,

sanitation and hygiene for all by 2025 [2].

Better water conservation, water management, pollution control and water reclamation are all part of

the solution to projected water stress. So too are new sources of fresh water, including the desalination

of seawater and brackish water. Desalination technologies have been well established since the mid-

century and widely deployed in the Middle East and North Africa. The contracted capacity of

desalination plants has increased steadily since 1965 and is now about 36 million m

/d worldwide [3],

as shown in Figure 2.1. The top line in the figure shows total operating and contracted capacity. The

bottom line in the figure shows just operating capacity. This capacity could provide the world’s

population roughly 6 litres a day per capita of fresh potable water. If this capacity were available to the

1.5 billion in the world without direct access to drinking water, it would provide approximately

20 litres/day each.

FIG. 2.1. Cumulative capacity of all land-based desalination plants (unit capacity > 100 m

/day)

(reprinted with the permission of the author) [3,6].

Large-scale commercially available desalination processes can generally be classified into two

categories: (a) distillation processes that require mainly heat plus some electricity for ancillary

equipment, and (b) membrane processes that require only electricity to provide pumping power. In the

first category (distillation) there are two major processes: multi-stage flash (MSF) and multi-effect

distillation (MED). In both, seawater is heated; the steam that evaporates is condensed and collected as

freshwater; and the residual brine is discharged. In the second category (membranes) is the reverse

osmosis process (RO), in which pure water passes from the high-pressure seawater side of a semi-

permeable membrane to the low-pressure freshwater permeate side. The pressure differential must be

high enough to overcome the natural tendency for water to move from the low concentration

freshwater side of a membrane to the high concentration seawater side, in order to balance osmotic

pressures.

The energy for these plants is generally supplied in the form of either steam or electricity using fossil

fuels. The intensive use of fossil fuels raises environmental concerns, especially in relation to

greenhouse gas emissions. The depletion of fossil sources and the future price uncertainty of fossil

fuels and their better use for more vital industrial applications is also a factor to be considered for

sustainability. Many countries deprived of valuable fossil resources are therefore considering the

introduction of a nuclear power program or expansion of their existing nuclear power program.

2.2. Market context [4]

In recent years, the option of combining nuclear power with seawater desalination has been explored

to tackle water shortage problems. The desalination of seawater using nuclear energy is a feasible

option to meet the growing demand for potable water. Over 175 reactor-years of operating experience

on nuclear desalination have been accumulated worldwide. Several demonstration programs of nuclear

desalination are also in progress to confirm its technical and economical viability under country-

specific conditions, with technical coordination or support of IAEA.

There are many reasons that favour a possible revival of nuclear power production in the years to

come: the development of innovative reactor concepts and fuel cycles with enhanced safety features

that are expected to improve public acceptance, the production of less expensive energy as compared

to other options, the need for prudent use of fossil energy sources, and increasing requirements to

curtail the production of greenhouse gases (GHGs). It is estimated that water production of 10 million

/d by seawater desalination using fossil fuels would release 200 million t/y of CO

, 200 000 t/y of

, 60 000 t/y of NO

and 16 000 t/y of other hydrocarbons. For the current global desalting plant

capacity of 40 million m

/d the total emissions would be four times these values. This can be avoided

if nuclear or renewable energy sources are used for desalination. It is estimated that for producing

fresh water with the present desalination capacity, but by using nuclear energy, the needed nuclear

capacity would be about 40 1000 MWe nuclear reactors.

Using nuclear energy for the production of freshwater from seawater and brackish aquifers (nuclear

desalination) has been of interest in several IAEA Member States as a result of acute water shortage

issues in many arid and semi-arid zones worldwide. This stems from their expectation of not only its

possible contribution to the freshwater issue, but has also been motivated by a variety of reasons that

include: likely competitiveness of nuclear desalination in areas lacking cheap hydropower or fossil

resources, energy supply diversification, conservation of fossil fuel resources, and spin-off effects of

nuclear technology for industrial development.

2.2.1. Nuclear desalination market - past experiences and plans [4]

The desalination of seawater using nuclear energy is a demonstrated option having over 180 reactor-

years of operating experience worldwide, of which Japan now has over 150 reactor-years, with ten

nuclear power plants that also produce desalinated water. Kazakhstan (the Aktau fast reactor BN-350)

had accumulated 26 reactor-years of producing 80,000 m

/day of potable water before shutting down

in 1999. In the USA, the Diablo Canyon nuclear power plant produces desalinated water. Presently

India and Pakistan are setting up nuclear demonstration projects at their existing PHWRs. Operating

experience for all non-electric applications including desalination, district heating and process heat is

around 1000 reactor years (Table 1.2).

Table 2.1 summarizes past experience as well as current developments and plans for nuclear-powered

desalination using different nuclear reactor types. Most of the technologies in Table 2.1 are land-

based, but the table also includes a Russian initiative for barge-mounted floating desalination plants.

Floating desalination plants could be especially attractive for responding to emergency demands for

potable water.

Table 2.1. Reactor types used or considered for desalination

Reactor

Type

Location Capacity (m

/d) Status

LMFR

Kazakhstan (Aktau) 80,000 In service till 1999

PWRs

Japan (Ohi, Takahama, Ikata,

Genkai)

1,000-2,000 In service with operating

experience of over 150 reactor-

years

Rep. of Korea 40,000 SMART integral PWR is being

designed

Russia Floating Power Unit for

electricity and heat is under

construction; possible later units

could be used for electricity and

desalination

USA (Diablo Canyon) ~4500 In service

BWR

Japan (Kashiwazaki) Never in service following

testing in 1980s; owing to

alternative freshwater sources,

dismantled in 1999

HWR

India (Madras) 6,300 Under commissioning (RO

commissioned in 2002, MSF to

be commissioned by the end of

2007).

Pakistan (KANUPP) 4,800 Under construction, to be

commissioned by the end of

2007

NHR

China 120,000 Under design

HTGR

South Africa, France, The

Netherlands

Under consideration

Table 2.2 shows the operating nuclear desalination plants in Japan.

Table 2.2. Operating nuclear desalination plants in Japan

Plant

name

Location

Application

Start of

operation

reactors /

desal.

Net

Power

(MW(e))

Water

capacity

/d)

Remarks

Ikata-1,2 Ehime Electricity/

desalination

1977-82

1975

566 2000 PWR/MED,

MSF

Ikata-3 Ehime Electricity/

desalination

1994

1992

566 2000 PWR/MSF

(2 x 1000 m

/d)

Ohi-1,2 Fukui Electricity/

desalination

1979

1973-76

1175 3900 PWR/MSF

(3 x 1300 m

/d)

Ohi-3,4 Fukui Electricity/

desalination

1991-93

1990

1180 2600 PWR/RO

(2 x 1300 m

/d)

Genkai-4 Fukuoka Electricity/

desalination

1997

1988

1180 1000 PWR/RO

Genkai-3,4 Fukuoka Electricity/

desalination

1995-97

1992

1180

1000

PWR/MED

Takahama Fukui Electricity/

desalination

1985

1983

870 1000 PWR/RO

The salient features of the existing and proposed nuclear desalination demonstration projects and a

number of feasibility studies conducted by interested Member States [5] are given in Annex 1.

2.2.2. Economics [3]

Over the years, the cost of water produced in seawater desalination plants has dropped considerably,

but the cost of water produced in conventional treatment plants has risen, due to over-exploitation of

aquifers, intrusion of saline water in coastal areas, and generally increasing contamination of ground

water. Fig 2.2 shows the water costs from global seawater desalination and conventional production

(in various countries). Seawater desalination costs are already comparable to conventional water costs

in water scarce/starved countries and are likely to approach each other even in the countries having

cheap, abundant water sources. This makes the prospects of seawater desalination quite promising.

FIG. 2.2. Development of water costs (reprinted with the permissionof the author) [3].

Fig. 2.3 shows the capacity of desalination plants in various countries. As can be seen, the major

contribution comes from the Middle East countries, followed by US, Spain, and the Caribbean

countries. In recent years, plans for large-scale deployment of desalination in Asia and Pacific

countries have been reported.

Presently, the total capacity of desalination plants worldwide is of the order of thirty-six million cubic

meters/day. The major contribution comes from the Middle East countries.

Desalination processes are energy intensive, and energy is the major cost component of the water

produced. As most of the current desalination is based on fossil energy sources, the cost of desalted

water varies with the prevailing fuel costs in particular areas. Apart from the fossil fuel cost and its

availability, the associated environmental concerns of late have kept in abeyance the launching of

some large-scale desalination projects. This has led to a search for renewable and other sustainable

energy sources including nuclear.

There are no officially reported cost data from existing nuclear desalination plants. Several feasibility

studies, however, have been carried out by the Member States under the IAEA’s coordinated research

projects and technical cooperation programmes. Some results are reported in IAEA-TECDOC-1561

[6].

Preliminary techno-economic studies conducted in China for the NHR-200 reactor coupled to a

160,000 m³/d vertical-tube evaporator multi-effect distillation (VTE-MED) plant estimated the

desalted water cost to be around 0.68 US$/m³. A similar economic evaluation of the integrated

SMART-MED desalination plant of 40,000 m³/d capacity indicated the water cost ranging from 0.70

to 0.90 US$/m³. The projected cost of water from the Russian KLT-40 floating reactor based nuclear

desalination plants is also in these same ranges. These costs are comparable with desalination costs

using locally available fossil fuels.

Pre-feasibility studies have been carried out recently for the proposed nuclear desalination projects at

Madura, Indonesia, and La-Skhira, Tunisia, under an IAEA technical cooperation inter-regional

project (1999-2004). These indicate economic competitiveness of nuclear desalination over fossil-

based plants under the specific conditions in their countries.

Despite large interest of the Member States which are considering deployment of nuclear desalination

plants and IAEA’s efforts in bringing about information exchange among the technology providers

and the user countries, no significant progress is reported in the deployment of nuclear desalination

plants. Today nuclear desalination contributes only 0.1 % of total desalting capacity worldwide.

Economic comparison with fossil desalination

Table 2.3 provides some comparative water costs of present-day fossil-based desalination plants and

projected costs of water from nuclear desalination projects from recent feasibility studies in Member

States.

Table 2.3. Water costs from fossil desalination plants and estimated costs

from nuclear desalination

Country Capacity (m

/d) Process Water costs ($/m

)

Fossil based

Singapore 135,000 RO 0.45

Ashkelon (Israel) 165,000 RO 0.52

Al-Taweelah (UAE)

Fujairah

237,500

375,000

MED

MSF-RO

0.70

0.80

Nuclear based

Argentina (CAREM) 12,000 RO 0.72

China (NHR-200) 160,000 MED 0.68

Rep. of Korea

(SMART)

40,000 MED 0.80

The projected costs for nuclear desalination appear to be marginally higher than the actual costs from

present-day commercial desalination plants using fossil sources. Various aspects of cost reduction

strategies in nuclear desalination are presently being proposed to make it more competitive.

Table 2.4 shows the desired objectives to be achieved for producing potable water economically from

nuclear desalination plants [7].

Table 2.4. Desired objectives for economic costs

Reactor cost $/kWe 2000 – 1000 $/kWe

construction time

lifespan

electricity cost

60 - 40 months

40 - 60 years

0.06 – 0.04 $/kWh

Desalination plant cost 1500-800 $/m

plant life

construction time

water cost

> 30 years

24 months

0.80 – 0.45 $/m

Variables reactor size

plant capacity

seawater salinity

temperature

40 -600 MWe

50,000 – 200,000 m

30,000 – 45,000 ppm

18 – 35

The broader picture, however, is that the worldwide use of desalination is still negligible compared to

the demand for fresh water. To become a noticeable market for nuclear energy, desalination needs to

compete successfully with alternative means of increasing fresh water supply. For nuclear desalination

to be attractive in any given country, two factors must be in place simultaneously: a lack of fresh water

and the ability to use nuclear energy for desalination. In most regions, only one of the two is present.

Both are present for example in China, the Republic of Korea and, even more so, in India and

Pakistan. These regions already account for almost half the world’s population, and thus represent a

potential long-term market for nuclear desalination.

2.3. Challenges [8]

The following sections describe the key challenges facing nuclear desalination.

2.3.1. Economics

Economic comparisons indicate that water costs (and associated electricity generation costs) from

nuclear seawater desalination are generally in the same range as costs associated with fossil-fuelled

desalination at their present costs. Given the conclusion that nuclear and fossil-fuelled desalination are

broadly competitive with each other, any particular future investment decision will depend on site-

specific cost factors and on the values of key parameters (capital cost, fuel price, interest rate,

construction time, etc.) at the time of investment. Higher fossil fuel prices would, of course, favour

nuclear desalination; higher interest rates would favour less capital-intensive fossil-fuelled options.

2.3.2. Infrastructure development

Those countries suffering from scarcity of water are, generally, not the holders of nuclear technology,

do not generally have nuclear power plants, and do not have a nuclear power infrastructure. The

utilization of nuclear energy in those countries will require infrastructure building and institutional

arrangements for such things as financing, liability, safeguards, safety, and security and will also

require addressing the acquisition of fresh fuel and the management of spent fuel. The concept of

multi-national fuel cycle centres as are being examined by IAEA could be used to assure a supply of

nuclear material to legitimate would-be users under control of sensitive parts of the nuclear fuel cycle.

2.3.3. Public perception

The design of nuclear desalination plants address various aspects related to nuclear plant safety. The

possibility of radioactive contamination of product water is also an important issue to be considered

for nuclear desalination plants. The dissemination of data from existing facilities that carry out nuclear

desalination would help to alleviate the concern and improve the public perception for nuclear

desalination plants.

2.3.4. Socio-environmental aspects

The socio-environmental aspects of nuclear desalination need greater attention for its large-scale

adoption. Setting up a desalination plant at nuclear reactors for providing much-needed fresh water to

the public will no doubt add to social acceptance of nuclear desalination, if the quantity and quality of

the fresh water are consistently assured.

The intakes/outflows of nuclear desalination plants must be designed to assure the continued use of

areas for fishing and other socio-cultural activities. Protection of the marine environment near the

desalination plant site, particularly the flora and fauna, needs to be assured. The use of the reject brine

from the desalination plants for pisciculture or other uses such as the production of useful minerals is a

possibility worth consideration [9].

Studies have reported on the significant reduction in water cost if a carbon tax were considered in the

future if nuclear is accepted as a Clean Development Mechanism under the Kyoto Protocol. The

environmental impact assessment of nuclear-powered desalination systems further indicates

advantages over fossil-based energy sources. These would result in enhanced economic

competitiveness of nuclear desalination plants.

2.4. Solutions [10]

2.4.1. Utilization of waste heat from nuclear reactors

2.4.1.1. Utilization of waste heat from the condensers of LWRs and HWRs for pre-heat RO (the

ROph process)

The net electrical efficiencies of the power conversion systems in most water-cooled reactors are of

the order of 30 to 33%. This means that nearly two thirds of the net thermal power produced in the

reactors is evacuated to the heat sink through the condensers. The temperature of the water from the

condensers is too low (30 to 32°C) for meaningful desalination with distillation processes. However,

this relatively hot water can be fed to an innovative variant of the RO process, with preheating now

known as the ROph process. In hybrid systems, it is also possible to use the cooling seawater return

stream from the thermal desalination component as feed to the RO component.

The viscosity of the feedwater is inversely proportional to its temperature. Thus, as temperature

increases, water viscosity decreases and RO membranes become more permeable, with a consequent

increase in production.

CANDESAL first developed an advanced reverse osmosis (RO) desalination system that emphasizes a

non-traditional approach to system design and operation. Key features of this advanced approach to

RO system design and operation are the use of preheated feedwater, operation at high pressures,

advanced feedwater pre-treatment, advanced energy recovery systems, site-specific optimization, and

automatic real-time plant management systems (Fig 2.4 and 2.5).

0.6

0.7

0.8

0.9

1.1

1.2

20 25 30 35 40 45 50

Temperature, C

Relative Water Production

62.1 bar (900 psi)

69 bar (1000 psi)

FIG. 2.4. Water production vs. temperature[10].

10 15 20 25 30 35 40 45

Feed water temperature, C

Required feed

pressure, bar

35K

38K

43K

45K

R, %

FIG. 2.5. Required feed pressure vs. salinity and temperature [6]. Here, R is the percentage of

recovery of fresh water from seawater and the curves represent different salinity levels of seawater,

from 35,000 ppm to 45,000 ppm.

As can be seen from Fig 2.4, there is a 2-3 % increase in water production per degree rise in seawater

feed temperature. This helps in reducing the applied pressure and hence the pumping power with

rising temperature (Fig 2.5). Thus, an energy saving of nearly.10% is achievable in pre-heat RO

plants. An important consideration in ROph is that it can easily use the hot water from the main

condensers of the water-cooled nuclear power plants.

The amount of feedwater preheating depends both on the ambient seawater temperature and the

specifics of the nuclear reactor design. The only limitation is that the maximum temperature allowed

by the RO membrane design limits must not be exceeded. Currently available RO membranes

typically have a limit of about 45°C, though this is expected to increase as membrane performance

continues to be improved by the manufacturers. Cost savings are possible at all temperatures where

waste heat can be used to preheat the feedwater, but overall savings depend on a number of factors

that are site specific: the salinity of the feedwater, the size of the plant, the amount of preheat

available, etc.

2.4.2. Waste heat utilization from Indian PHWRs for thermal desalination

2.4.2.1. Research reactor CIRUS

For conducting a practical demonstration of waste heat utilization, BARC (India) designed a low-

temperature vacuum evaporator (LTE) desalination plant and coupled it to the research reactor

CIRUS.

The product water from this plant meets the make up water requirements of the reactor. The reactor

produces 40 MWth using metallic fuel, a heavy-water moderator, demineralized water coolant, and

seawater as the secondary coolant. To ensure protection against radioactive contamination, an

intermediate circuit has been incorporated between the reactor and the LTE plant. Table 2.5

summarizes the operating data of this plant. Such experience could be used for a larger sized plant

utilizing waste heat.

Table 2.5. Typical operating data of the CIRUS reactor providing waste heat for desalination

Parameter Unit Value

Hot water flow rate liters/minute 1500

Hot water inlet temperature °C 53.6

Hot water outlet temperature °C 47.5

Seawater flow rate liters/minute 1200

Seawater TDS ppm 35 000

Seawater inlet temperature °C 27.6

Seawater outlet temperature °C 35.5

Vacuum in the evaporator mm Hg 700

Product water flow rate L/minute 15.5

Product water conductivity µS/cm 7

2.4.2.2. Waste heat utilization from the 500 MWe PHWR

In the 500 MWe Indian PHWR, the heavy-water moderator is cooled from 80 to 55 °C by process

water, which in turn is cooled to 35 °C by seawater that enters at 32°C and comes out at 42°C. About

100 MWth is thus available as waste heat for seawater desalination.

The details have been worked out using 55°C process water temperature, providing heat to the

desalination process, to avoid any changes in the moderator system. The coupling scheme is presented

in Figure 2.6.

The nuclear desalination system produces about 1000 m

/day of desalinated water, which is about 25%

more than the total makeup demineralized (DM) water requirements of the 500 MWe PHWR.

It is considered more economical to use this water as make up DM water because:

• The energy cost for the LT-MED plant is essentially zero, since it only uses waste heat;

• Direct production of distilled water eliminates the need for demineralizers and regeneration

chemicals;

• The raw water, otherwise used as feed for the DM plant, can be made available for other

purposes such as for drinking.

FIG. 2.6. PHWR500 coupling scheme, utilizing waste heat (reprinted from IAEA-TECDOC-1561 [6]).

2.4.3. Utilization of hybrid systems

The advantages of hybrid desalination systems will be illustrated by a specific example: that of the

hybrid MSF-RO system coupled to the MAPS PHWR at Kalpakkam (India) as shown in Figure 2.7.

As one of the leading and oldest desalination processes, MSF is often preferred because of its

operational simplicity and proven performance. MSF is advantageous for large desalting capacities

and high purity water, in particular where inexpensive thermal energy is available.

However, its installed cost and specific power consumption remain relatively high. Since the energy

cost is high in India, an MSF system, with a large gain output ratio (GOR) leading to lower water

production costs, has been chosen.

Sea Water In

1700 kg/s, 32

72.5

Heavy Water

972 kg/s

Process Water

1215 kg/s, 32

Sea Water In

720 kg/s, 32

Sea Water Out, 42

Feed

30 kg/s

Blow down

17.5 kg/s

Sea Water Out

CONDENSE

Product Water

12.5 kg/s, 44.5

1. Moderator heat exchanger 2. Process water heat exchange

3. Desalination Unit 4. Product water pump

ote: When the desalination unit is shut down, the sea water

required for the process water heat exchanger is 2430 kg/s at 32

FIG. 2.7. Hybrid MSF-RO coupling to the PHWR at Kalpakkam, India

(reprinted from IAEA-TECDOC-1561 [6]).

Seawater desalination by RO has proved to be most economical, as has been shown in the case studies

from IAEA Member States. Apart from its need for an elaborate pre-treatment plant, RO has many

advantages:

• Enhanced flexibility due to its modular structure;

• Operation at ambient temperature, reducing corrosion risks;

• Possibility of coupling with energy recovery devices, thus further reducing the costs;

• Potential for further innovations as compared to the MSF technology, which has almost reached

a saturation point in its development.

Because of the particular advantages of MSF and RO technologies, it is logical to consider that a

hybrid MSF-RO system may lead to greater cost reductions in water costs because of:

- The use of common, smaller seawater intake and outfall structures and other facilities;

- Flexible and improved water quality by blending distillate from the MSF plant and the

permeate from the RO plant;

- Extension of membrane lifetimes as a result of blending.

Awerbuch has reported that applying a hybrid solution reduces desalinated water costs, compared with

non-hybrid schemes, from as little as 2-3% to as much as 15% [11].

2.5. Conclusion

Seawater desalination provides a source of fresh water, especially for the water scarce arid and semi-

arid areas of the world. The present desalination capacity of about 36 million cubic meters per day

worldwide meets a very small fraction of the world’s fresh water needs. There is, however, a

significant potential of desalination and water reuse technology for rapid expansion to augment the

fresh water resources in the water scarce areas. Use of fossil fuels for large-capacity desalination

plants could lead to large emission of undesired greenhouse gases. The price uncertainties of fossil

fuels and their sustainability is also an important issue. Use of energy from nuclear reactors for

desalination is a demonstrated option; it is environmentally friendly and can be a sustainable energy

source. Feasibility studies carried out recently indicate that present costs of water produced from

nuclear desalination plants are similar to those of fossil fuel based desalination plants. The

development of higher-temperature and more economical reactor designs would likely reduce the

desalinated water cost. Nuclear desalination will be an important option for safe, economic and

sustainable supply of large amounts of fresh water to meet the ever-increasing worldwide water

demand.

REFERENCES FOR CHAPTER 2

[1] SOMMARIVA, C., Desalination & Water Reuse Quarterly, Vol.13, No.2, (2003), pp. 13-16.

[2] UNESCO, Water for People Water for Life, The United Nations World Water Development

Report, UNESCO Publishing (2002).

[3] WANGNICK, K., IDA World’s Desalting Plants Inventory, Report No. 18 (2004).

[4] MISRA, B.M., Role of Nuclear Desalination in Meeting the Potable Water Needs in Water

Scarce Areas in the Next Decades, Desalination 166 (2004) pp. 1-9.

[5] INTERNATIONAL ATOMIC ENERGY AGENCY, IAEA INDAG Newsletters, Issues 5 & 6,

Vienna (2005, 2006).

[6] INTERNATIONAL ATOMIC ENERGY AGENCY, Economics of Nuclear Desalination -

New Developments and Site-Specific Studies, Final Report of a Coordinated Research Project

2002-2006, IAEA-TECDOC-1561 (2007).

[7] MISRA, B.M., Status and Prospects of Nuclear Desalination, IDA World Congress on

Desalination and Water Reuse, Singapore (2005).

[8] MISRA, B.M., Status and Prospects of Nuclear Desalination, Atom for Peace- An International

Journal, Vol. 1, No. 2-3 (2006) pp. 216-226.

[9] NISAN, S., Extraction of Strategic Materials from the Concentrated Brine Rejected by

Integrated Nuclear Desalination Systems, Desalination, Vol 182, pp. 451-462, (2005).

[10] INTERNATIONAL ATOMIC ENERGY AGENCY, Status of Nuclear Desalination in IAEA

Member States, IAEA-TECDOC-1524, Vienna (2006).

[11] AWERBUCH, L., Hybridization & Dual Purpose Plant Cost Considerations, MEDRC Int. Conf.

on Desalination Costing, Limassol (2004) pp. 204-230.

CHAPTER 3

DISTRICT HEATING

3.1. Opportunities

Assessing realistic future demand for energy products other than electricity is not an easy task. Even

for heat demand, statistical data available are by far less exhaustive and robust than is the case for

electricity. Furthermore, as far as district heating is concerned, the heat distribution structure and

human settlement configuration are key driving factors that are difficult to predict.

District heat involves the supply of space heating and hot water through a district heating system,

which consists of heat plants (usually producing electricity simultaneously) and a network of

distribution and return pipes. A potential market for district heating appears in climatic zones with

relatively long and cold winters. In many countries, such as central and northern European countries

and countries in transition economies, district heat has been widely used for decades.

District heating accounts for 11% of total energy consumption in Central Europe and Ukraine and over

30% in Russia and Belarus. District heating accounts for almost half of the heat market in Denmark,

Estonia, Finland, Poland, Romania and Sweden. District heating networks generally have installed

capacities in the range of 600 to 1200 MWth in large cities to approximately 10 to 50 MWth in towns

and small communities [1]. Although a large number of district heat suppliers, especially in countries

with transition economies, are facing financial and technical problems, nuclear-based district heat is

still expected to have great additional potential for meeting a share of heat demand in many countries

that are currently using fossil fuels and are considering other sources owing to environmental

concerns.

In general, district heating can offer significant benefits because, under certain conditions, it can

compete economically in densely populated areas with individual heating arrangements, and because it

offers the possibility of reducing air pollution in urban areas. Whereas emissions resulting from the

burning of fuels can be controlled and reduced up to a point for relatively large centralized plants, this

is not practical in small individual heating installations fuelled by gas, oil, coal or wood.

Although it is hard to obtain exact statistics for the current use of district heat in the world, the size of

its market can be estimated in relation to the final energy demand in the residential, agricultural and

commercial sector. A 2002 IAEA report [2] took this approach and calculated the total use of district

heat in 1996 as 119.5 Mtoe based on the International Energy Agency (IEA) world energy database,

which requires a heat production capacity of 340 000 MWth assuming an average load factor of 50%.

District heating has the following technical requirements:

• It requires a heat distribution network to transport steam or hot water in a typical temperature

range of 80-150°C.

• Owing to higher losses over longer transmission distances, the heat source must be relatively

close to the customer, typically within 10-15 km.

• The district heat generation capacities are determined by the collective demands of the

customers. In large cities a capacity of 600-1200 MWth is normal. The demand is much lower

in small communities.

• The annual load factor is normally not higher than 50%, since heat is supplied only in the colder

part of the year.

• To secure a reliable supply of heat, a backup capacity is required.

Typically, coal and gas dominate the fuels used for district heating. Various other heat sources are also

used for district heating, including biomass materials, waste incineration, and waste heat from

industrial processes. Usually district heating is produced in a cogeneration mode in which waste heat

from electric power production is used as the source of district heat.

There is plenty of experience in using nuclear heat for district heating, so the technical aspects can be

considered well proven. There are no technical impediments to the application of nuclear reactors as

the heat source for district or process heating. Several countries already have experience in nuclear

district heating: Bulgaria, Hungary, Romania, Russia, Slovakia, Sweden, Switzerland and Ukraine.

For production of district or process heat, there are basically two options: Co-generation of electricity

and heat, and heat-only reactors. All existing reactor types can be used for cogeneration of heat and

electricity. Co-generation has been widely applied; there is not much experience with heat-only

reactors. In principle, any portion of the heat can be extracted from co-generation reactors as district

heat, subject to design limitations. Co-generation plants, when forming part of large industrial

complexes, can be readily integrated into an electrical grid system to which they supply any surplus

electricity generated. In turn, they would serve as a backup for assurance of the electricity supply. This

means a high degree of flexibility. Heat-only reactors, on the other hand, have only the objective of

heat production, not electricity generation. This limits their operational flexibility, especially during

warm weather, leaving the large capital investment stranded during times when heat is not needed.

As shown by experience, availability factors of 70% to 80% or even 90% can be achieved. These

values are similar to the availabilities achieved by fossil fuelled power plants. The frequency and

duration of unplanned outages can be kept very low with good preventive and predictive maintenance.

The availability of nuclear or fossil fuelled plants, however, can never reach the nearly 100% levels

required by most large heat users. Therefore, multiple-unit co-generation power plants, modular

designs, or backup heat sources are necessary to achieve the required availabilities.

Nuclear reactors are proven, safe, reliable and environmentally clean energy sources, but for

commercial deployment they also have to be economically competitive with alternative energy

sources. Compared to fossil fuelled sources, nuclear reactors are characterized by higher investment

costs compensated by lower fuel costs. With increasing fossil fuel prices the economically competitive

position of nuclear power, both for electricity generation and for heat supply, improves.

Due to economy of scale [3], nuclear economics are, in general, improved for larger units. This has led

to the development and predominant deployment of large reactors in industrialized countries with

large interconnected electrical grid systems. Nevertheless, there continues to be an interest in small

and medium-sized power reactors (SMRs), especially for applications other than base load electricity

generation.

The siting of nuclear plants is another issue. For co-generation or heat-only reactors, close location to

the load centres has a strong incentive. However, the trend is to choose remote, but accessible,

locations for siting nuclear plants in order to mitigate the consequences of an accident. Locating a new

plant far from densely populated areas makes it easier to comply with regulatory requirements.

Furthermore, plants need to be located near a ready supply of cooling water, which may not

necessarily correspond to the location of the population centre.

3.2. Market context

3.2.1. Early history of nuclear district heating markets [4]

Dedicated nuclear heating systems have been designed, built and operated in China and in the Russian

Federation. The plant in China is for demonstration purposes, whereas the Russian plants supply heat

to various settlements in the northern parts of the country.

A 5 MW(th) test nuclear heating reactor (NHR-5) was commissioned in China and has been in

operation since 1989, supplying heat to the Institute of Nuclear Energy Technology of Tsinghua

University, near Beijing. The Russian Federation has operated an experimental 10 MW(th) heating

reactor at Obninsk since 1954 and has developed the technology of the nuclear district heating reactor,

AST-500.

Nuclear co-generation plants for electricity and district heating have been built and operated in

Bulgaria, Hungary, Romania, Russian Federation, Slovakia and Switzerland. Almost 500 reactor-years

of successful operational experience have been accumulated.

The Kozloduy NPP in Bulgaria has supplied heat to the town of Kozloduy since 1990. The Kozloduy

NPP originally consisted of four WWER-440 reactors of 408 MW(e) and two WWER-1000 reactors

of 953 MW(e). However, the four smaller reactors had to be shut down as a condition for Bulgaria’s

accession to the European Union. No relevant problems with district heating have been experienced.

The Paks Nuclear Power Plant (Hungary), consisting of four units of the Soviet design WWER-440

type V-230, is supplying heat to the town of Paks. The water pressure in the heat exchanger is kept

higher than the steam pressure to prevent contamination of the hot water system.

The Cernavoda Nuclear Power Plant in Romania has supplied heat to the town of Cernavoda since the

plant began commercial operation in 1996.

The Bohunice Nuclear Power Plant in Slovakia produces electrical energy and low-temperature heat

for heating and industrial purposes. The heat supply from the nuclear power plant is used for the town

of Trnava.

The district heat extraction from the Beznau NPP (Switzerland (2 × 360 MW(e) PWR) has been

operated reliably and successfully since its commissioning in 1983/84. The peak heat load is about 80

MW(th), which is equivalent to about 10 MW(e) of electric power. The district heating system

supplies about 2100 private, industrial and agricultural consumers through 35 km of main piping and

85 km of local distribution pipes.

The most extensive experience with district heat supply from nuclear co-generation plants has been

gained in the Russian Federation. The NPPs of Bilibino, Belojarsky, Balakovo, Kalinin, Kola, Kursk

and Leningrad are supplying heat from steam turbine bleeders through heat exchangers to district

heating grids of towns with typically about 50 000 inhabitants, situated between 3 and 15 km from the

NPP sites. The heat output capacities range from about 50 to 230 MW(th).

Table 3.1 shows the worldwide experience in nuclear district heating.

Table 3.1 Operating nuclear heating plants

Country

Plant type or

name

Location Application Phase

Start of reactor

operation

Net

Power

(MW(e))

Bulgaria Kozloduy 5,6 Kozloduy Electricity/

District heating

Commercial 1989 2 x 953

China NHR-5 Beijing District heating Experimental 1989

1989

Czech Rep. Temelin 1,2 Temelin Electricity/

District heating/

Process heat

Commercial 2002 2 x 930

Hungary PAKS 2,3,4

Paks Electricity/

District heating

Commercial 1984 1 x 441

1 x 433

1 x 444

India Rajasthan

1,2,3,4

Rajasthan Process heat Commercial 1 x 90

1 x 187

2 x 202

Romania HWR

CANDU-6

Cernavoda –

Unit 1

Electricity/

District heating

Commercial 1998 1 x 660

Russia WWER-1000 Novovoronezh Electricity/

District heating/

Process heat

Commercial 1971-73 3 x 385

1 x 950

Russia WWER-1000 Balakovo Electricity/

District heating/

Process heat

Commercial 1986-93

4 x 950

Russia WWER-1000 Kalinin Electricity/

District heating/

Process heat

Commercial 1985-87 2 x 950

Russia WWER-440 Kola Electricity/

District heating/

Process heat

Commercial 1973-84 4 x 411

Russia LWGR Bilibino Electricity/

District heating

Commercial 1974 4 x 11

Russia LWGR St. Petersburg Electricity/

District heating/

Process heat

Commercial 1974-81 4 x 925

Russia LWGR Kursk Electricity/

District heating/

Process heat

Commercial 1977-86 4 x 925

Slovakia Bohunice-3,4 Bohunice/Trnava Electricity/

District heating/

Process heat

Commercial 1987 2 x 408

Switzerland Beznau 1,2 Beznau Electricity/

District heating

Commercial 1985, 1989 1 x 365

1 x 357

3.2.2. Summary of some specific district heating systems of interest

The details of the world’s first district heating plant at Stockholm, Sweden, and the latest district

heating plant at Cernavoda, Romania, are given in Annex 2. Their salient features are presented below,

along with information on the Russian floating reactor system.

3.2.2.1. Swedish district heating [5,6,7]

The Swedish district heating system is well developed. About half of the heating of homes and houses

is done by means of district heating. Two hundred and seventy of the country’s 290 communities have

district heating networks. All cities and towns with more than 10,000 inhabitants have district heating

networks. Very many of the smaller cities and towns have district heating networks as well.

The total Swedish district heating system uses about 60 TWh of energy to produce 48 TWh of heat

and 6 TWh of electrical power, which leads to an overall system efficiency of about 90%. The fuel

that is used is 45% biomass, 15% fossil, 15% electricity, 10% waste, 10% residual heat, and 5%

miscellaneous.

Typically a Swedish district heating network is a hot water system with a hot temperature of 70 to

110

C, depending on the time of the year, and a return temperature 40 to 50

C lower. The distribution

is done by means of pumps at the heat and power plants, but also by means of distributed pumps for

the larger networks.

The following figures on production and economics are based on statistics from 2003-2005.

About 570 towns and villages in the country have district heating networks and the growth potential is

still considered to be high. The total yearly heat delivery is about 50 TWh. The growth rate is

estimated to be about 10 TWh by 2010. In the long run, district heating is judged to represent about

75% of the total Swedish heating need.

To reach the goal of 60 TWh of district heat in 2010 the investment is estimated to be about 500

million euros per year. This will also provide some electricity generation capacity. The domestic

environmental gain is estimated to be a reduction of about 3 Mton of CO

. Because the expansion in

Swedish district heating saves imported electricity from coal fired plants in other countries, the

reduction in CO

release abroad is estimated to be an additional 2 Mton.

The investments in the coming years are divided in the following way:

• Heat and power generation: 300 million euros.

• Distribution network: 150 million euros.

• Distribution heat exchange centrals: 50 million euros.

The total sales income to the district heating companies is about 2000 million euros. The average

income per kWh per year is about 4 cents. The range of income per kWh based on the different

heating companies was from 3 cents up to 7 cents.

The economics for different district heating utilities varies widely and results in large price differences

for end consumers, compared with other heating sources. Prices for heat for end consumers are often

split into a fixed contract, based on demanded power, and a price per kWh.

Contract:

• For an installation of < 500 kW capacity, the customer pays 100 euros per year fixed price;

• For an installation from 500 kW and up to 3000 kW capacity, the customer pays 10 000 euros

per year fixed price; and

• For an installation of >3000 kW capacity, the customer pays 100 000 euros per year fixed

price.

Price per kWh, including taxes and environmental fees:

• Summer: typically 4 to 5 cents per kWh.

• Winter: typically 5 to 6 cents per kWh.

District heating tends to have more modest yearly price increases than other sources for heating.

An economical survey for a typical small apartment building showed the following situation on total

heating cost per year for the whole apartment building for different fuels:

Electricity 24 k euro

Oil 28 k euro

Bio Pellets 12 k euro

Heat Pump 14 k euro

District heating 15 k euro

A major drawback is considered to be the natural monopoly that the district heating system layout

creates. In the Nordic countries the rather free market on electricity is accepted and the contrast to the

district heating, in this respect, is often discussed.

After the Swedish deregulation of the electrical market in 1996 there has been a move from city-

owned district heating towards ownership by large electrical utilities.

A typical return on investment for a district heating utility is 6.5 %, with city-owned systems having

on average higher returns. The companies’ balance sheets show typical turnover figures between

30 million euros to 45 million euros.

3.2.2.2. District heating in Russia [8, 9]

In Russia, consideration has been given to the use of the VBER-300 reactor with 850 MW thermal

power as the basis for land-based and floating two-unit and single-unit nuclear co-generation plants to

provide heat and power supplies for some cities in the European part of Russia, Urals, and the Far

East, such as Arkhangelsk, Okhotsk, Petrozavodsk, and Ussuriisk.

The main parameters of a floating nuclear power plant based on the VBER-300 are the following:

• Maximum electric power output to the power-supply system: 2×280 MW;

• Construction period: 6 years;

• Construction period for hydraulic engineering and coastal installations assigned to the project of

3-4 years;

• Total plant construction period: 7 years.

Typical prices for heat delivered by a city owned utility are as follows:

The land-based option of the nuclear co-generation plant based on the VBER-300 plant has also been

developed:

• Maximum electric power output to power supply system: 2×280 MW;

• Maximum thermal power output to heat supply system: 2×530 MW;

• Electric power in co-generation mode to the power supply system: 2×185 MW.

3.2.2.3. Summary of district heating in Romania [10,11,12]

A total of five nuclear power reactors were initially intended to be built in Romania at the Cernavoda

site on the Danube River. The site currently comprises Unit 1 (which has been in full commercial

operation since 1996) and Unit 2 which has been connected to the grid in 2007. Units 3, 4, and 5 are in

different stages of completion. All reactors are PHWRs of the CANDU-6 type.

The site is about 2 km southeast of the town of Cernavoda (20 514 inhabitants) in the lower Danube

region near the Black Sea. Two large towns are located within a 30 km radius of the site, namely

Medgidia (43 867 inhabitants) and Fetesti (33 197 inhabitants), and many small rural communities and

villages. Around the NPP site, within a radius of 30 km and 100 km, approx. 180,000 and 1,375,000

persons respectively reside.

From early 1980s there were intentions to use the steam extracted from the turbine for district heating,

and a reference study was produced in 1985 [10] with the purpose to provide approximately 1,300

MW of district heating from all five Units of the Cernavoda NPP for distances up to 100 km..

The existing nuclear district heating system provides 60% of the necessary heating for the town of

Cernavoda, as well as necessary heat for the NPP site and site sub-contractor facilities. Studies were

performed [11, 12] and a modernization project has to be implemented to improve the existing district

heating system.

3.2.3. Economics

A comparison of the costs of nuclear heat production with those of competing technologies was

reported by IAEA [2] and the estimates are shown in Table 3.2. The costs are levelized heat generation

cost obtained with a method analogous to one conducted to compute levelized electricity generation

costs. The study assumed the oil cost as US$ 25 per barrel of oil equivalent and the cost of coal as

US$ 50/t. The other key parameters are given in the table. The data show that the assumed values for

the discount rate play an important role. At a 10% discount rate even a large nuclear heating plant

(NHP) is barely competitive with a large coal-fired boiler. These estimates were made in 1992. The

present increasing fossil fuel price and lowering interest rates would make large nuclear heating

systems more competitive. Note, however, that the effects of specific sites may well outweigh the

general trends shown in Table 3.2, depending on the heat transport and distribution networks at

different locations.

Table 3.2. Estimate of the competitiveness of the NHPs

Levelized heat costs

(US) $/kWth

Cost ratio: nuclear vs.

gas-oil boilers

Cost ratio: nuclear vs.

coal boilers

Plant type

Plant

size

(MWth)

Assumed

base

construction

cost

(US) $/kWth

Discount

rate: 5%

Discount

rate: 10%

Discount

rate: 5%

Discount

rate: 10%

Discount

rate: 5%

Discount

rate:10%

Nuclear plants

50 1650 25 36 1.3 1.6 1.8 2.1

100 1100 19 26 1.0 1.1 1.4 1.5

200 825 16 22 0.8 1.0 1.1 1.3

500 605 13 17 0.7 0.7 0.9 1.0

Fossil fuel plants

Gas-oil boiler 100 440 20 23 - - - -

Coal boiler 500 440 14 17 - - - -

Few economic cost data are reported from the existing nuclear district heating plants [13]. Canada’s

experience showed that the nuclear heat cost was significantly lower than heat from natural gas or

other fossil fuels. The Czech Republic’s district heat systems report high construction costs for hot

water pipelines from NPPs to consumers as a reason for higher heat costs. In Cernavoda, Romania,

nuclear heat provided by the NPP covers 60% of the total heat consumption. The heat cost delivered to

the distribution company of the municipality is about 5.5 Euro/MWh (presuming an exchange rate of

3.4 Lei per Euro), and the tariff to the public is 15.1 Euro/MWh, which is about half of the average

cost of heat in Romania. In the Russian Federation, the nuclear heat plants contribute about a third of

the total production of heat in the country. The cost of nuclear heat is reported to be 2-2.5 times

cheaper than that from local heating boilers. In Russia and Ukraine, however, the nuclear heating cost

is subsidized, leading to a low cost to consumers. In Trnava, Slovakia, nuclear heat contributed 60 %

of the total heat supply. It is also reported to be cheaper than fossil-fuel heat. In Switzerland’s Benzau

unit, the heat cost is reported to be around 70 - 95 CHF/ MWh, which is higher than oil firing, which is

around 45 - 60 CHF/ MWh. The improved environmental benefits have made this higher cost

acceptable, however.

3.3. Challenges

Transporting heat is difficult and expensive. The need for a pipeline, thermal insulation, pumping, and

the corresponding investments, heat losses, maintenance, and pumping energy requirements make it

impractical to transport heat beyond distances of a few kilometres, or at most, some tens of kilometres.

There is also a strong size effect to the system cost. Furthermore, the specific cost of transporting heat

increases sharply as the amount of heat to be transported decreases. Compared to heat, the

transmission and distribution of electricity is cheap, even over distances measured in hundreds of

kilometres. Worldwide transport of gas through pipelines up to thousands of kilometres long is, of

course, well-established.

The foremost challenge to district heating systems, whether fossil or nuclear based, is their

competitiveness with small domestic heating units using oil or gas fired mini boilers or electricity,

which are presently meeting consumer demands satisfactorily. These units are not subject to transport

of heat and attendant problems of costs for heat transport equipment, piping insulation, and heat losses

during distribution.

Nuclear plants are capital intensive. The influence of the fixed cost component is predominant in the

final cost of energy and its products. Therefore, base load operation with load factors as high as

achievable is needed for competition with alternate energy sources. This is only possible when the

demand of the heat market to be supplied has base load characteristics, or when the combined

electricity and heat market enables overall base load operation of a co-generation plant. This is

particularly relevant for district heating, where the heat load is substantial and varies with season.

Because heating requirements are not needed throughout the year, the overall district heat plant’s load

factors are typically around 50-60% in cold climates. The co-generation plants are designed to

distribute the electricity and heat loads adequately year-round, but the overall economics are affected.

There is, however, an possibility to improve the situation for a plant using nuclear energy by

increasing the thermal efficiency of the heat transport systems. If this could be done together with a

lowered investment cost it would improve the likelihood that a nuclear-based heating system could

compete economically with a fossil fuel fired system.

A benefit of district heating systems is the reduction of air pollution emissions near urban localities

and the consumer centres, compared to small localized units. In this context, the role of nuclear district

heating will have a higher significance as it does not contribute to any emission.

The elimination of CO

and flue gas emissions is, of course, a key essential driver for the use of

nuclear, rather than fossil, energy. Were nuclear energy also recognized as a Clean Development

Mechanism (CDM) under the Kyoto Protocol, this could lead to further improved economics of

nuclear district heating.

3.4. Solutions

The challenges mentioned above are a mix of socio-political and technical ones. The technical

solutions, discussed below, to meet these challenges are primarily directed towards reactor plant type

and layout, their size and location, and safety aspects.

Plant type and layout

Nuclear heat-producing plants for district heating for space heating and hot tap water can, in principle,

be divided into two different types:

• Dedicated heat-producing reactors, so called single-purpose systems;

• Heat and power reactors, so called dual-purpose systems.

Initial efforts in district heating considered dedicated reactors. However seasonal variation of heat

requirements for district heating led to a wide use of co-generation systems.

Important factors that are limiting the benefits that could be realized by retrofitting district heating to

existing power plants are the outage costs and risks for the necessary shutdown period to carry out the

retrofitting work, and the fact that such plants seldom are optimally sited for the district heating

network.

New nuclear heat-producing plants must, of course, be designed to have availability factors

comparable or preferably higher than today’s plants. The requirements on availability and reliability

are particularly keen for new district heating networks, since there would be no existing heat-

producing capacity that could serve as backup. For existing systems, heat production capacity through,

for instance, oil boilers can serve as the backup capacity during nuclear outages.

Heat storage allows a matching of the heat supply to the heat demand. This has several advantages,

including better utilization of the investments. This is true regarding both the production unit as well

as the district heating network. Today there are many examples of short-term storage, for instance, on

the daily scale. In the future, more long-term storage facilities may be realized. Today’s storage relies

on hot water accumulator tanks. More innovative concepts, such as storage in underground water

layers, may also be possible.

Plant size and location

Nuclear district heating requires that the reactors be installed in the district heating network close to

the consumers. In this way the thermal losses and pipeline costs can be kept low. The proximity to

population centres implies the need for a high degree of safety including the lowering of core damage

frequencies and enhancing mitigation systems in the case of an accident.

The design features to prevent the transfer of radioactivity into the district heating grid network have

proven to be effective. These features include one or more barriers to radioactive cross

contanmination, e.g., in the form of a leak-tight intermediate heat transfer loop at a pressure higher

than that of the steam extracted from the turbine side of the nuclear plant. These loops are

continuously monitored, and isolation devices are provided to separate potentially contaminated areas.

Another key factor is that the heat reactors need to be small compared to modern power producing

reactors, since the heat demand even in big district heating networks seldom is more than 200 MW. A

small size could also facilitate licensing of a location close to a population centre.

In order to be able to compete with fossil fuel fired heat boilers, the installation cost per installed MW

heat for a nuclear-based system must be much lower than today’s power producing plants. Reducing

plant complexity is one option, which would also serve, potentially, to simplify operation,

maintenance, and training.

Small dedicated reactors would have the following advantages:

• Less severe operating conditions, such as lower pressures and temperatures;

• A smaller size, which reduces the demands associated with manufacturing the main

components;

• A high potential for modularization and standardization;

• Improved ease of operation, without excessive demand on qualified personnel;

• Design transparency; the safety features can be more simple and easier to understand.

The less severe operating conditions and simpler safety systems facilitate a design with a high degree

of safety that relies to a large extent on passive safety systems. Such systems are often simpler with a

low degree of complexity.

Lower pressures and temperatures also lower the need for sophisticated materials and, therefore, may

reduce material and manufacturing costs. A clear strategy for nuclear district heating reactors must be

to use industrial grade components to as large an extent as possible, instead of the customized nuclear

grade components used in power producing plants, assuming that this strategy would be endorsed by

the nuclear safety authorities.

A small plant has several advantages for the manufacturing industry compared to a large power plant.

Mechanical components are smaller and lighter than those of a conventional nuclear power plant. This

makes the manufacturing of the main components of the plant possible even in countries that do not

have the workshops and experience that is normally needed for making heavy nuclear-grade

components for large nuclear power plants.

In order to keep down the cost, a high degree of standardization is desirable. This may further reduce

maintenance costs, as well. A relatively large proportion of both process components and control

equipment could be provided as factory-assembled packages. This would keep the on-site installation

costs lower.

Despite the advantages of small, single-purpose plants, it must also be said that the cost of a plant

tends to increase rapidly with decreasing capacity, and the economic competitiveness of such a reactor

becomes questionable. Standardization of design and construction may help overcome this

disadvantage, even if individual plants are not ideally sized for the specific district heating application

in mind.

Conclusions

The low prices of fossil fuels have stunted the development of small, single-purpose nuclear district

heating plants. This situation is changing. Furthermore, as environmental concerns mount over the use

of fossil fuels, the prospects for nuclear-based district heating are improving. Nevertheless, though

many concepts of such small-scale heat-producing reactors have been presented during the years, very

few have been built.

The main features of such a plant would be:

• A small capacity (for example <200MW);

• Low temperatures and pressures;

• A simple, standardized design;

• Passive safety systems.

REFERENCES FOR CHAPTER 3

[1] OECD/NUCLEAR ENERGY AGENCY, Non-electricity Products of Nuclear Energy, OECD-

NEA Report (2004).

[2] INTERNATIONAL ATOMIC ENERGY AGENCY, Market Potential for Non-electric

Application of Nuclear Energy, TRS No. 410, Vienna (2002).

[3] INTERNATIONAL ATOMIC ENERGY AGENCY, Improving Economics and Safety of

Water cooled Reactors: Proven Means and New Approaches, IAEA-TECDOC-1290, Vienna

(2002).

[4] INTERNATIONAL ATOMIC ENERGY AGENCY, Introduction of Nuclear Desalination-A

Guidebook, TRS No. 400, Vienna (2000).

[5] SANDSTRÖM, S. “Operating Experiences at the Ågesta Nuclear Power Station” AB

Atomenergi (1966). AE-246.

[6] INTERNATIONAL ATOMIC ENERGY AGENCY, Status of Advanced Light Water Cooled

Reactor Designs 1996, ISSN 1011B4289, IAEA-TECDOC-968, Vienna (1997).

[7] BENTO, J.-P. and MANKAMO, T., Safety Evaluation of the Secure Nuclear District Heating

Plant, Nuclear Technology Vol. 38. (1978).

[8] PANOV, Yu., POLUNICHEV, V, ZVEREV, K. Use of Reactor Plants of Enhanced Safety for

Seawater Desalination, Industrial and District Heating, IAEA-TECDOC-923, Vienna (1997).

[9] PANOV, Yu., POLUNICHEV, V., Nuclear Head Applications: Design Aspects and Operating

Experience, in IAEA-TECDOC-1056, IAEA, Vienna, pp. 249-262 (1998).

[10] INSTITUTE FOR POWER STUDIES AND DESIGN – ISPE, “The full utilization of the

available heat from Cernavoda NPP for large area district heating, aimed to reduce the country’s

hydrocarbons consumption”, Institute for Power Studies and Design – ISPE, Bucharest

(December 1985).

[11] INSTITUTE FOR POWER STUDIES AND DESIGN – ISPE, “Cernavoda District Heating

Modernization - Pre-feasibility Study”, ISPE, Bucharest (October 2004).

[12] INSTITUTE FOR POWER STUDIES AND DESIGN – ISPE, “Cernavoda District Heating

Modernization - Feasibility Study”, ISPE, Bucharest (July 2005).

[13] INTERNATIONAL ATOMIC ENERGY AGENCY, Nuclear Heat Applications: Design

Aspects and Operating Experience, IAEA-TECDOC-1056, Vienna (1998).

CHAPTER 4

INDUSTRIAL PROCESS STEAM

4.1. Opportunities

Within the industrial sector, process heat is used for a large variety of applications with different heat

requirements and with temperature ranges covering a wide spectrum. Whereas in energy-intensive

industries the energy input represents a considerable fraction of the final product cost, in most other

processes it contributes only a few percent. Nevertheless, the supply of energy has an essential

character: all industrial users need the assurance of energy supply with a degree of reliability and

availability approaching 100%. In contrast to district heating, the load factors desired by industrial

users do not depend on climatic conditions. The demands of large industrial users usually have base

load characteristics.

The characteristics of the market for process heat are quite different from district heating, though there

are some common features, particularly regarding the need for minimal heat transport distances.

Industrial process heat users do not have to be located within highly populated areas. Many of the

process heat users, in particular the large ones, can be, and usually are, located outside urban areas,

often at considerable distances. This makes joint siting of nuclear reactors and industrial users of

process heat not only viable, but also desirable in order to drastically reduce the heat transport costs –

provided that the co-siting does not adversely affect the safety case for the nuclear installation.

Process heat involves the supply of heat required for industrial processes from one or more centralized

heat generation sites through a steam transportation network. Within the industrial sector, at

temperatures higher than those needed for district heating and seawater desalination, process heat is

used for a variety of applications as shown in Figure 4.1 [1].

FIG. 4.1. Required temperatures for industrial processes (Figure taken from [1]).

As discussed in earlier chapters, water-cooled nuclear reactors have been used in low-temperature

applications including desalination, district heating and process heat. There is a potential for their use

at medium temperature ranges such as are used in the fertilizer, pulp and paper, and oil and petroleum

industries, etc. However, applications shown in Fig 4.1 that require heat above about 550 ºC (the

temperature achievable by super-critical water cooled reactors) would require other reactor types and

shall not be discussed in this report.

In a similar way as for district heat, the 2003 IAEA report [2] took the approach that the size of the

process heat market can be estimated by examining the total use of centralized process heat in 1996,

which was 150.1 Mtoe according to the IEA world energy database and required a heat production

capacity of 240 000 MWth assuming an average load factor of 90%.

Process heating has the following technical requirements:

• Owing to higher thermal losses over long transmission networks, the heat source must be

relatively close to the customer;

• The annual load factor must be much higher than that in district heating, probably 70-90%,

since process heat demand does not depend on climatic conditions;

• To secure a reliable supply of heat, a backup capacity is required.

Several co-generation nuclear power plants have supplied process heat to industrial users [3]. The

largest projects implemented have been in Canada (Bruce for heavy water production and other

industrial/agricultural users) and in Kazakhstan (Aktau for desalination). Other power reactors, which

currently produce only electricity, could be converted to co-generation. Nevertheless, installing a new

nuclear co-generation plant close to existing and interested industrial users has better prospects. Even

better would be a joint project whereby both the nuclear co-generation plant and the industrial

installation requiring process heat are planned, designed, built, and operated together as an integrated

complex.

For reactors in the small to medium size range, and in particular for small and very small reactors, the

share of process heat generation may be larger, and heat could even be the predominant product. This

would affect the plant optimization criteria, and could present much more attractive conditions to the

potential process heat user. Consequently, the prospects of SMRs as co-generation plants supplying

electricity and process heat are considerably better than those of large reactors.

Heat-only reactors have not yet been applied on an industrial/commercial scale for the supply of

process heat, though several designs have been developed.

4.2. Market context

4.2.1. Past experience

As in the case of district heat, all existing reactor types are potentially applicable to process heat

needs, depending on the required temperature of the processes. There have been some experiences in

providing process heat for industrial purposes with nuclear energy in Canada, Germany, Norway,

Switzerland, and India. In Canada, CANDU reactors supplied steam for industries such as food

processing and industrial alcohol production until their closure in 1998. In Germany, the Stade PWR

supplied steam for a salt refinery located 1.5 km from the plant from December 1983 until its

shutdown in November 2003. In Norway, the Halden Reactor has supplied steam to a nearby factory

for many years. In Switzerland, since 1979 the Gösgen PWR has been delivering process steam to a

cardboard factory located 2 km from the plant. In India, the RAPS-II PHWR at Kota supplies heat to

the nearby heavy-water plant. Tables 4.1 and 4.2 present the salient features of operating nuclear

process heat plants and projects [4]. A brief summary of these applications is presented in the

following paragraphs.

Table 4.1. Operating nuclear process heat production plants

Country

Plant

name

Location

Application

Start of operation

reactors / heat

Phase

Power

(MW

(e))

Heat

delivery

(MW(t))

Temperature

(°C) at

interface

(feed/return)

Remarks

Canada Bruce-A

Bruce Process heat 1977-87 1981 Commercial 4 x 848

5350

O production

and six industrial

heat customers

Germany Stade Stade Electricity/

process heat

1983 Commercial 640 30 190/100 Salt refinery

Switzerland Goesgen Goesgen Electricity/

process heat

1979 1979 Commercial 970 45 220/100 Cardboard factory

India RAPS Kota Electricity/

process heat

1975/1980 Commercial 160 85 250 D

Unit 2 was taken out of service in 1995, units 1, 3 and 4 were taken out of service in 1998.

Table 4.2. Nuclear process heat production projects

Country

Plant

name

Location

Application

Start of operation

reactors / heat

Phase

Heat

delivery

(MW(t))

Temperature

(°C) at

interface

(feed/return)

Remarks

China HTR-10 Beijing Electricity/

process heat

Criticality 1999 Construction

completed

10 700-950/250 Experiments for HTR

technology development.

Japan HTTR Oarai Process heat Criticality 1998 Construction

completed

30 950/395 Experiments for HTR

technology development,

potentially including

hydrogen production.

Russia VGM Process heat Design

In Canada, steam from the Bruce Nuclear Power Development (BNPD) was supplied to heavy water

production plants and to an adjacent industrial park at the Bruce Energy Centre (BEC). BNPD is the

world’s largest nuclear steam and electricity generating complex. It includes eight CANDU nuclear

reactors with a total output of over 7200 MW(e), the world’s largest heavy water plant (HWP), and the

Bruce Bulk Steam System (BBSS). The BBSS, capable of producing 5350 MW(th) of medium-

pressure process heating steam, was built to supply the HWP from the four 848 MW(e) units of the

Bruce A complex. Each of the four 2400 MW(th) reactors can supply high-pressure steam to a bank of

6 heat exchangers (24 in total), which produce medium-pressure steam for the HWP and site services.

The normal capacity is approximately 1680 kg/s of medium-pressure steam from the reactors with 315

kg/s emergency backup available from oil fired boilers. In 1995, Unit 2 of the Bruce A NPP was laid

up; the HWP and units 1, 3 and 4 of Bruce A were laid up in spring 1998. However, unit 4 was

restarted in 2003 and unit 3 in 2004. In 2006 agreement was also reached on a four-year programme to

also restart units 1 and 2.

FIG. 4.2. Bruce nuclear power development (8 x 850 MW(e) CANDU units, heavy water production,

greenhouse complex using nuclear steam). (Credit: Bruce Power.)

The six private industries currently established at the park are:

(1) a plastic film manufacturer;

(2) a 30 000 m

(7.5 acres) greenhouse;

(3) a 12 million liter/year ethanol plant;

(4) a 200 000 ton/year alfalfa dehydration, cubing, and pelletising plant;

(5) an apple juice concentration plant; and

(6) an agricultural research facility.

In Germany, the Stade NPP PWR (1892 MW(th), 640 MW(e)) has supplied steam for a salt refinery,

which is located at a distance of 1.5 km, since December 1983. The salt refinery requires 45 t/h

process steam at 190°C and 1.05 MPa. This represents a thermal power of about 30 MW and is 1.6%

of the thermal output of the NPP. Since 1983, the steam supply by Stade has had high availability, and

the operating experience with process steam extraction is good.

The Gösgen-Däniken nuclear power station (KKG) with a pressurized water reactor situated on the

River Aare between Olten and Aarau in Switzerland and built under the overall management of

Kraftwerk Union AG (KWU) is the first of its kind in the world to supply process stream. Its steam

user is the nearby cardboard mill, Kartonfabrik Niedergösgen. The heavy-oil-fired boilers installed at

that plant, which with their emissions were once the source of considerable atmospheric pollution,

now have only standby status.

Further design details of the Gösgen process heat plant are given in Annex 4.

In India, the RAPS II reactor at Kota has been supplying 110 t/h of steam at 250°C and 4 MPa since

1980. The steam is reduced to 0.6 MPa and used in the nearby heavy-water production plant.

4.2.2. Near-term potential

The Russian Federal Agency for Atomic Energy (ROSATOM) has started construction of a floating

barge-mounted heat and power co-generation nuclear plant based the ship propulsion PWR-type

reactor KLT-40C in Severodvinsk. It is planned to put the plant into operation in 2010. The floating

NPP can produce up to 70 MW for electric power and about 174 MW of heat for district/process

heating. The lifetime of the plant is 40 years; it is designed for a continuous operation period before

dockyard refurbishment of 12 years.

Demonstration of this nuclear technology is intended to allow its larger-scale application inside the

country and abroad for electricity and heat production.

Another PWR, the SMART integral type reactor, is under development in the Republic of Korea for

desalination. It could however also produce industrial process heat.

Application in oil extraction

Atomic Energy Canada Limited (AECL) has studied the feasibility of using CANDU energy in

applications beyond traditional electricity generation, such as open pit mining and oil sand extraction.

Alberta’s oil sand deposits are the second largest oil reserves in the world, and have emerged as the

fastest growing, soon to be dominant, source of crude oil in Canada. The oil sand industry currently

produces more than a third of the nation’s petroleum needs, and has the potential to account for more

than sixty percent of Western Canadian crude production by 2010.

Currently, the majority of oil sand production is through open-pit mining, which is suitable for

bitumen extraction when the oil sand deposits are close to the surface. The ore, a mixture of bitumen

and sand, is removed from the surface by truck and shovel operation. The ore is then mixed with hot

water to form a slurry that eventually undergoes a separation process to remove bitumen from the

sand.

The thermal energy required for the open-pit mining process is in the form of hot water at a relatively

low temperature (around 70°C), and the rest is dry process steam at around 1.0 to 2.0 MPa. The oil

extraction facilities require electrical power as well.

To increase production capacity, the industry is looking for new technology to extract bitumen from

deep deposits. Among them, Steam-Assisted Gravity Drainage (SAGD), which uses steam to remove

bitumen from underground reservoirs, appears to be the most promising approach. Recently, the in-

situ recovery process has been put into commercial operation by major oil companies.

Overall, for both extraction methodologies, a significant amount of energy is required to extract

bitumen and upgrade it to synthetic crude oil as the feedstock for oil refineries. Currently, the industry

uses natural gas as the prime energy source for bitumen extraction and upgrading. As oil sand

production continues to expand, the energy required for production becomes a great challenge with

regard to economic sustainability, environmental impact and security of supply. With this background,

the opportunity for nuclear reactors to provide an economical, reliable and virtually zero-emission

source of energy for the oil sands becomes a realistic option.

Further details are given in Annex 3.

4.2.3. Economics

The 2003 IAEA report [2] discussed the industrial process heat market size and features. The

industries that are main consumers of heat are:

- food,

- paper,

- chemicals and fertilizers,

- petroleum and coal processing, and

- primary metal industries.

The breakdown of the total industrial heat varies from country to country, but the chemical and

petroleum industries are the major consumers worldwide. These would be key target clients for

possible applications of nuclear energy.

With respect to economic competitiveness, many of the features described for electricity generated by

nuclear energy for desalination and district heating are valid for process heat applications. There are

several important considerations specific for process heat applications, which include:

- The ability to locate the heat source close to the demand,

- The relatively small-scale demand,

- The need for high reliability.

The economics of nuclear energy for process heat applications will likely be improved by the

development of small, low-cost reactors. Current development trends in many countries have already

begun to move in this direction.

The co-generation plants for process heat based on fossil fuels or water-cooled reactors derive much of

their revenue from electricity, but add the operational flexibility to adapt to process heat markets.

Specific costs for oil extraction from Canadian oil-sands

In 2003 AECL commissioned an independent study by CERI (Canadian Energy Research Institute) to

compare the economics of Advanced CANDU Reactor (ACR)-supplied energy with natural gas. This

study provided an evaluation using ACR design data, the assumptions on configurations and

economics, and compared equivalent amounts of energy supplied from the nuclear and natural gas

options to ensure a proper comparison. The study identified comparable ACR and natural gas-supplied

configurations, each delivering steam and electricity. The electricity output was set at 150 MWe

(gross) to meet the facility’s demand, and the remaining thermal power of the ACR was delivered as

steam to the Steam-Assisted Gravity Drainage (SAGD) plant. A common economic model was also

developed, using parameters such as natural gas and electricity costs based on 2003 market value,

without attempting to extrapolate or forecast future prices. The natural gas price used was Cnd

$4.25/GJ and the electricity price was Cnd $50/MWh. Based on these numbers, the results show

nuclear steam to be 10% cheaper than that generated through natural gas.

The study examined energy price sensitivity to changes in key parameters. The nuclear case is more

sensitive to capital cost changes, as might be expected. A 25% increase in capital cost would increase

steam cost by 20%. The gas-fired option is extremely sensitive to fuel prices. A 25% increase in the

price of natural gas would increase steam cost by nearly 25%. With the current gas price more than

50% higher than in 2003, the economic advantage of nuclear over natural gas becomes significant.

The study also examined the impact of CO

emissions on cost. The reference basis for CO

costs or

credits was $15/tonne. This could add an additional 18% to the cost of natural gas-supplied steam.

All indications are that the nuclear option has a significant advantage in cost over the competition. The

nuclear option also provides for cost predictability and stability, which would reduce the risks for a

potential oil sand operator.

4.3. Challenges

The market for industrial heat is highly competitive. Heat is produced predominantly from fossil fuels,

with which nuclear energy will have to compete. Most of the industries using fossil fuel as a heat

source have abundant waste heat available and it is being economically used in various process

streams.

Similar to nuclear district heating, the close siting of a nuclear plant to the customer is preferable, as

the heat transportation costs grow significantly with distance. This will require specific safety features

appropriate to the location and the application. Until now few technical problems in coupling nuclear

reactors to various applications have been identified, though some safety-related issues of coupled

systems may need more study.

The nuclear process heat supply has to be reliable. As an example, the average adequate steam supply

availabilities for chemical processing, oil refineries and primary metals are respectively 98%, 92% and

near 100%. Such high levels can be ensured only by the combination of a highly reliable heat source

and the availability of reserve capacity.

The supply of industrial heat is more uniform throughout the year than that of district heat, mainly

because of the absence of seasonal variation. Accordingly, the average load factors of industrial

boilers are relatively high, between 70 to 90%. Nuclear reactors, which are typically run in base load

operation, will be quite useful in this context.

Although nuclear industrial process heat applications have significant potential, it has not been

realized to a large extent. In fact, presently only the Goesgen reactor in Switzerland and RAPS–2 in

India continue to provide industrial process heat while other process heat systems have been

discontinued after successful use (see Table 1.2). Among the reasons cited for closure of these units,

one is availability of cheaper alternate energy sources, including waste heat near the industrial

complexes. The nuclear slow down in many industrialized countries could be another reason.

Studies are being carried out in Canada for oil extraction from its vast oil sand resources. These

studies consider using present day and advanced water-cooled reactors as a heat source. Currently

natural gas is used for this application. Although these studies have been motivated by a need for an

environmentally sound energy option, the ultimate challenge in the utilization of nuclear steam for this

application is the economics.

4.4. Solutions

4.4.1. Oil extraction from Canadian oil sands

Application to open-pit mining

When a CANDU plant is adapted to supply thermal power to open-pit mining processes, the low

temperature and pressure requirements allow extraction steam from the turbine to be used as the heat

source. This boosts the overall system efficiency. Steam extracted from the low-pressure turbine at

low pressure is used to heat water in steam-to-water heat exchangers. The hot water is supplied to the

bitumen extraction facility; most of the water is recovered after the process, treated and sent back as

the feedwater to the hot water heaters. The condensate from these hot water heaters returns to the

turbine’s feedwater system. The thermal power of the water counts for about 80% of total thermal

power demanded by the open-pit processes.

There are two steam heaters operating at different pressures. The higher pressure one uses main steam

directly from the steam generators and the lower pressure one uses extraction steam from the high-

pressure turbine as a heating source to generate process steam at 2.0 MPa and 1.0 MPa respectively.

The process steam is piped to the bitumen extraction process, and mostly used in mixture heat

exchangers without condensate return. Therefore, feedwater to these steam heaters is mainly from the

make-up water. The condensate from these steam heaters returns to the turbine’s feedwater heating

system. The thermal power of the process steam represents about 20% of total thermal power

requirement. Therefore, the amount of the steam used in these steam heaters is not as significant as the

low-pressure turbine extraction steam used in the hot water heaters.

In contrast to condensing steam turbines that are used in conventional nuclear power plants, the steam

turbines used in this configuration are of the automatic extraction type. Steam is extracted from high-

pressure and low-pressure turbines as the heating steam. The appropriate means have to be provided to

control the amount and the pressure of steam extracted. The turbine design allows the thermal and

electrical output from the plant to vary within a certain range if required. This is a proven technology

in fossil-fuelled co-generation power plants and has been used for decades.

A system simulation has been performed for the year-round weather conditions for the production of

330,000 bbl/day of bitumen, which is a manageable size of an open-pit mining project. For the average

weather condition (in April), the thermal power demand is 1440 MWt, and the electricity demand is

300 MWe (including the oil facility and nuclear plant demands). A CANDU-6 plant is able to provide

the required thermal power for this condition, while generating 367 MWe (gross) electricity. In

summer, the thermal demand decreases to 1220 MWt, and consequently the electrical output increases

to 420 MWe (gross). In the coldest month (January), the total thermal power demand from the oil sand

facility is as high as 1670 MWt, and the CANDU-6 plant generates 316 MWe (gross) electricity while

producing enough hot water and steam to meet the thermal requirements of the bitumen production.

During a year, the nuclear plant generates electricity within a range from 316 MWe to 420 MWe,

while being able to meet the entire thermal power requirement. This offers a limited capability to

deliver electricity to the grid. The simulation results are shown in Table 4.3.

Table 4.3. Simulation results: CANDU-6 for open-pit mining application

Month Jan Feb Mar Apr May Jun Jul

Electricity (gross) MWe 316 331 348 367 385 403 420

Thermal Power MWt 1670 1590 1520 1440 1370 1300 1220

Other technical aspects for adapting a CANDU reactor for open-pit mining processes are similar to

those for the Steam-Assisted Gravity Drainage process discussed in the next subsection, and there are

no insoluble issues identified.

An economic analysis for this configuration is currently in progress.

Application to advanced mining technology

As described earlier, Steam-Assisted Gravity Drainage (SAGD), which uses steam to remove bitumen

from underground reservoirs, is an advanced process being used to exploit deep deposits of oil sands.

A typical SAGD application involves twin horizontal wells drilled in parallel, with one a few meters

above the other, as shown in Fig 4.3. The upper well is called the injection well and the lower one the

production well. Medium pressure steam is injected into the underground deposit area through the

injection well to heat the reservoir of bitumen-sand mixture by conduction. The heating reduces the

viscosity of the bitumen, increases its mobility, and establishes pressure communication between the

two wells along their length, so that a flow of fluids (a mixture of bitumen and condensed water) can

occur and be collected through the production well. The production liquid is transported to a central

facility, where the bitumen is separated and the condensate is collected, treated, and sent back to the

boilers.

FIG. 4.3. Steam assisted gravity drainage process (reprinted with the permission of AECL).

Cap Rock (shale & glacial t ill) 250m t hic

Steam

Ch am b er s

Unrecovered

Heavy Oi l

6mo

2yr

5yr

8yr

10yr

~1 kilometer

~200m

The required steam injection pressure depends on the circumstances of the oil field and the life cycle

of the well, and varies from 2 to 6 MPa. At the initial stages of production (two to three months), each

well requires steam at higher pressure than that required during normal operation. Each barrel of

bitumen requires 2–3 barrels of steam (steam volume is corrected to 4°C and 1 bar). Generally, about

18% of the energy content of the oil produced is used to provide heat for the extraction process; a

further 5% is used in generating hydrogen to upgrade the bitumen to synthetic crude oil.

In addition to steam demand, SAGD production facilities are also significant consumers of electricity.

Adaptation of ACR-1000 for Steam Assisted Gravity Drainage

The primary product of a water-cooled nuclear power plant is steam from the steam generators.

Depending on the requirements of specific projects, the plant can be adapted to provide steam only, or

a mixture of steam and electricity for various steam/electricity ratios. With the steam-only option, the

steam generated from a plant is totally dedicated to supply steam to oil sand processes, and no

electricity is generated. Hence, the turbine island is totally eliminated from the plant, and replaced by

the facilities dedicated to steam and feedwater supplies. The steam/electricity option splits main steam

from the steam generators into two streams: one is dedicated to supply steam to the oil sand facility

and the other is channeled to generate electricity. As a result, the turbine capacity becomes smaller

than that of a standard plant.

As an example, the ACR-1000 design is an evolutionary development of CANDU technology. The net

electrical output from a standard ACR-1000 will be approximately 1000 MWe. The main steam

pressure is 6.5 MPa. The license requirements for an ACR SAGD project were examined and found to

pose no major issues. Since the Bruce A nuclear plant in Ontario has supplied nuclear-generated steam

to various facilities outside the exclusion area, no major impediments to getting regulatory approval

are foreseen.

For the steam-only option, there will be no on-site source of station service power for the nuclear unit.

Therefore, a large combustion turbine generator or other local generation source will be required to

back-up offsite power to satisfy power supply reliability requirements.

Water sources in the northern Alberta oil sand areas are scarce. It would be necessary for any

individual project to minimize its water usage to meet overall regional water use planning guidelines.

The study has looked into the use of air-cooled heat exchangers to take the heat load, which is

normally removed by once-through water in the traditional CANDU plants. This was found to be

feasible for up to 350 MWe electricity generation capacity. The possibility of using more conventional

cooling towers was also examined and found to be feasible.

The remote location and severe weather conditions of oil sand sites raise concerns about the

constructability of a large plant. The ACR design is highly modularized, and the use of prefabricated

modules will be maximized. This approach minimizes the on-site construction activities, enabling

schedule compression, and reduces the size of the on-site labour force. The module sizes and weights

have been selected for suitability for road transportation to northern Alberta. No major construction

issues are predicted.

Overall, the studies indicate that construction and operation of an ACR to meet the energy demand for

SAGD projects are technically feasible.

4.4.2. Massachusetts Institute of Technology (MIT) study [5]

The following summarizes the study:

Introduction

The two general classes of oil sand recovery are mining and in-situ methods. In mining, the oil sand

ore is recovered by electric or hydraulic shovels and transported by heavy trucks before the bitumen

can be extracted. For in-situ methods, most of the bitumen is separated from the oil sands in the

deposit by injecting steam into the ground to separate the bitumen from sand. The bitumen is then

pumped to the surface for further processing.

A 2005 MIT study analyzed the feasibility of integrating a nuclear power plant with Steam Assisted

Gravity Drainage (SAGD). Natural gas-fired plants provide the energy for projects today, but concerns

are heightening within the industry over increased carbon dioxide emissions, volatile natural gas

prices, and depletion of natural gas reserves. Nuclear power is an emission-free alternative to natural

gas, but the key to implementation hinges on whether nuclear systems can compete economically with

natural gas-fired plants in the oil sand industry. Successful integration of emission-free nuclear

technology with oil sand operation will remove the dependence of the price of oil from oil sands on

the volatile and high price of natural gas and also address the problem of CO

emissions.

Energy requirements

Extraction facilities can be divided into three categories: those that only require process heat, those

that require process heat and electricity, and those that require process heat, electricity and hydrogen

to upgrade the bitumen to syncrude on site. In order to compare the different scenarios, a processing

plant capable of producing 100 000 barrels of bitumen per day was assumed as a reference design.

100 000 barrels of bitumen can be upgraded to approximately 87 000 barrels of synthetic crude. The

thermal requirements for each scenario were calculated and compared to the available output of

several reactor systems.

The first scenario requires only process heat to be produced on site. Electricity is assumed to be taken

from the grid. The bitumen after dilution is pumped to a processing plant. The thermal energy

requirements for this scenario range from 820 MWth to 1264 MWth.

The second scenario requires electricity in addition to process heat. The energy requirement for this

scenario includes 1200 MWth heat and 250 MWe.

The third scenario is a self-contained facility that produces its own electricity and process heat and

refines the product on-site from bitumen to synthetic crude. This scenario includes the production of

hydrogen using high-temperature electrolysis for refining. The energy requirement for this scenario

includes 1300 MWth and 740 MWe.

Nuclear reactor design options

Eleven different reactor systems were considered by MIT for this application; three were selected for

the mission of providing the energy needs required. These include the Canadian ACR-700, the

Westinghouse AP-600 and the South African 400 MWth PBMR. An evaluation of design-specific

characteristics that benefit and impede the oil sand extraction process was used to distinguish reactors.

Economics

The study showed that nuclear energy would be feasible, practical and economical for use at an oil

sand facility. Nuclear energy is two to three times cheaper than natural gas for each of the three

scenarios analyzed. Also, by using nuclear energy instead of natural gas, a plant producing 100,000

barrels of bitumen per day would prevent up to 100 mega tonnes of CO

per year from being released

into the atmosphere.

Nuclear obstacles

There are several obstacles to implementing nuclear power in oil sand operations. Public perception

could offer resistance to the project, but a well-planned education effort could address the issue.

Owing to unfamiliarity with nuclear plants in the oil sand industry, it is expected that a qualified

nuclear utility will be needed to operate the nuclear plant and provide heat and electricity as merchant

products for the oil sand extraction and refining company.

4.4.3. Long-term possibilities

The Generation IV International Forum (GIF), an international group of ten countries and Euratom is

exploring the development of six systems that could be deployed by 2030 or earlier. Their capabilities

to produce non-electricity products are shown in Table 4.4.

Table 4.4. Generation IV reactor concepts

Neutron

spectrum

Coolant

Temperature

(°C)

Fuel

cycle

Size(s)

(MWe)

Gas-cooled Fast

Reactors

(GFR)

Fast Helium 850

closed,

on site

288

Lead-cooled

Fast Reactors

(LFR)

Fast Pb-Bi 550-800

closed,

regional

50-150

300-400

1200

Molten Salt

Reactors (MSR)

Epithermal

Fluoride

salts

700-800 closed 1000

Sodium-cooled

Fast Reactors

(SFR)

Fast Sodium 550 closed

150-500

500-1500

Supercritical

Water cooled

Reactors

(SCWR)

Thermal or

fast

Water 550

open

(thermal)

closed

(fast)

1500

Very High

Temperature

Gas Reactors

(VHTR)

Thermal Helium 1000 open 250

Of these concepts, the one water-cooled reactor concept is the supercritical water cooled reactor

(SCWR).

The SCWR system features two fuel cycle options: an open cycle with a thermal neutron spectrum

reactor and a closed cycle with a fast-neutron spectrum reactor and full actinide recycle. In either

option, the reference plant has a 1700 MWe power level and a reactor outlet temperature of 550°C.

This is a very high-pressure water-cooled reactor that operates above the thermodynamic critical point

of water to give a thermal efficiency about one third higher than today’s light water reactors from

which the design evolves. The supercritical water directly drives the turbine, without any secondary

steam system. It is primarily envisioned for missions in electricity production, with an option for

actinide management. Given its R&D needs in materials compatibility and reactor control, the SCWR

system is estimated to be deployable by 2025.

The SCWR could provide process heat at temperatures up to about 550 ºC.

REFERENCES FOR CHAPTER 4

[1] OECD/NUCLEAR ENERGY AGENCY, Non-electricity Products of Nuclear Energy, OECD-

NEA Report (2004).

[2] INTERNATIONAL ATOMIC ENERGY AGENCY, Market Potential of Non-electric

Application of Nuclear Energy, IAEA TRS No. 410, Vienna (2003).

[3] INTERNATIONAL ATOMIC ENERGY AGENCY, Status of Non-electric Nuclear Heat

Application; Technology and Safety, IAEA-TECDOC-1184, Vienna (2000).

[4] INTERNATIONAL ATOMIC ENERGY AGENCY, Introduction of Nuclear desalination- A

Guidebook, IAEA, TRS No 400, Vienna (2000).

[5] MASSACHUSETTS INSTITUTE OF TECHNOLOGY, Nuclear Technology and Canadian Oil

Sands, MIT-NES-DES-005 (2005).

CHAPTER 5

NUCLEAR ELECTRICITY FOR TRANSPORTATION:

HYBRID-ELECTRIC VEHICLES

5.1. Opportunities

The reduction of gasoline consumption by using hybrid gasoline and electric drive engines in

automobiles and light utility vehicles (four-wheel vehicles that include minibuses, delivery vans,

pickup trucks, and SUVs (sport utility vehicles)) may be an idea whose time has come. Electric-drive

engines have the potential to significantly reduce both the cost of vehicle fuel and emissions of

greenhouse gases in the transportation sector, and can reduce the ever-growing pressure for the

countries with oil reserves to find and distribute more oil to both developed and developing countries.

Furthermore, the technologies for some of the alternative routes, particularly the use of hybrid-electric

vehicles, is currently available with minimal changes to the normal transportation infrastructure. The

plug-in feature, when used, allows charging of the vehicle batteries from utility electric power sources,

and it is this application of nuclear electricity that could have an impact on greenhouse gas emissions

and dependence by the transportation sector on petroleum. The United States and Japan were chosen

for detailed studies of the benefits and impacts of substituting electricity for petroleum fuels by using

plug-in hybrid vehicles.

Consideration was given to other transportation systems, primarily railroads. In Japan, less than 5% of

the transportation energy on an oil equivalent basis is used for rail transportation, of which virtually all

already uses electricity. In the United States, the distances are so great between most major cities that

the capital cost of electrical transmission structures militate against its use except in a few locations in

the northeastern United States. No consideration was given to air transportation because the weight of

the electrical motors and batteries would be prohibitive.

In this chapter, the opportunities to use nuclear power plants, particularly water-cooled reactors , are

investigated. The situations in the United States and Japan are developed in detail, and the lessons

learned are extended to the situation in Europe, and especially China and India where the use of

automobiles and light utility vehicles is currently small, but growing rapidly.

Analyses of the current opportunities will be based on simplified models that deal with quantitative

information available from reliable government sources: the U.S. Department of Energy (DOE)

Energy Information Administration (EIA) in the United States and the Ministry of Land

Transportation and Infrastructure (MLIT) in Japan. Average performance data (20 miles per gallon of

gasoline—mpg) will be used to illustrate the overall behaviour of all the vehicles in the United States

with full realization that smaller, lighter vehicles will perform better, and larger, heavier vehicles will

not perform as well.

The models used in the analysis of the situation in the United States are based on three recent

publications [1, 2, 3]. Data from DOE-EIA are used to define an average gasoline-fueled light vehicle

as a reference vehicle against which the various hybrids and hydrogen-fueled vehicle alternatives can

be compared. Analyses of fuel quantities, fuel costs, and greenhouse gas emissions will be used for

comparisons.

The models used in the analysis of the situation in Japan are also based on recent publications [4, 5, 6].

Data from the MLIT are used to define an average behaviour of target motor vehicles (personal-use

passenger vehicles, called “registered” vehicles and “light” vehicles). The methodology used for the

analysis is similar to the one used for the analysis for the United States [2].

5.1.1. Opportunities in the United States

5.1.1.1. Hybrid vehicles

The hybrid-electric vehicle is not a new concept. Hybrids were first conceived and vehicles

constructed about 100 years ago. Even though it was demonstrated to be a viable concept technically,

the hybrid vehicle received relatively little attention until the late 1960s when it was considered by

some to be a possible way of meeting the newly established emission reduction requirements for

automobiles. However, the real stimulus for pursuing hybrids with an organized effort and significant

funding came as a result of the OPEC petroleum embargo and resulting energy crisis of 1973–74. The

U.S. Congress passed Public Law 94-413, the Electric and Hybrid Vehicle Research, Development,

and Demonstration Act of 1976, which directed the newly established Department of Energy (DOE) to

pursue, among other activities, the technologies associated with electric and hybrid-electric vehicles.

While these activities were underway, the energy crisis subsided simultaneously with automobile

manufacturers making dramatic improvements in conventional vehicle fuel efficiency and emission of

pollutants. The introduction and wide spread deployment of engine-controlling microprocessors along

with continued improvements in exhaust after-treatment led to a near doubling of Environmental

Protection Agency (EPA) fuel mileages and an order of magnitude reduction in exhaust emissions. As

a result, there was little corporate interest in pursuing the heavier, more fuel efficient, less polluting,

but more complex and more expensive hybrid vehicles. Even so, the considerable work that had been

completed showed that hybrids could simultaneously improve fuel efficiency and further reduce

greenhouse gas emissions compared to current conventional vehicles.

It was the Japanese automobile industry that introduced conventional hybrid-electric vehicles to the

world with the Toyota Prius and Honda Insight and Civic models.

Today, four general types of hybrids are commonly recognized. Micro-hybrid, mild-hybrid, and full-

hybrid vehicles are commercially available; plug-in hybrids have been demonstrated, but are still

under development. Regenerative braking is used on almost all types of hybrids. It converts some of

the kinetic energy of a moving vehicle to electrical energy and stores it in the battery for later use,

rather than converting it to wasted heat by friction between the brake discs and brake pads. However,

friction brakes are also required to come to a complete stop. The identifying characteristics of the four

types are:

Micro-Hybrid. When the vehicle stops, the engine is turned off to save fuel. When the driver

pushes the accelerator, the integrated starter/alternator initiates acceleration of the vehicle and

simultaneously starts the gasoline engine. The integrated starter/alternator assists the engine in

accelerating the vehicle until the desired speed is reached. The gasoline engine alone propels the

vehicle during cruising. Fuel efficiency is about 10% better than for a comparable standard

vehicle (22 mpg vs. 20 mpg).

Mild-Hybrid. The electric motor (starter) and alternator are separate units. The electric motor

assists the gasoline engine, but generally does not propel the vehicle alone except in “start and

stop” traffic. The electrical components are larger and the gasoline engine is smaller than in the

micro-hybrid. Fuel efficiency is about 20–25% better than for a comparable standard vehicle

(24-25 mpg vs. 20 mpg).

Full-Hybrid. All the electric components are larger than in the mild-hybrid so that it can

operate on the battery alone for longer periods of time. The gasoline engine is somewhat

smaller, and the fuel efficiency is typically 40–45% better than for a comparable standard

vehicle (28–29 mpg vs. 20 mpg).

Plug-in Hybrid. The battery typically needs a much larger capacity than in the full-hybrid, and

the vehicle needs an “all electric” range that is about 5 times greater than that of a full-hybrid.

The gasoline engine may be somewhat smaller, and the digital control system to optimize the

various driving situations is more complex. Gasoline mileage has little meaning since the

vehicle may use little or no gasoline for short trips, only electrical energy in the battery that

came from an electric utility.

These four types of hybrid have many common components, such as regenerative braking, gasoline

engine, electric motor, alternator, battery pack, and central digital-control system. Moving from the

micro-hybrid to the plug-in hybrid, the size of the electrical components becomes larger and their use

increases, the gasoline (or diesel) engine becomes somewhat smaller, the performance (acceleration)

increases, and the fuel economy increases. However, larger electrical components are heavier, more

complex, and more expensive. Furthermore, the decrease in the size of the gasoline engine is often less

than the increase in size of the electrical components.

The reason that hybrid vehicles accelerate so well is that torque, which provides acceleration, is very

high at stall and low speed for electric motors. Torque produced by a gasoline engine increases with

engine speed from a low value at low rpm (revolutions per minute) to a maximum in the 1500–2500

rpm range, after which it falls off somewhat. Hence, in hybrids, the combination of an electric motor

and a gasoline engine together provides higher torque and better acceleration than is available in

comparable conventional vehicles of equal horsepower, even though the hybrids usually weigh more

and have smaller gasoline engines.

The reason that hybrids are so fuel efficient is that the amount of fuel consumed per unit of energy

output (specific fuel consumption—pounds or gallons per horsepower-hour output) generally

decreases with power level until it reaches a minimum at 65–85% of maximum power. Multi-speed or

continuously variable speed drives are used to keep the engine operating near its most efficient speed.

Thus, a smaller engine running at a higher percentage of its full power is more efficient and more

economical for a given load than a larger, heavier gasoline engine operating at a lower percentage of

its maximum power.

The Electric Power Research Institute (EPRI), the research organization of the U.S. electric-utility

industry, has conducted a research program for plug-in hybrids using batteries that are charged

primarily with electricity generated by utilities. Generating the electricity needed to charge these

batteries is a primary new market for nuclear electricity, as discussed in this chapter [7].

5.1.1.2. Opportunities for reducing greenhouse gas emissions from transportation

The principal greenhouse gases are water vapour

(60–65%) and CO

(20–25%)

Water vapour stays in

the atmosphere for a relatively short time, a matter of hours or days, whereas CO

has an average

residence period of about a century. As a result, the amount of water vapour remains relatively

constant at a level related to the rate at which it is produced by weather phenomena, while CO

tends

to accumulate as the amount emitted increases. All other greenhouse gases (10–20%) such as methane,

ozone, nitrous oxide, carbon monoxide, and fluorocarbons tend to have lesser effects on the

atmosphere over time because of smaller quantities or short residence times. Hence, the only

greenhouse gas considered in this analysis is CO

Greenhouse gas emissions from gasoline vehicles in the United States of America

Combustion of gasoline emits 19.56 pounds of CO

per gallon of gasoline. Since the average gas

mileage in our model is 20 miles/gallon, the annual emission of carbon dioxide is

19.56 lb CO

per gallon / 20 miles/gallon = 0.978 lb/mile

0.978 lb/mile x 12,260 miles/year = 12,000 lb CO

/vehicle-year for gasoline vehicles

The total miles per day and per vehicle year are:

[9 x 10

barrels/day x 42 gallons/barrel x 20 miles/gallon] = 7.56 x 10

miles/day;

[7.56 x 10

miles/day x 365 days/year] / [225 x 10

vehicles] = 12,260 miles/vehicle year.

Clearly, the amount of CO

for smaller vehicles would be less than for larger vehicles because the

gasoline mileage is greater. However, the model for this analysis deals with average vehicles that

achieve 20 miles per gallon, the reference performance used for all comparisons.

Emissions for traditional hybrid vehicles

Since all the energy to propel traditional types of hybrid vehicles is provided by gasoline, this analysis

utilizes the increased fuel mileages assigned in an earlier publication [2], which reduces the total CO

emissions for traditional hybrid vehicle accordingly, as shown in Table 5.1.

Table 5.1. Emissions for hybrid vehicles

Type Gasoline CO

per CO

per

Hybrid Mileage Mile Vehicle-Year

Miles/gal lb lb

Micro-Hybrid 22 0.889 10,900

Mild-Hybrid 25 0.782 9,600

Full-Hybrid 29 0.674 8,270

These values are for hybrid vehicles of a size corresponding to an average vehicle that attains 20

miles/gallon. A larger or smaller vehicle would have proportionally higher or lower emissions.

A more thorough analysis of the environmental impacts of hybrid electric vehicles was performed in

1997 using the lifecycle analysis software GREET, the Greenhouse gases, Regulated Emissions, and

Energy use in Transportation model. GREET was developed at Argonne National Laboratory to

evaluate well-to-wheels energy and emission impacts of motor vehicle technologies powered with

various transportation fuels. The model and associated documents are posted at

http://www.transportation.anl.gov/software/GREET/index.html

. The 1997 study looked at total

lifecycle energy use and emissions from the vehicle cycle, the fuel cycle, and vehicle operations for

several hybrid electric vehicle designs and compared them with results for conventional vehicles.

Greenhouse gas emissions from the hybrids were found to be 40% lower than those from conventional

vehicles. Volatile organic compound emissions were reduced by 15 to 28%, carbon monoxide by 7 to

37%, and particulate matter with sizes smaller than 10 micrometers (PM

) by a small amount. On the

other hand, NOx emissions were calculated to increase by 28 to 67%, and SOx by a factor of 6 to 14.

In large part those increases were due to the processing of nickel needed for nickel-metal hydride

batteries. The transition to lithium-ion batteries should reduce those pollutants.

Overall energy use for hybrids was shown to be about 40% less than that for conventional vehicles,

with an equivalent reduction in fossil energy use and greenhouse gas emissions (CO

, CH

, and N

O).

No plug-in hybrid vehicles were examined in 1997. Those studies are underway now and results are

expected shortly.

Emissions for plug-in hybrid vehicles

The model used for greenhouse gas evaluations for a plug-in hybrid vehicle is the same model used in

sections 5.2.1.3 and 5.2.1.4 for cost analysis. The total distance travelled per day by all 4-wheel

gasoline-fueled vehicles is 7.56 x 10

miles/day. (See Section 5.2.1.2.) Subtracting the 5.625 x 10

miles per day travelled on electricity

gives 1.935 x 10

miles/day as the distance per day travelled as

a full-hybrid. This means that 74.4% of the distance was travelled using electricity as fuel and 25.6%

of the distance was travelled using gasoline.

The emission of carbon dioxide by plug-in hybrid vehicles is made up of two parts: that emitted

directly for 25.6% of the total mileage using gasoline and that emitted in the generation of 74.4% of

the total energy provided by electricity. The direct emissions due to the operation in full hybrid models

given in Table 5.1 for 25.6% of the miles is

8,270 lb CO

/vehicle year x 0.256 = 2,120 lb/vehicle year

If the electricity is supplied by nuclear, solar, wind, hydro or renewables, no carbon dioxide is

generated in the process of electricity production (though greenhouse gases are emitted in other stages

of the lifecycle of the energy source, for example in the mining and enrichment of uranium or in the

manufacturing of solar photovoltaic cells). Hence, the total emissions are 2,120 lb/vehicle year.

If the electricity is generated by fossil fuels (natural gas, oil or coal), the resulting generation of carbon

dioxide must be added to that generated directly. Carbon dioxide emissions generated per kWh of

electricity by fossil fuels are given in Table 5.2 based on data from the Department of Energy, Energy

Information Administration.

In Section 5.2.1.4, it is established that 0.603 kWh/mile is a reasonable average expenditure of

electrical energy for hybrid vehicles that would be comparable to a vehicle getting 20 miles per gallon

of gasoline using an internal combustion engine. It is readily shown that the average distance travelled

by each plug-in hybrid vehicle while operating on electricity alone would be 9,125 miles/year.

Hence, the electricity used is

9,125 miles/year x 0.603 kWh/mile = 5,502 kWh/vehicle year.

Table 5.2. Emission rates for fossil fuels

Fuel to Generate % of Total CO

Emission Rate

Electricity Generation lb/kWh

Coal 51.0 2.100

Oil 3.2 1.970

Natural Gas 15.2 1.320

Renewables 0.6 0 (net)

Non-Fossil* 30.0 0

*(Nuclear 20%; Hydro 7%; Wind 2%; Solar <1%)

If this value is multiplied by the amount of CO

emission per kWh for the three fossil fuels given in

Table 5.2 and added to the 2,120 lb/vehicle-year of CO

for operation in the full hybrid mode, the

results given in Table 5.3 for the various fuels are obtained.

The miles per day driven on electricity is:

[225 x 10

vehicles x (15 + 35)/2 miles/vehicle day] = 5.625 x 10

miles/day.

The average distance per year on electricity is:

[(15 + 35)/2 miles/vehicle day x 365 days/year] = 9125 miles /vehicle year.

Table 5.3. Emissions for plug-in hybrid vehicles

Fuel to Generate Emissions of CO

Electricity lb/vehicle-year

Coal 13,650

Oil 12,950

Natural Gas 9,400

Nuclear 2,120

Solar 2,120

Wind 2,120

Hydro 2,120

Renewables (Net) 2,120

It is clear that if some 200-250 new 1000 MWe power plants, as calculated later in this chapter, or

even a fraction of this number, are to be built to provide electricity for plug-in hybrid-electric vehicles,

they should not use fossil fuels. Indeed, a strong case can be made that nuclear energy is the only

practical choice. Both solar and wind are intermittent and would require large amounts of energy

storage and recovery systems that are almost as complex as generation systems. There are relatively

few, if any, remaining practical hydro sites in the United States, and renewables on this scale would

utilize an enormous amount of land that will be needed for food production for a growing population.

5.1.2. Opportunities in Japan

5.1.2.1. Situation of automotive fuels and electric power in Japan

In 2004 Japan imported about 96% of its energy from abroad, including 99.7% of its petroleum (of

which 89.5% is from the Middle East), and 96.5% of its natural gas. The transport sector consumes

about a quarter of the total energy in Japan. Most of the consumption is petroleum fuels (98% in

FY2000) such as gasoline or diesel oil used for automobiles.

Electricity also makes up a quarter of total energy demand. Electricity in Japan is generated from a

diverse set of sources, including nuclear 31.5%, coal 25.4%, natural gas 24.0%, petroleum 10.3%, and

hydro 8.4% (2005 statistics). Thus, in the power generation sector, the dependence on fossil fuels is

only about 60%. Hence, the security of the energy supply and the reduction of CO

emission are being

improved by decreasing the petroleum and carbon fuel consumption through a growth in non-carbon

electricity sources.

Similarly, if automobiles are powered by electricity by using plug-in type vehicles, the energy supply

can be diversified to become less dependent on petroleum. Along with the increase of plug-in vehicles

in the future, the new electric demand for charging the batteries would hopefully be supplied by

nuclear power, thus making the energy supply more secure and reducing CO

emissions in Japan.

5.1.2.2. Driving patterns of Japanese passenger vehicles

There are about 77.4 million vehicles altogether in Japan. From the size and the driving pattern of

these vehicles, the categories suitable for plug-in hybrid electric vehicles are the personal-use

passenger vehicles, of which there were 54.4 million vehicles as of 2003. They are classified into the

”registered” vehicles, which are ordinary-sized cars and ”light” vehicles, which are smaller cars with

engine capacities under 660 cm

and which have some benefits in terms of taxes and other costs.

The average daily travel distances of these categories of vehicle are estimated from the statistical

survey data from MLIT on the relationship of passengers carried for various distances.

Driving Pattern of Japanese Passenger Vehicles

Registered and Light Vehicles for Personal Use

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 20 40 60 80 100 120 140 160

Average Daily Travel Distance [Km]

Cumulative Fraction of Vehicles [-]

Registered V.

Light V.

FIG. 5.1. Driving patterns of Japanese passenger vehicles.

From Figure 5.1 on the driving pattern of Japanese passenger vehicles, it is presumed that on average

Japanese vehicles are driven about 20 km (18 km for light vehicles and 22 km for registered vehicles).

The average daily travel distance of Japanese vehicles is about 62% of that of US light vehicles, which

is about 20 miles or 32 km per day, as previously mentioned.

5.1.2.3. Expectation for plug-in hybrid electric vehicles in Japan

As the self-sufficiency of energy is currently very low in Japan, shifting the energy for the

transportation sector to nuclear energy, though it may take a long time, would significantly improve its

energy security. For nuclear energy supply to serve the transportation sector several technologies have

been suggested, including plug-in type vehicles, hydrogen fuel cell or combustion engines, or the use

of synthetic fuels. Among these, the introduction of plug-in hybrid vehicles into the automotive market

is expected to be the most realistic and is considered the leading option for this purpose.

As the weight of Japanese vehicles is lighter and the daily distance travelled is shorter in Japan as

compared to the U.S., especially for the category of ”light vehicle,” it would be easier to introduce

plug-in hybrid vehicles in Japan because a smaller battery could give a larger electric run fraction.

5.1.3. Opportunities in other countries

A recent comparison of gasoline consumption for several countries gives a useful view of the world

situation. In an article entitled “Situation is Obscenely Out of Whack” [8] the data in Table 5.4 were

given for the consumption of gasoline per person per year for transportation.

Table 5.4. Consumption of Gasoline throughout the World [8]

Consumption of Gasoline per person per year

United States 453 gallons

Europe (includes diesel fuel) 133 gallons

Japan 124 gallons

World Average 47 gallons

World Average (w/o U.S.) 28 gallons

China 10 gallons

India 2 gallons

The discrepancy between the gasoline consumption in United States and the rest of the world is clearly

shown. In many respects, the situation is a reflection of the historic low price and the large domestic

production of oil. Given the rapidly growing demand for oil in the developing countries, particularly

China and India, and the signs of declining production in many of the oil-producing countries,

including the United States, there is an urgent need for reducing the use of oil. Substitution of

electricity for oil by the use of plug-in hybrid vehicles is an attractive way of achieving this goal

without disrupting the existing transportation infrastructures in the developed countries, particularly

the United States.

Opportunities in the European Community

For the last several decades, the price of gasoline has been much higher in Europe than in the United

States, because of a large tax each European country has imposed. Since the OPEC embargo in 1973

until 2005, the price of gasoline has varied between $3 and $6 per gallon in Europe while the price in

the United States has varied between $1 and $2 per gallon. Europeans have adjusted to the higher

prices by buying smaller, more efficient automobiles and using a much higher percentage of diesel

powered light vehicles. The recent availability of biodiesel fuel that virtually eliminates diesel

pollutants may accelerate this trend. In addition, Europe has adopted efficient public transportation

systems. As a result, the steep rise in oil prices in 2005–2006 has had significantly less impact on

transportation costs in Europe than in the United States. Hence, there may be less urgency to consider

hybrid vehicles in Europe than in the United States. Indeed, the principal European automobile

manufacturer seriously investigating hybrid vehicles today is DaimlerChrysler, and none have hybrid

vehicles for sale or lease.

Opportunities in China and India

China and India have populations of about 1.4 and 1.0 billion, respectively, and are growing. Their

economies are growing extremely rapidly, and both are developing a large economic middle class that

are buying automobiles and other light vehicles. If these vehicles utilize oil-based fuels, the current

world mismatch between supply and demand will be exacerbated, and the price of oil will continue to

rise. A strategy by China and India to minimize the use of gasoline through substitution of electricity

would be beneficial to all countries and help stabilize the price of gasoline in China and India as well

as in the rest of the world. China has an aggressive program of installing new nuclear (and other)

power plants that could be utilized to provide electricity to charge automotive batteries at night.

Indeed, with all the new power plants they are building, their excess capacity at night may be adequate

to charge vehicle batteries, which would contribute to keeping the nuclear power plants at continuous

base load operation.

5.2. Market context

5.2.1. Market context in the United States of America

5.2.1.1. Status of hybrid-electric vehicles

Today, there are several automotive manufacturers, including Ford, General Motors, Honda, Toyota,

and Lexus that offer conventional hybrid (micro-hybrid, mild-hybrid, and full hybrid) vehicles.

Generally, these vehicles (except the micro-hybrids) sell at prices that are $5000 to $10 000 higher

than corresponding traditional models, and that typically are not offered at discounted prices. Some

models provide gas mileages that are significantly better than their corresponding traditional models;

others offer only minor gasoline mileage improvements, but rather, offer outstanding acceleration.

General Motors, Ford and Toyota are the principal automotive manufacturers which have expressed

interest in plug-in hybrids. GM and Ford displayed plug-in hybrid electric vehicles using lithium-ion

batteries at the Detroit Automobile show in early 2007. However, as indicated in section 5.3.1, few

automakers intend to produce consumer test vehicles as GM had done with their EV1 electrical

vehicles. Toyota, however, announced on July 25, 2007, that it is donating several prototypes of its

Plug-in HV to the University of California-Irvine and the University of California-Berkeley for road

testing. In addition, Toyota stated that the Japanese Ministry of Land, Infrastructure and Transport

(MLIT) has now approved testing of plug-in hybrid vehicles on Japanese public roads. The Plug-in

HV has a battery range of 8 miles on a full charge, which is significantly less than the 30-mile all-

electric range achieved by EDrive with its modification of the Prius with larger lithium ion batteries.

Toyota has indicated that the Plug-in HV is not ready for commercialization, because it uses low-

energy nickel-metal hydride batteries, rather than more advanced lithium-ion batteries. The company

sees battery technology as the key technical barrier to the viability of plug-in hybrid vehicles. Toyota

and General Motors have announced targets of 20 to 40 miles on a single charge for plug-in hybrids.

The U.S. government offers up to $3,400 in credits against income taxes for the first 60,000 U.S.

taxpayers who purchase certain certified hybrid vehicle models from any manufacturer. Generally the

certification is related to the improvement in gasoline mileage and decrease in greenhouse gas

emissions. The combination of this tax credit and the reduction in the cost of fuel (i.e. use of lower-

cost electricity in place of expensive gasoline) may be adequate to recover the higher price of some

hybrid vehicles (but not others) over a few years. Toyota, for instance, has already reached the 60,000

limit, and the tax credits are being phased out over a year for both Toyota and Lexus models.

The primary motivation for buying the more efficient hybrid vehicles such as the Toyota Prius and

Honda Civic appears to be better gas mileage. However, trends in newer hybrids (Toyota Highlander

and Honda Accord) have been to emphasize performance (0 to 60 mph in about 7 seconds), whereas

gas mileage is only a little better than their conventional counterparts. Honda recently discontinued its

most efficient hybrid, the two-passenger Honda Insight, apparently because it sold less than 1000

vehicles in the last year. The total number of hybrid vehicles sold in the United States in 2005 was

205,749 of which 52% were the Toyota Prius. Even so, this is a small fraction of the ~15 million total

vehicles sold annually in the United States. Given the present pattern of traditional hybrid designs and

sales, the overall impact on the amount of gasoline used for transportation in the United States is not

likely to be significant. Estimates for market penetration in a decade or two range from 3% by J. D.

Power Forecasting to 80 % by Booz Allen Hamilton, with the DOE EIA predicting a conservative 7%

of total sales. If an average of 30% improvement in gas mileage and a 30% market penetration by

conventional hybrids is assumed, the savings of gasoline would be only about 0.6 of the 9.0 million

barrels per day currently used, a 6.9% saving. This is not the kind of fuel saving that is needed in the

United States to significantly reduce the U. S. dependence on foreign imports. The conclusion is that

the traditional hybrid vehicles will not significantly reduce fuel consumption in the United States.

Only plug-in hybrid-electric (or perhaps hydrogen fueled) vehicles can save enough gasoline to

significantly reduce gasoline consumption to the extent needed.

Given the situation described above in which the market penetration for conventional hybrids appears

limited with the primary emphasis of recent models on performance rather than fuel economy, we

must look to the plug-in hybrids to achieve a significant saving of fuel. It is theoretically possible to

save almost 75% of the fuel currently used, some 6.7 of 9.0 million barrels per day if all vehicles

suddenly became plug-in hybrids operating in the average manner described in the model. If there

were only a 30% market penetration by plug-in hybrids, there would be a savings of about 2 of the 9

million barrels per day, about three times the savings of traditional hybrid vehicles.

5.2.1.2. U.S. light-vehicle transportation statistics and model

Estimates based on extrapolated DOE-EIA data

from the 1990s indicate that there are approximately

225 million four-wheel, light-transportation vehicles in the U.S; 133 million are passenger

automobiles and 92 million are light truck vehicles (including SUVs, minivans, pickup trucks, and

delivery vans). It is further estimated by EIA that on any given day, on average, 50% of U.S. vehicles

are driven less than 20 miles. Using these statistics, a simple model can be developed to calculate the

potential saving of fuel by the use of hybrids operating in a plug-in mode. The model assumes that

only the electric motor, operating on batteries charged from electric-utility sources, is used to power a

vehicle until the battery has discharged to a level requiring charging of the battery to maintain normal

full-hybrid performance (estimated to be 35 miles). Beyond that point, the gasoline (or diesel) engine

and electric motor would operate together in the normal full-hybrid mode.

Model for plug-in operation

As before, the standard automobiles and light truck vehicles are grouped and assumed to achieve an

overall average of 20 miles per gallon of gasoline.

It is assumed that in two to three decades (i.e.,

2025 to 2035), all these vehicles are hybrids capable of the plug-in mode of operation.

This involves

charging the batteries of a hybrid vehicle overnight using electricity from an electrical outlet, typically

in the owner’s garage. It is assumed that when batteries are fully charged, these hybrids can operate

using only the electric motor for at least the first 35 miles. For this type of operation, the controls of

current full-hybrids would need to be modified so as not to use the gasoline engine to recharge the

batteries beyond the level necessary to sustain normal hybrid operation. The vehicles envisioned by

the authors for plug-in operation are those manufactured by automotive companies to meet today’s

safety and quality standards, and are equipped with normal features such as automatic transmission, air

conditioning, and power steering. Hence, a more powerful electric motor (kW) and better and higher-

capacity batteries (kWh) would be required.

This could lead to the use of a smaller gasoline engine.

Solid-state digital controls capable of optimizing performance and economy while minimizing the use

of fuel should make the performance and economics of these vehicles more than competitive with

comparable standard vehicles while drastically reducing both fuel consumption and greenhouse gas

emissions.

Unless otherwise indicated, data on U.S. vehicles are from the DOE Energy Information Administration’s

(EIA) statistics available on the internet (see Bibliography).

DOE EIA data show that in 2003, automobiles averaged 22.3 miles per gallon and light trucks averaged 17.7

mpg.; hence, 20 mpg is a reasonable weighted-average value for all vehicles (see Bibliography).

This assumption was made in order to evaluate the total potential savings of fuel associated with using hybrid

vehicles operating in the plug-in mode. Fuel savings will be reduced in relation to the percent of light vehicles

that are not plug-in hybrids.

Most current commercial full-hybrid vehicles would have to have batteries with at least five times more

capacity (kWh) and probably more power (kW) to operate at highway speeds for this distance.

5.2.1.3. Model to calculate fuel saved by the plug-in mode of operation

The model assumes that each day one-half of the 225 million light-hybrid vehicles operate only for 15

miles on batteries alone while the other half operate on batteries alone for their first 35 miles and then

automatically switch to normal full-hybrid mode (in which gasoline powers the vehicles for the

remaining miles that day). This means that electrical energy provided by a utility to recharge batteries

would drive these vehicles for a grand total of 5.625 billion miles per day or an average of 9,215 miles

per vehicle year.

If the comparable standard (non-hybrid) light vehicle averages 20 miles per gallon,

then 225 million light vehicles would use 281 million gallons of fuel per day to travel 5.625 billion

miles per day. Hence, it is theoretically possible, based on this simple model, to replace 281 million

gallons (6.7 million barrels) of fuel per day with electricity by using hybrid vehicles operating in the

plug-in mode.

This represents 74.4% of the estimated nine million barrels of oil per day now used to

produce gasoline for standard automobiles and light-truck based vehicles.

These results are

consistent with work carried out by the Electric Power Research Institute in cooperation with Daimler

Chrysler. [7] Clearly reductions in both imported oil for transportation fuels and emitted atmospheric

pollutants would be dramatic with widespread acceptance of full-hybrids operating in the plug-in

mode with power from non-carbon sources. However, realistically, some of the saved fuel would still

be needed, because in the two to three decades needed for full implementation, the number of vehicles

and the number of miles driven per vehicle in the U.S. could increase significantly—perhaps 50% or

more in total miles.

5.2.1.4. Fuel cost savings

At a price of $3.00 per gallon, the fuel cost is $0.15 per mile for standard light vehicles averaging 20

mpg. Since a gallon of gasoline contains 36.65 kWh of thermal energy, 1.833 kWh is used per mile.

However, the efficiency of an internal combustion engine operating over a range of speeds plus energy

losses in the transmission, drive, and tires results in an “overall gasoline thermal energy to miles

travelled efficiency” of about 20%.

Hence, the average mechanical energy expended at the

pavement for driving the vehicle is only 0.367 kWh per mile. If the overall efficiency of the electric

drive including charger, batteries, motor, generator, and drive is 70%, the electrical energy purchased

from the utility is 0.524 kWh per mile. Because the proposed plug-in mode of operation would

probably require larger batteries and perhaps a larger electric motor, adding a few hundred pounds of

weight to the vehicle, this value could be increased by 15% to 0.603 kWh per mile. At a price of $0.08

per kWh

, the cost of electricity to drive a mile in a hybrid vehicle is only $0.048. This is $0.102 per

mile less than the $0.150/mile for gasoline. For the half of light hybrid drivers in our model who travel

15 miles per day (5,475 miles per year) using electricity, the annual savings would be $558 per year.

For the other half of the light-hybrid drivers who travel 35 miles per day (12,770 miles per year) using

electricity before shifting into full-hybrid mode, the savings would be $1303 per year. There would

also be some additional saving of gasoline, calculated to be 108 gallons/year, associated with full-

[225 x 10

vehicles] x [(15 +35)/2 miles/vehicle day] = 5.625 x 10

miles/day;

[5.625 x 10

miles/day x 365 days/year] / 225 x 10

vehicles = 9125 miles/vehicle year.

5.625 x 10

miles/day / 20 miles/gallon = 281 x 10

gallons/day or 6.70 x 10

barrels/day.

Changing the model assumptions would give different numerical results, but would not affect the overall

conclusion that it is possible to save a large majority of the petroleum fuel used for U.S. light vehicles

today through the wide-scale use of plug-in hybrid vehicles.

Estimate of this efficiency by Toyota Motor Company is 16%, which is used in the analysis of Japanese

vehicles later in this chapter.

This price is the estimated interruptible price in which the utility could interrupt the charging of vehicle

batteries during short periods of peak electrical demand in exchange for a reduced cost of electricity. The

consequences to the driver are estimated to be negligible, perhaps a few extra gallons of gasoline per year.

hybrid operation for the remaining distance travelled by the second half of the vehicles. This amounts

to$324 per year for $3.00 per gallon gasoline. Hence, the total savings would be $1627/year at

$3/gallon for the second half of the vehicles.

5.2.1.5. Impact of tax on electricity used in vehicles

It is inevitable that if electricity becomes a significant source of energy for automotive and light-truck

vehicle travel, it will be taxed by an amount sufficient to recover the tax revenue lost on petroleum-

based fuels by governmental authorities at the national, state, and local levels. If we assume that the

current total tax on these fuels is about $0.35 per gallon and the total consumption of fuel is 103

billion gallons per year (281 million gallons per day), the total tax would be $36.0 billion per year.

Using information provided earlier, the calculated total kWh of electricity consumed in the plug-in

mode would be 1.238 trillion kWh per year. The equivalent tax is about $0.029 per kWh, thereby

increasing the cost of electricity used on the road from $0.080 to $0.109 per kWh. Hence, the fuel cost

per mile for the light-hybrid vehicles increases from $0.0483 to $0.0657 per mile, which is still less

than half of the $0.150 per mile for standard vehicles using $3 per gallon of gasoline. These electrical

costs are equivalent to $0.97 and $1.32 per gallon respectively without and with taxes.

The annual savings for gasoline at $3 per gallon are substantial, but they may not be large enough to

justify the additional cost of a plug-in hybrid vehicle. However, if the cost of gasoline increases to $5

or $6 per gallon, prices that are common in Europe today and a realistic possibility in the U.S. if oil

imports are not significantly reduced or if taxes are imposed to reduce greenhouse gas emissions, the

savings become much larger. These annual savings with and without taxes for gasoline prices ranging

from $1 to $7 per gallon are shown in Figure 5.2.

Annual Savings of Plug-In Hybrid Vehicles

Cost of Electricity: $0.08 per kWh

-500

500

1000

1500

2000

2500

3000

3500

4000

4500

1234567

Cost of Gasoline $/Gallon

Annual Savings $/Year

15 miles/day No Tax

15 miles/day Tax

35 miles/day No Tax

35 miles/day Tax

FIG. 5.2. Annual savings of plug-in hybrid.

[(7.560 x 10

– 5.625 x 10

) miles/day x 365 days/year x $3/gal] / [225 x 10

vehicles x 29 miles/gal]

= $324/vehicle year.

5.2.1.6. Home electrical service required

Now let us look at the electrical supply required to support plug-in hybrid-electric vehicles. Light-

hybrid vehicles that travel 35 miles per day on electricity using 0.603 kWh/mile would use 21.1 kWh

per day. If batteries are to be charged in eight hours at night using a 110-volt system, the required

capacity would be about 24 amps. However, charging batteries requires more current when the

batteries are deeply discharged, so the peak currents could be higher. Even so, it seems reasonable that

most modern homes would have adequate spare capacity to provide at least 30 amps at 110 volts

during the night. Apartment dwellers or urban dwellers who rely on street-side parking or public

parking facilities may not have ready access to electricity for overnight charging. Infrastructure would

need to be developed to accommodate such consumers.

5.2.1.7. Electric utility generating capacity

Plug-in hybrid electric vehicles may represent a significant new demand for electricity. It is important

to know, then, the total potential electrical generating capacity required. Multiplying the 5.625 x 10

miles per day for all the light hybrids using electricity times the 0.603 kWh per mile results in 3.39

billion kWh per day. Charging the batteries in eight hours would require 424 million kWe or 424

GWe. This equals the output of 424 power plants of 1,000 MWe size. Because the entire generating

capacity of the United States today is about 950 GWe, it is clear that there would not be sufficient

spare capacity available at night or any other time to charge the batteries of all the hybrids that could

exist in 2035. Although not all charging would occur in the same eight-hour period because of time

zones and the availability of some existing excess capacity, significant new generating capacity—

perhaps 200 to 250 new 1,000 MWe nuclear or other non-polluting plants—would have to be built to

charge the batteries for complete conversion to plug-in hybrids. New transmission and distribution

lines and substations would also be needed to deliver the electrical power. Building 200 to 250 new

1,000 MWe power plants and associated power delivery facilities in two to three decades would be a

daunting task, but certainly feasible.

5.2.2. Opportunities in Japan

5.2.2.1. Model evaluation of plug-in hybrid-electric vehicles in Japan

The effect of introducing plug-in hybrid electric vehicles (PHEV) in Japan is evaluated for the

category of personal use passenger vehicles.

Target vehicles for evaluation

As described earlier, in Japan passenger cars are classified into two categories: the ”registered” vehicle

and the ”light” vehicle. Typical statistical data of these vehicles are shown in Table 5.5, which are

derived from the 2003 Report by the Ministry of Land Infrastructure and Transport, Japan (MLIT).

Table 5.2.1. Data used for evaluation of PHEV

Registered

vehicles

Light

vehicles

Number of cars 42,620,000 11,820,000

Average distance traveled per

working day per car, km

40.7 27.9

Working ratio *, %

66.9 72.7

Average distance traveled per

day per car, km

27.2 20.3

Average distance traveled per

year per car, km

9,900 7,400

Fuel consumption per car per

Km **, liter/km

0.12 0.09

* Working ratio＝(Working days x cars / Existing days x cars ) x 100

** Gasoline engine

Methodology and input data

The methodology and most of the parameters used are similar to the U.S. analysis just described. [2]

Nevertheless, there are some differences from the U.S. analysis:

•

The average electric run fraction is estimated from the statistical data from MLIT;

•

The tank-to-wheel efficiency for ICEVs is based on the information from Toyota Motor

Company.

Input data used for the evaluation are as follows:

•

Tank-to-wheel efficiency for ICEVs: 16%;

•

Battery-to-wheel efficiency for PHEVs: 70% (Adding 15% to the required energy because of

the extra weight for PHEVs);

•

Gasoline price: 122 Yen/litre including a gasoline tax of 53.8 Yen/litre;

•

Electricity price: 10 Yen/kWh (A typical price of the midnight special fee for 11pm to 7am

including the basic charge);

•

emission for gasoline: 2.32 kg-CO

/liter gasoline (Guideline by the Ministry of

Environment);

•

emission for electric power: 0.381 kg-CO

/kWh (Performance data of Tokyo Electric

Power Company in 2004).

Electric run fraction

In this evaluation, the average daily travel distance is estimated from the statistical survey data by

MLIT on the relationship of passengers carried for various distances for the categories of vehicle as

described in Section 5.1.2 In Fig. 5.1. is shown the cumulative fraction of vehicles with average daily

travel distances for the two categories of vehicles.

The average fraction, by distance, of traveling in the electric vehicle mode (electric-run) relative to the

capacity of the equipped battery can be estimated from the relation of Fig. 5.1. The relation obtained

for the average electricity-run fractions is shown in Fig. 5.3 for the registered vehicles and the light

vehicles. From the figure, it is estimated that 70% of the electric-run fraction by distance can be

obtained by installing a battery with a capacity of about 60km for the registered vehicles and about 35

km for the light vehicles.

Abbreviations

ICEV: Internal Combustion Engine Vehicle

PHEV: Plug-in Hybrid Electric Vehicle

HEV: Hybrid Electric Vehicle or Gas-Electric Vehicle

BEV: Battery Electric Vehicle

Passenger Vehicles for Personal Use

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 20 40 60 80 100 120 140 160

Battery Capacity [km]

Electric-Run Fraction [ -

]

FIG. 5.3. Relation of electric-run fraction with battery capacity.

Running cost

The running costs of ICEVs, PHEVs in the electric-run mode, and PHEVs in the mixed electric-

run/hybrid-electric mode are evaluated and compared as follows:

The running costs for registered vehicles are:

ICEV: 14.6 Yen/km

PHEV in the electric-run mode: 3.0 Yen/km

- PHEV in the 70% electric-run mode and 30% hybrid-electric mode: 4.0 Yen/km

The running costs for the light vehicles are:

ICEV: 11.0 Yen/km

PHEV in the electric-run mode: 2.3 Yen/km

PHEV in the 70% electric-run mode and 30% hybrid-electric mode: 3.0 Yen/km

The running cost of PHEVs in the electric-run mode is about 1/5 of that for a gasoline ICEV, and the

running cost of PHEVs in the 70% electric-run mode and 30% hybrid-electric mode is 1/3.6. If the

gasoline tax is excluded, this ratio becomes 1/2.7 and 1/2.6, respectively.

5.2.2.2. Electric power requirements in Japan

If all the vehicles (both registered vehicles and light vehicles for a total of 54 million vehicles) become

PHEVs in the 70% electric-run mode, the total electricity requirement for 8-hour charging is about 35

GW (35 units of 1,000 MW plant). Since there is about a 50-GW difference between the peak hours

and the midnight hours currently in Japan, most of the power for all PHEVs could be supplied by the

spare power.

Since nuclear power is presently used as the base load in Japan, the additional power requirements

would have to be supplied by operating fossil fuel plants at night. For energy security and global

environment, it is better to shift the power supply structure, in the course of introducing PHEVs, to a

greater nuclear share by replacing the fossil fuel plants by new nuclear plants.

Registered

Light

5.2.3. Energy utilization efficiencies of various power trains

Energy flow to the vehicles with various power trains, such as internal combustion engine vehicles

(ICEVs), hybrid electric vehicles (HEVs), plug-in hybrid electric vehicles (PHEVs), battery electric

vehicles (BEVs) and hydrogen fuel cell vehicles (FCVs), is shown in Fig. 5.4.

The energy carriers such as hydrocarbons (gasoline, diesel oil, etc.), electricity, and hydrogen are

produced from primary sources, such as fossil fuels, nuclear energy, and renewable energies.

Fossil Fuels

Coal, Petroleum,

Natural Gas,

Oil Sands, etc.

Hydrocarbons

Gasoline, Diesel Oil, LPG,

CNG, DME, Synthetic Fuels,

Bio-fuels, etc.

Electricity

Hydrogen

Nuclear

Energy

Renewable

Energies

Primary Energy

Energy Carrier

Combust. Engine

ICEV

Hybrid

HEV

Plug-in Hybrid

PHEV

Battery Electric

BEV

Fuel Cell

FCV

Vehicle

FIG. 5.4. Energy flows to vehicles with various power trains.

Table 5.5. Energy utilization efficiency for various power train vehicles

well-to-wheel efficiency – fossil fuels

29~42 %50~60 %

Tank

58~70 %

Fuel Cell Vehicle

FCV

35 %

70 %50 %

Battery Electric Vehicle

BEV

Battery

Natural Gas Field

(29~30 %)

Plug-in Hybrid Vehicle

PHEV

28~32 %

32~37 %88 %

Gasoline Hybrid Vehicle

HEV

14 %

Wheel

16 %

Tank

88 %

Oil Field

Gasoline Engine Vehicle

ICEV

Well To Wheel

Efficiency

Tank to Wheel

Efficiency

Well to Tank

Efficiency

¾ The values for ICEV, HEV, FCV are from a Toyota Motors's 2003 presentation. The values for FCV are for the

hybrid specification.

¾ Electric Power for BEV is based on the natural gas ACC power generation of 55% thermal efficiency, 5% loss

from well to station, and 5% loss for electricity transmission and distribution.

¾ EV battery-to-wheel efficiency is based on Uhrig (ANS, 2005).

¾ PHEV adds 15% to the energy required by weight increase. PHEV well to wheel efficiency is estimated for 70%

EV run.

¾ The heating values are based on the Lower Heating Value (LHV).

The lifecycle energy utilization efficiencies of vehicles are usually expressed by Well-to-Wheel

(WTW) efficiencies, of which typical values are shown in Table 5.5. In this table, for gasoline engine

vehicles the ”well” means the oil wells producing crude oils, and for battery powered electric vehicles

and hydrogen fuel cell vehicles the ”well” means the gas fields producing natural gas currently used

for hydrogen generation. From Table 5.5, the FCV has the highest efficiency and the BEV is the

second highest. The PHEV efficiency would be somewhere between BEV and HEV.

The energy utilization efficiencies for BEVs and FCVs using nuclear energy as a primary source are

shown in Table 5.6. Here, the efficiencies for three kinds of nuclear reactor are examined, namely

LWR (Light Water Reactor, typical of low-temperature reactors), SFR/SCWR (Sodium-cooled Fast

Reactor / Super Critical Water Reactor, typical of medium-temperature reactors), and VHTR (Very

High Temperature Gas-cooled Reactor, typical of high-temperature reactors).

As for the LWR-based energy flow paths to vehicles, one path is the electricity from a LWR being

supplied to the BEV, and the other is hydrogen from water electrolysis by LWR electricity being

supplied to the FCV. As for the SFR/SCWR-based energy flow paths to vehicles, one path is

electricity from a SFR/SCWR being supplied to the BEV, and the other path is hydrogen from

SFR/SCWR-heated steam reforming of natural gas being supplied to the FCV. As for the VHTR-

based energy flow paths to vehicles, one path is electricity from a VHTR being supplied to the BEV,

and the other path is hydrogen from a thermochemical splitting of water by VHTR heat being supplied

to the FCV.

As shown in Table 5.6, in either the LWR or the VHTR case, the path to BEVs is more efficient than

the path to FCVs. This is due to the following two reasons:

(1). Both the electricity generation and the hydrogen production by electrolysis or thermochemical

splitting of water have to go through the a heat engine cycle in which the conversion efficiency

is limited by thermodynamic laws (the Carnot-cycle efficiency providing an upper limit);

(2). The drive train efficiency is higher in a BEV (70%) than in an FCV (50-60%).

In contrast to the above assessment for LWR and HTGR systems, in the SFR/SCWR case the path to

FCVs provides a higher efficiency than the path to BEVs, as hydrogen is produced by the process of

nuclear-heated steam reforming of natural gas (methane). In this hydrogen production process, the

chemical energy of methane and nuclear heat is converted to the chemical energy of hydrogen with no

limitations of thermodynamic cycle efficiency. This is the same as in the case of hydrogen production

from natural gas shown in Table 5.5.

In the case of nuclear-heated steam reforming of methane, it is inevitable that the process produces

though the total amount produced is reduced by about 30% as compared to the case of

conventional methane-combusted steam reforming of methane.

A medium-temperature reactor with an outlet temperature 500 - 600 ºC such as an SCWR or an SFR is

the best suited for the membrane reformer hydrogen production method using palladium (Pd) as

membrane material. The Pd-membrane reformer has been developed by Tokyo Gas as a production

method for a hydrogen fueling station [9, 10]. The nuclear-heated membrane reformer that combines

the membrane reformer with a nuclear reactor has been designed by Mitsubishi HI and others and

evaluated to be economically competitive with conventional methane-combusted steam reforming of

methane [11]. HTGRs and other higher-temperature reactors could also be used in this application

with the excess heat available for other purposes such as electricity production or process heating uses.

That case has not been assessed here.

Table 5.6. Energy utilization efficiency for electric and fuel cell vehicles

‘nuclear reactor to wheel’ efficiency

23~27%50~60%45%

Thermochemical

FCV

31%70%45%

Gas Turbine

BEV

VHTR

38~46%*50~60%77%*

Nuclear-Heated

Steam Methane

Reforming

FCV

27%70%39%

Steam Turbine

BEV

SFR /

SCWR

12~14%50~60%23%

Electrolysis

FCV

21%70%30%

Steam Turbine

BEV

L W R

Overall Efficiency

Reactor

→Wheel

Efficiency

Battery/Tank

→Wheel

Efficiency

Reactor →

Battery/Tank

Electricity / Hydrogen

Vehicle Power Train

Nuclear

Reactor

¾ Thermal efficiency: LWR steam turbine 32%, SFR steam turbine 41%, VHTR gas turbine 47%

¾ Efficiency of H

production: Electrolysis 80% from electricity and Thermochemical from heat 50%

(LHV) Reforming 85% (* Based on the sum of both primary energies)

¾ Transmission & distribution loss for electricity: 5%, Compression & transportation loss for H

: 10%

It can be concluded that, in the nuclear energy based energy flow to vehicles, the path to electric

vehicles is more efficient than the path to hydrogen fuel cell vehicles, except in the case of using

hydrogen produced by nuclear-heated steam reforming of methane.

5.2.4. Greenhouse gas emissions in Japan

The CO

emissions of ICEVs, PHEVs in the electric-run mode, and PHEVs in the mixed electric-

run/hybrid-electric mode are evaluated and compared as follows:

The CO

emissions for registered vehicles are:

- ICEV: 0.278 kg-CO

/km

- PHEV in the electric-run mode: 0.115 kg-CO

/km

- PHEV in the 70% electric-run mode and 30% hybrid-electric mode: 0.117 kg-CO

/km

The CO

emissions for the light vehicles are:

- ICEV: 0.209 kg-CO

/km

- PHEV in the electric-run mode: 0.0866 kg-CO

/km

- PHEV in the 70% electric-run mode and 30% hybrid-electric mode: 0.0877 kg-CO

/km

The CO

emissions of both PHEVs in the electric-run mode and PHEVs in the 70% electric-run mode

and 30% hybrid-electric mode is about 1/2.4 of that for gasoline ICEVs.

5.3. Challenges

This section discusses technical barriers, and Section 5.4 addresses potential solutions. Certainly there

are separate barriers associated with transportation infrastructure and with the electric power industry,

but these are outside the scope of this document. Some of these barriers are:

• Conversion of automobile technology from conventional gasoline-powered vehicles to electric

and plug-in hybrid vehicles;

• Public acceptance of plug-in hybrid vehicles;

• Structuring of electricity pricing mechanisms to provide low-price electricity during off-peak

demand periods to encourage use of nuclear power plants for base load generation;

• Provision of other incentives (e.g., tax benefits) for adoption of vehicles that produce less

greenhouse gases and reduce reliance on petroleum fuels.

• Building of carbon-free electricity generation capacity and electricity transmission and

distribution systems.

5.3.1. Barriers to be overcome in the United States of America

Barriers to plug-in hybrid vehicles

Only a few plug-in hybrids are in existence in the United States, and until recently none of them came

from an automotive manufacturer. E-Drive Systems has converted several Toyota Prius models by

replacing the nickel metal hydride battery with a lithium-ion battery system having thousands of small

cells with about seven times the energy storage capacity of the Prius nickel metal hydride battery. A

modified control system has been added to optimize the performance while minimizing the use of

gasoline. The cost of the conversion is about $10,000 for each vehicle. DaimlerChrysler initially built

five Sprinter delivery vans that they distributed for testing (three in the United States of America).

Recently, they announced that they were building several dozen Sprinter vans for testing under a wide

variety of circumstances throughout the world. It is clear that the plug-in hybrid has a long way to go

before it can displace a significant fraction of the 9 million barrels of fuel used every day in the United

States.

The focus on delivery vans by DaimlerChrysler is a logical approach. The potential savings of fuel

costs by fleets of such vehicles operated from a central facility — the Postal Service, delivery services,

military organizations, or similar commercial and government organizations with fleets of vehicles

where centralized battery charging could become a routine part of the daily maintenance and service

— should be greater than the initial extra cost. The critical item for improving the performance of

plug-in hybrid vehicles is lighter, less expensive, reliable, more robust batteries having a factor of 5 to

10 greater energy storage capacity.

General Motors displayed a plug-in hybrid vehicle named Volt at the Detroit Auto Show in early 2007

[12]. It has a series configuration in which the electric motor drives the vehicle full time, and the

engine (3-cyclinder, 1000 cm

displacement), capable of using gasoline or ethanol E85, only drives the

generator to charge the 400 pound lithium ion battery. It is effectively an electric vehicle with a motor-

generator that can travel 40 miles without charging and can be fully charged in six hours on 110 volt

electricity. Indeed, the Volt has considerable similarity to the defunct GM electric EV1 vehicle (made

infamous in the movie "Who Killed the Electric Car?"). This appears to be the simplest and quickest

way to develop a new plug-in hybrid by using their experience with the EV1. GM is still developing

hydrogen as an automotive fuel and has suggested that they might use a hydrogen-fueled fuel cell in

place of a gasoline engine on their PHEV. However, GM has not announced any plans to build plug-in

vehicles for lease or sale, and has indicated that there is need for improved and lower cost batteries to

make plug-in vehicles commercially viable. Volt is the first variant built upon GM’s E-flex system

that will enable them to utilize the same chassis for multiple electric drive systems.

Ford Motor Company also displayed its PHEV concept at the 2007 Detroit Auto Show. Called the

Airstream because its style resembles the iconic “Airstream” aluminum recreational vehicles, it uses

lithium batteries with an all-electric travelling range of 25 miles that are charged using a fuel cell. The

hydrogen fuel cell drive train operates under electric power all the time. It has half the weight and cost

of today’s fuel cells and, unlike most fuel cells, it can operate under extreme winter conditions.

5.3.2. Barriers to be overcome in Japan

As summarized by Professor Hisashi Ishitani of Keio University at the closing speech of EVS-22

Workshop on “Plug-In Hybrid Electric Vehicle Workshop” that was held on October 25, 2006, in

Yokohama, Japan, the view of Japanese industry and academia on plug-in hybrid electric vehicles can

be expressed as follows:

(1) It is expected that PHEVs are an effective measure to solve the CO

and energy issue, and also a

practical and possible transition from HEVs to FCVs;

(2) The challenge is the cost and durability of batteries. It is necessary to support the development

of this technology;

(3) It is better to put forward the introduction of PHEVs, focusing on the petroleum savings and

CO2 reduction, by an available set-up (like the hybrid mode) than a pure-EV mode, which may

be difficult in the early stage;

(4) It is essential not to repeat the failures in development of BEVs and FCVs. As PHEVs are seen

to be based on current technology, it is vital to take one step forward at a time by assessing the

accomplishments along the way.

As stated in the press release of Toyota Motor Corporation in June 2006, Toyota will advance its

research and development of plug-in hybrid vehicles and is working on a next-generation vehicle that

can extend the distance traveled by the electric motor alone and that is expected to have a significant

effect on reducing CO

and helping to abate atmospheric pollution. Toyota also said on other

occasions that PHEVs would not be feasible for mass production without a breakthrough in battery

technology, and that, with today's best technologies, PHEVs are not commercially viable.

Toyota reiterated this point on July 25, 2007, when it announced it is donating several prototypes of its

Plug-in HV to the University of California-Irvine and the University of California-Berkeley for road

testing. The Plug-in HV has a battery range of only 8 miles on a full charge, because of its use of low-

energy nickel-metal hydride batteries, rather than more advanced lithium-ion batteries, which are not

yet available for these purposes.

In August, 2006, the Study Group on Next Generation Vehicle Batteries in the Ministry of Economy,

Trade and Industry (METI) issued a report, “Recommendations for the Future of Next-Generation

Vehicle Batteries” (The main text is written in Japanese, though an English summary is

available) [13].

In Annex 5 of this report, the battery cost and the competitiveness of PHEVs with ICEVs and HEVs

are evaluated for setting the R&D goals of battery development. The comparison was made on the

sum of vehicle purchase cost and fuel/electricity cost for a 10-year vehicle life. One example on Prius-

class vehicles shows that, for the PHEV to become comparable with ICEVs and HEVs, it is necessary

to reduce the cost of lithium-ion battery from the current cost (200 K Yen/kWh) by a factor of about 7

(to 30 KYen/kWh).

This example shows that intensive efforts toward development of battery technology are necessary for

the introduction of economically competitive PHEVs into the market. The report recommends that, for

introducing PHEVs around 2015, it is necessary to conduct a battery development project that is

completed by about 2010. The recommended action plan by the Study Group is described in

Section 5.4.2.

5.4. Solutions

5.4.1. Solutions in the United States of America

Hybrid battery technology

Today, most commercial hybrid vehicles have sealed nickel metal hydride batteries. They are

significantly better than traditional lead-acid batteries, but are relatively heavy, expensive, and do not

show a capability of becoming much less expensive in mass production. The power of nickel batteries

comes from the raw material, which is getting more expensive because of increased demands. The

primary alternative under consideration today is the lithium-ion battery, made up of thousands of

lithium cells, each one of them the size of a common “AA” battery. The Volvo 3CC concept car,

unveiled in 2004, was an all-electric vehicle that relied exclusively on 3000 lithium-ion cells and

provided the equivalent of 105 horsepower with zero emissions. The benefits of the lithium-ion

batteries are derived from the mass processing that can scale to the high volumes required for the

rapidly growing hybrid vehicle market without a corresponding increase in price. Larger and fewer

lithium ion-cells would have been more attractive, but they do not exist commercially yet.

Furthermore, as lithium cells that use cobalt-oxide cathode material become larger, they sometimes

encounter thermal-runaway transients in which they burn or explode. Substituting phosphate for cobalt

seems to prevent this problem, but reduces the output power. Even so, progress is being made to

address these problems. Estimates are that it will take three to five years before such batteries are

available in large size and are powerful enough, cheap enough, and reliable enough for mass-produced

vehicles. Meanwhile, lithium ion battery packs with thousands of cells continue to be the primary

technology under consideration for PHEVs in the near future.

5.4.1.1. Research and development in the United States of America

R & D in batteries

As an example of research progress in the U.S., recently U.S. patent #06979513 entitled “Battery

Including Carbon Foam Current Collectors” (assigned to Firefly Energy Corporation, Peoria, Illinois,

a spinout from Caterpillar Tractor Corporation) appeared on the “Battery Digest” web site.

This

patent has similarities to an earlier patent issued to Alvin Snaper regarding foam plates in lead acid

batteries.

The fundamental concept of both patents is a replacement of the lead plate current

collectors. With both concepts, active materials are deposited on a high-surface-area substrate,

reducing total weight and possibly offering additional advantages of corrosion resistance and higher

power density. The high surface area greatly increases the current density, leading to much greater

current delivery. Furthermore, the Firefly carbon foam substrate has a very high thermal conductivity,

thereby overcoming the thermal build-up reported in larger lithium ion batteries.

5.4.2. Solutions in Japan

The METI Study Group recommended two action plans for the future of next-generation vehicle

batteries in August 2006, namely the R&D Strategies and the Infrastructure Building Strategies.

Inventors: Kelley and Votoupal. Assignee: Firefly Energy Corporation.

This description is taken from the Batteries Digest Web Site at http://batteriesdigest.com/id492.htm.

Action Plan – R&D Strategies

This action plan is composed of three phases: (i) Improvement phase, (ii) Advanced phase, (iii)

Innovation phase. At each phase are specified the types of vehicles expected to be developed,

performance and cost target of batteries, and the role of industry, government and academia. As shown

in Table 5.7, the PHEV is supposed to be introduced around 2015 with a battery of 1.5 times

performance and 1/7 cost of current batteries. The New Energy and Industrial Technology

Development Organization (NEDO) will be the secretariat for coordinating universities, research

institutes, automobile manufacturers, battery manufacturers, material manufacturers, and electric

power companies.

Table 5.7. Japan’s battery development action plan [13]

2. Infrastructure Building Strategies

1. R&D Strategies

This action plan is to be implemented along with the battery R&D plan, and is composed of building

software and hardware infrastructures such as incentive measures for vehicle popularization,

regulatory framework, standardization, safety standards, and battery charge stations, as shown in

Table 5.7. The secretariat of this action plan will be the Japan Automobile Research Institute (JARI)

and METI. The R&D strategies to implement this action plan, shown in Table 5.8, were taken from

the report, “Recommendations for the Future of Next Generation Vehicle Batteries,” carried out by the

Study Group on Next Generation Vehicle Batteries, Ministry of Economy, Trade and Industry, Japan,

in August 2006.

Table 5.8. Research and Development, Action Plan for Next Generation

Battery Technology Development

Goals of Battery

Phase Time

Target Vehicle

Type

Performance Cost

Required

R&D Items

Limited Purpose

Commuter BEV

Battery Range

80Km, 2 Seater

Same as Present

100Wh/Kg

1000W/Kg

1/2 of

Present

１

Improvement ca. 2010

High Performance

Hybrid

HEV

Fuel Economy 30%

Same as Present

70Wh/Kg

2000W/Kg

1/2 of

Present

Li-ion Battery

Carrier: N.R.

Material: P.R.

Design: R.

Commuter

BEV

Battery Range

150Km, 4 Seater

1.5 Times of

Present

150Wh/Kg

1200W/Kg

1/7 of

Present

２

Advanced ca. 2015

Plug-in Hybrid

Electric

PHEV

Battery Range

40Km

1.5 Times of

Present

100Wh/Kg

2000W/Kg

1/7 of

Present

Li-ion Battery

Carrier: N.R.

Material: R.

Design: R.

３

Innovative 2030~

Full-fledged

Electric

BEV

Battery Range

480Km

7 Times of

Present

700Wh/Kg

1000W/Kg

1/40 of

Present

New Principle

Battery

Carrier,

Material and

Design: All

Required

N.R.= Not Required, P.R.= Partly Required, R.= Required

REFERENCES FOR CHAPTER 5

References: United States of America

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Pi, Vol. XCV, No. 2 (Spring, 2004).

[2] UHRIG, R.E., “Using Plug-in Hybrid Vehicles to Drastically Reduce Petroleum-Based Fuel

Consumption and Emissions,” The BENT of Tau Beta Pi, Vol. XCVI, No. 2 (Spring, 2005).

[3] UHRIG, R.E., “Greenhouse Gas Emissions from Gasoline, Hybrid-Electric, and Hydrogen-

Fueled Vehicles,” Climate Change Technology Conference, Ottawa, Ontario, Canada (May 10-

12, 2006).

[4] HORI, M., “Which is Earth-Friendly? Conventional Hybrid Car or Plug-in Hybrid Car” (In

Japanese) Monthly Energy (August 2005) (Published by Fuji-Sankei Group).

[5] HORI, M., “Plug-in Hybrid Cars for the Energy Security and Global Environment, What About

the Effect?” (In Japanese) Monthly Energy (May 2006) (Published by Fuji-Sankei Group).

[6] HORI, M., “Plug-in Hybrid Electric Vehicles for Energy and Environment” (Text in Japanese

and extended summary in English), JSAE Transactions, Vol. 38, No. 2 (March 2007).

[7] GRAHAM, R., “Comparing the Benefits and Impacts of Hybrid Electric Vehicle Options,”

EPRI Report #1000349, Final Report (July 2001).

[8] GAGE, T., “Situation is Obscenely Out of Whack,” FLEETS & FUELS (November 14, 2005).

[9] SHIRASAKI, Y. and YASUDA, I., "New Concept Hydrogen Production System Based on

Membrane Reformer", 2002 Fuel Cell Seminar, Palm Springs (2002).

[10] YASUDA, I., SHIRASAKI, Y., “Development of Membrane Reformer for Highly-efficient

Hydrogen Production from Natural Gas”, 15th World Hydrogen Energy Conference, Yokohama

(2004).

[11] TASHIMO, M., et. al., “Advanced Design of Fast Reactor Membrane Reformer”, Proceedings

of OECD/NEA Second Information Exchange Meeting on Nuclear Production of Hydrogen,

Argonne USA, October 2-3, 2003, p. 267 (2003)

[12] GENERAL MOTORS, “New Step, Same Direction: No Way GM will Kill the Electric Car

says Lutz,” Automotive News (Jamie Lareau), November 7, 2006

http://www.autoweek.com/apps/pbcs.dll/article?AID=/20061107/FREE/61106014&SearchID=7

3279821382571

[13] METI Study Group on Next-Generation Vehicle Batteries, Recommendations for the Future of

Next-Generation Vehicle Batteries, Ministry of Economy, Trade and Industry (August, 2006)

(http://www.meti.go.jp/english/information/downloadfiles/PressRelease/060828VehicleBatterie

s.pdf).

[14] WANG, M. Q., GAINES, L., and CUENCA, R., “Modeling the Vehicle Cycle Impacts of

Hybrid Electric Vehicles,” Air and Waste Management Association 90

Meeting and

Exhibition, Toronto, Canada, June 8-13, 1997.

BIBLIOGRAPHY FOR CHAPTER 5

“Batteries Digest” Web Site at <http://batteriesdigest.com/id492.htm

> 2006.

Consumer Reports, “What’s New—2005 Cars, Fueling the Future,” Consumer Reports, Vol. 69,

No.10, October 2004.

DAIMLER CHRYSLER, “Mercedes Introduces Sprinter Diesel Electric Hybrid,”

<www.whnet.com/4x4/sprinter.html>, click on “Hybrid Page,” July 31, 2004.

The Economist Technology Quarterly, “Why the Future is Hybrid,” pp. 26-30, December 4, 2004.

DEPARTMENT OF ENERGY, ENERGY INFORMATION ADMINISTRATION (DOE and EPA),

“Carbon Dioxide Emissions from the Generation of Electric Power in the United States (July 2000).

http://www.eia.doe.gov/cneaf/electricity/page/co2_report/co2report.html

DEPARTMENT OF ENERGY, ENERGY INFORMATION ADMINISTRATION, Energy

Information Administration, “Petroleum Flow 2002.” Annual Energy Review at <www.eia.doe.

gov/emeulaer/diagram2.html> (2003).

DEPARTMENT OF ENERGY, ENERGY INFORMATION ADMINISTRATION, Energy

Information Administration, “Green-house Gases, Climate Change, and Energy,” at

<http://www.eia.doe.gov/oiaf/1605/ggccebro/chapter1. html

> (2005).

GOSWAMI, D. Yogi, “Hydrogen Supply Technologies: Introduction to Issues,

<www.ases.org/hydrogen_forum 03/Goswami.pdf

> (2005).

MILLER, A. and DUFFY, R.B., “Meeting the Near-Term Demand for Hydrogen using Nuclear

Energy in Competitive Power Markets,” Proceedings of GLOBAL 2000 Meeting, American Nuclear

Society, New Orleans, LA, Nov. 16-20 (2003).

STUART, S., “Nuclear-Electric Synergies: For Neat Hydrogen Production and Cleaner Fossil

Reserves Harvesting,” ANS President’s Special Session: Hydrogen Systems, ANS Meeting, Reno,

NV, Nov. 11-15, 2001.

TerraPass, “Carbon Dioxide Calculator,” <Terrapass.com/ carboncalc.html>.

CHAPTER 6

ELECTRICITY AND HEAT FOR HYDROGEN PRODUCTION