Megatrends for Energy Efficiency and Renewable Energy

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Megatrends for Energy Efficiency and Rene wable Energy By Michael Frank Hordeski

Library of Congress Cataloging-in-Publication Data Hordeski, Michael F. Megatrends for energy efficiency and renewable energy / by Michael Frank Hordeski. p. cm. Includes bibliographical references and index. ISBN-13: 978-1-4398-5354-2 (Taylor & Francis distribution : alk. paper) ISBN-10: 0-88173-632-5 (alk. paper) ISBN-10: 0-88173-633-3 (electronic) 1. Renewable energy sources--Forecasting. 2. Energy consumption-Forecasting. I. Title. TJ808.H67 2010 333.791’6--dc22

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Megatrends for energy efficiency and renewable energy / by Michael Frank Hordeski ©2011 by The Fairmont Press. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopy, recording, or any information storage and retrieval system, without permission in writing from the publisher. Published by The Fairmont Press, Inc. 700 Indian Trail Lilburn, GA 30047 tel: 770-925-9388; fax: 770-381-9865 http://www.fairmontpress.com Distributed by Taylor & Francis Ltd. 6000 Broken Sound Parkway NW, Suite 300 Boca Raton, FL 33487, USA E-mail: [email protected] Distributed by Taylor & Francis Ltd. 23-25 Blades Court Deodar Road London SW15 2NU, UK E-mail: [email protected] Printed in the United States of America 10 9 8 7 6 5 4 3 2 1

0-88173-632-5 (The Fairmont Press, Inc.) 978-1-4398-5354-2 (Taylor & Francis Ltd.) While every effort is made to provide dependable information, the publisher, authors, and editors cannot be held responsible for any errors or omissions.

Preface In the world’s existing energy system, 85% is based on coal, oil and other fossil fuels which have become a part of modern life. The demand for energy worldwide has been increasing in many countries including India and China. China has been opening a new coal-fired power plant every week. Their increasing demand now makes them a net importer of coal in spite of their vast domestic reserves. The American Association for the Advancement of Science (AAAS) estimates that underground coal mine fires contribute to carbon dioxide emissions and that as much as 3% of the total world CO2 output could be due to these fires in China where more than two billion people still cook on firewood or dried dung and 1.5 million of these may die from breathing indoor smoke. The climate crisis may be more of an energy challenge. The key to limiting climate risks and solving other problems including the end of cheap oil may involve a determined effort to conserve, harvest and store clean energy. There are many environmental, economic, and geopolitical reasons to become more resource-efficient. The business community has a major role on the current world energy stage. Building owners and managers decide how much attention and capital to allocate in efficiently equipping and operating their facilities. Manufacturers of cars and trucks must decide how they will treat any increases in fuel economy standards. In every sector of the economy, businesses make decisions each day that determine global energy use. Harnessing America’s massive coal reserves to advance our energy independence is one option under consideration. But, according to a recent report building a 100,000-barrel-a-day, coal-to-liquid could cost $12 billion while increasing U.S. auto and truck fuel efficiency by 10% could offset the need to build ten new 100,000-barrel-a-day plants. There is much evidence of corporate energy responsibility in the increased use of solar panels. But, many corporations still have millions of square feet of space with inefficient lighting, HVAC and motors. Buildings continue to be operated manually because the funds are not allocated for energy management systems. Even if global warming is not a problem, the many benefits of making the world more resource-efficient vii

are compelling. Aggressive growth in areas like India, and China and even Russia and Brazil puts pressure on energy prices. Making energy efficiency a worldwide, no-exceptions practice means a cleaner and greener global economy. Nuclear power produces few emissions but a recent estimate from Princeton indicates the world would need almost 900 new nuclear power plants in the next 45 years to reduce the expected carbon dioxide release by 10%. The need for technological advances is vital and investments in energy research could help avoid oil wars and economic hardships while lowering energy costs. Funding for alternative energy research peaked in the United States and abroad during the oil shocks of the 1970s, then dropped quickly and has never really recovered. Only Japan has sustained its investment in this type of research. Harnessing the power of the sun has always been a goal from the earliest of time. But research on solar technologies remains small in scale, though the potential has been known for years. Back in 1932 even Thomas Edison praised solar energy as a power source and hoped that we would not wait until our oil and coal run out before using it. At the California Institute of Technology, scientists are working on new types of devices for turning sunlight into electric power. Atoms of metals are being deposited on tiny rods to investigate ways that could raise the efficiency of solar panels. Solar power is widely seen as an alternative energy source that is abundant enough and could be cheap enough to eventually replace fossil fuels. Windmills are effective in certain areas and conditions, but they face problems for large-scale applications. In areas like Texas, the hottest days which cause the biggest needs in power use are the least windy. In New Haven, West Virginia, workers have drilled more than 9,000 feet under one of the country’s largest coal-fired power plants to test if the layers of rock can provide a repository for the CO2 released as the coal burns. At the headquarters of Plug Power in Latham, NY, stationary hydrogen fuel cell units are manufactured for backup power applications. At the National Renewable Energy Laboratory outside Denver, special strains of algae are being tested for hydrogen production. Under certain conditions these algae can generate hydrogen which could be an alternative for fossil fuels if it can be produced cheaply and cleanly. So viii

far, the gas has been produced in small amounts. In 5-10 years we may be making inroads on replacing petroleum and become less dependent on Middle East oil supplies. Chapter 1 is an overview of the energy mix evolution. It introduces key trends in technology and emission issues; alternative fuels such as natural gas, hydrogen gas, methanol, ethanol and fuel cell power. Chapter 2 investigates current trends in green power. Issues affecting energy generation include carbon accounting and global warming. This chapter outlines major environmental trends and concerns including Kyoto and global warming, temperature cycles, deforestation and the greenhouse effect. Building trends is the subject of Chapter 3. Energy management, high efficiency heating, district heating and cooling, sustainable buildings, green roofs and LEED standards are all growing trends. Fuel sources is the theme of Chapter 4. Subjects include hydrogen, methanol, syn gas, biofuels, fueling methods, safety and storage trends. Chapter 5 is concerned with conservation and automation trends including efficiency trends, lighting, insulation, upgrades and HVAC trends. Environmental mitigation and measures are the themes of Chapter 6. It is concerned with cap and trade theory, renewable certificates, abatement, sequestration and offsets. Chapter 7 is concerned with grid integration and transmission issues. Topics include tariffs, reliability, stability, smart/home grids and advanced grid trends. Chapter 8 discusses the renewable power and energy future which includes growing trends in wave and thermal marine energy as well a high potential in geothermal sources. Many thanks to Dee who did much to check over the chapters and get this book into its final form.

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Table of Contents Chapter 1

How the Energy Mix is Changing ..........................................1

Chapter 2

Green Power Trends ...............................................................41

Chapter 3

Building Trends .......................................................................81

Chapter 4

Fuel Sources ...........................................................................121

Chapter 5

Conservation and Automation Trends...............................159

Chapter 6

Environmental Mitigation ...................................................195

Chapter 7

Grid Integration and Transmission ....................................227

Chapter 8

The Future for Renewables ..................................................267

Index ...............................................................................................................303

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Chapter 1

How the Energy Mix is Changing Keywords:

Energy and the Environment Oil Supplies Oil Shale 2009 Energy Bill Renewable Growth Alternative Paths Concentrating Solar Solar Growth Fuels Ethanol Biomass

Hydrogen Fuel Switching Hydrogen Production Fuel Cells Fuel Cell Applications Hydrogen Air Transport Nuclear Energy Energy and Wealth The Cost of Energy A Carbon Age

The impact of environmental regulations is changing the way on how

we obtain and utilize energy in the future. The pressure is on the growth of cleaner and sustainable energy practices to replace older practices and sources. This can introduce new problems and costs associated as the growth of these policies and energy options results in the transformation of our energy structure. As energy becomes more critical, the impact of environmental controls and regulations presents very real questions on how we will obtain and utilize energy in the future. Energy taxes are being proposed to limit greenhouse gases and the growth of cleaner and sustainable energy practices is under more pressure to replace older energy sources. This injects new problems and costs associated with the growth of these policies and energy options and their transformation of our energy structure. The use of energy is being affected by environmental issues but the fear of global warming has resulted in a major conservation push. Concerns about global warming and potential changes have produced a number of proposed programs for greenhouse gas reduction. Many of these 1

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Megatrends for Energy Efficiency and Renewable Energy

involve limiting emissions. Government controls on industrial and agricultural emissions producing greenhouse gases may include additional regulations to ensure energy efficiency, usage with strict limits and curbs on industrial and agricultural growth. Strict economists push for little or no action now, assuming that resources can be used to maximize economic conditions in the future and solutions will develop. Environmentalists favor a redistribution of resources to modify costs and incomes. The development of nonfossil energy sources with improved efficiency in all energy sectors should become a high-priority strategic investment. Potential tax incentives may be used as a tool to reduce fossil fuel emissions. ENERGY AND THE ENVIRONMENT The spread of economic development has pushed the use of automobiles to all parts of the modern world. The bulk of industrialized nations including Japan, Britain, Germany, France and others have seen great increases in energy use. At the end of the 20th century, the U.S. used more energy per capita than any other nation, twice the rate of Sweden and almost three times that of Japan or Italy. By 1988, the United States, with only 5% of the earth’s population, consumed 25% of all the world’s oil and released about a fourth of the world’s atmospheric carbon. A major surge in U.S. energy consumption occurred between 1930 and 1970, climbing by 350% as more oil and natural gas was consumed for industry, agriculture, transportation and housing. The demand for energy soared as the nation’s economy grew and consumers became more affluent. By 1950, Americans drove three-quarters of all the world’s automobiles and lived in larger energy consuming homes with relatively inefficient heating and cooling systems. The use of appliances also increased which boosted power needs. Energy consumption slowed in the 1970s and 1980s, as manufacturers designed more efficient appliances. The growth of the interstates encouraged more single-family homes which had to be reached by private cars. Since the mid-1950s, cities like Phoenix, Arizona, have grown from 15-20 to over 200-400 square miles. From 1965 to 1990, the greater New York City area grew by 61% from 1965

How the Energy Mix is Changing

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to 1990, while adding only 5% to its population. From 1970 to 1990, the greater Chicago area grew by more than 46% in land area, but its population increased by only 4%. From 1970 to 1999 vehicle-miles of travel more than doubled while average miles per vehicle increased a little more than 20%. Developing nonfossil energy sources and improving efficiency in all energy sectors should be viewed as part of a high-priority strategic investment. The mechanisms to accomplish this include research and development on more cost effective renewable technologies, safer, modular nuclear plants and possible tax incentives to reduce fossil fuel emissions. Greenhouse gas buildup is a global problem and is connected to global economic development. It depends on population, resources, environment and economics. Developed countries are the major producers of carbon dioxide, but global strategies for preventing greenhouse gas buildup require international cooperation between rich and poor nations. The increased burden of debt is a major hurdle in the global development of the Third World. It is difficult for countries to invest in expensive energy-efficient equipment when they can barely pay back the interest on loans from other countries. A debt/nature swap has been proposed where underdeveloped countries would provide tracts of forest to developed countries in exchange for forgiving part of their debt. Another approach is to have the World Bank place environmental conditions on its loans. Population growth rates are another point of dissension between developed and developing countries. Total emission is the per capita emission rate times the total population size. The population growth which is occurring predominantly in the Third World will become an important factor. For the poor of the world, more energy and more energy services can mean an improved quality of life. Energy use can allow services that improve health care, education and nutrition in less-developed nations. As population or affluence grows, so does pollution. Ultimately the world population should stabilize and future pollution levels should be lower for any per capita standard of consumption. A stable population is a critical part of a sustainable future. If the buildup of carbon dioxide and other gases is not considered as part of global development, it is unlikely that greater buildup will be prevented, except by great advances in alternative fuel systems and programs to increase energy efficiency.

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The world produces over 7 billion metric tons of carbon every year in the form of carbon dioxide. The U.S. produces about 1.7 billion tons. Proposed legislation in 1988 called for a 50% reduction in carbon dioxide in the United States early in the next century. Our residential and commercial energy use is about 35% of the total energy used. Industrial energy use is about 38% and transportation is about 27%. Almost 40% of our energy is derived from oil. For the electric utilities about 21% is produced by coal, with about 8% from nuclear, about 23% from natural gas and the rest from hydro and other renewables. This accounts for most of the energy use in the United States. Since coal is the least efficient fuel, it produces the greatest amount of carbon dioxide per unit energy. Any increase in the use of coal would substantially increase carbon dioxide levels. Moving to more natural gas, nuclear, solar, hydro or wind power would decrease these levels. The Western Governor’s Association in 2004 approved a resolution to increase renewable energy production, which would require 30,000 megawatts to be produced by 2015 and encourage energy efficiency gains of 20 percent by 2020. THE 2009 CLIMATE AND ENERGY BILL The House and Senate moved to address climate and energy in 2009. The House of Representatives narrowly passed the 1,000-plus page comprehensive climate and energy bill, the American Clean Energy and Security Act (ACES), while the Senate Energy and Natural Resources Committee also pushed out an Energy Bill intended to be part of the Senate Climate package. The Senate Energy and Natural Resources Committee approved energy measures that call for 15 percent of the country’s power to come from renewable sources by 2021. The bill has significant solar provisions includes regional transmission grid planning. The Business Council for Sustainable Energy commended the U.S. House of Representatives for its vote on ACES. But, others maintain the bill is weak and will not require any additional renewables beyond what states already are doing. An analysis by the National Renewable Energy Laboratory said the national mandates would in some cases result in less renewable energy being used by 2030 than what is anticipated under existing state requirements and incentives from the economic recovery pro-


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gram. Complaints about the bill centered on its complexity particularly the offset provisions, which have been viewed as wanting from experiences in Europe. The free allowances have the effect of generating minimal useful action in the near term and while shifting a large and sudden burden to future generations. There may also be an excess of safety valves with no simple cap such as a $20 per ton of CO2 equivalent on what emitters have to pay. The Senate Committee on Energy & Natural Resources included a Renewable Electricity Standard that calls for 3% of U.S. electrical generation to come from non-hydro renewables by 2011-2013. But, according to the Electric Power Monthly report issued by the Energy Information Administration, non-hydro renewables such as wind, solar, geothermal and biomass already accounted for almost 4% of net U.S. electrical generation in 2009. Renewable Growth According to a report from BCC Research, the total global market for advanced materials and devices for renewable energy systems was worth almost $2.4 billion by the end of 2006. At a compound annual growth rate (CAGR) of 25.8%, the market would be worth almost $7.5 billion by 2011. Worldwide production of electricity from wind energy has more than tripled since 2000 and the use of solar cells for electricity has increased more than six times in the same period, making solar one of the fastest growing industries in the world. This activity has been driving down costs and accelerating technological advances. These include new material and devices that increase the cost efficiency of renewable energy, helping to expand the market further. Solar photovoltaic devices were worth $1.2 billion in 2006 and have highest share of the market at 55.1% of the total global market. By 2011 they will be worth more than $4.9 billion, a CAGR of 28.1% and their share of the market will increase to 56.3%. Ocean energy had the highest growth rate through the forecast period, reaching $360 million in 2011 with a CAGR of 66.5%. The crystalline silicon used in solar PV arrays has the largest consumption of any type of advanced material, followed at a distance by thin films. Composites had the third-largest consumption, but nanomaterials will surpass composites by 2011 according to the report.

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ALTERNATIVE PATHS A Department of Energy study compared alternative paths for future U.S. energy use: business-as-usual and energy-efficient. Both projections suggested a substantial rise in U.S. production of CO2 and the consumption of fossil fuels for the next 20 years. The study predicted an increase in energy between 1985 and 2010 of about 30%. The projected oil and gas increase remained relatively constant over this period, but coal consumption rose by more than 100%. CO2 emissions rose from 1.25 billion metric tons per year to about 1.73 billion metric tons in 2010. This represents a 38% increase in CO2. The major cause for the 38% increase in CO2 was a more than doubling of the coal use in electric utilities and a near doubling of coal use in industrial use. The energy efficiency path still increased CO2 production to 1.5 billion metric tons per year. The high-efficiency case does use less coal. Other energy studies predict a decline in energy-growth rates and a decline instead of an increase in CO2 emissions. One DOE forecast sees U.S. energy production with a free economic viability and strong technological growth. Other forecasts predict an energy future tied to broad societal goals of economic efficiency and equity with policy changes used to reach objectives. Market interventions that could reduce the energy supply include petroleum product taxes, oil import fees and carbon taxes for greenhouse problems. A report from the McKinsey Global Institute (MGI) stated that energy efficiency improvements from current technology could reduce the growth in global energy consumption by more than half over the next 15 years. The report recommends solutions such as compact fluorescent light bulbs (CFLs), better-insulated buildings, reduced standby power and higher appliance efficiency standards. It reported that consumers do not take full advantage of money-saving opportunities which are extensive. The report recommends that utilities be compensated more for their conservation programs. A study from an interdisciplinary MIT panel indicates that carbon capture/sequestration is the critical technology that would allow coal to meet the world’s energy needs. The study said that it is not clear which technology, integrated gasification combined cycle or pulverized coal would allow for the easiest carbon capture, since much engineering work remains to be done and that it was critical that the government not pick a technology.


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The report urged the U.S. to play a leadership role in demonstrating carbon capture and sequestration at commercial scale coal plants, so that public confidence in practical carbon mitigation control options will grow. Another analysis by the Electric Power Research Institute (EPRI) focused on technologies that have the potential to achieve significant carbon dioxide emission reductions from the U.S. electric power sector in the next 25 to 30 years. Aggressive development, demonstration, and deployment of a number of technologies is needed, including increased end-use energy efficiency, cost-effective large-scale renewable energy resources, continued operation of existing nuclear plants, significant new generation from advanced light-water reactors by 2020, improved efficiency at new coalbased generating plants, carbon capture and storage at new coal generating plants by 2020, accelerating the use of plug-in hybrid vehicles and expanded deployment of distributed energy including solar photovoltaic. The analysis found that it is feasible for the U.S. electric power sector to slow and then decrease carbon emissions with a combination of technologies. In generation and distribution, newer technologies will be pushed harder to replace older energy sources while innovations in industry and building design will be under more pressure to transform energy use. The result is an upheaval in the energy mix including the key energy options that are available. CONCENTRATING SOLAR In the deserts of Spain one of the world’s latest concentrating solar power stations has been built. Based on Fresnel technology the plant is set to establish new standards for supplying power. With over 3000 hours of sunshine per year, Almeria in Southern Spain has seen almost every facet in the development of solar power. Concentrating solar power (CSP) generation is gaining ground for its potential to produce large volumes of power and provide an alternative to fossil fuels. Three methods of solar thermal power generation have the potential to generate electricity within the 10-kW to 1000-MW range. These are dish/engine, solar tower, and parabolic trough technologies. A number of parabolic trough fields are commercially used today,

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mostly in the United States and southern Europe. ACCIONA’s Nevada Solar One is a 64-MW CSP in Boulder City, Nevada. It was the first of its kind to be built in 17 years and the third largest in the world. Nevada Solar One uses 760 parabolic collectors and over 182,000 mirrors. Until recently almost all solar power plants used parabolic trough mirrors to capture the sun’s radiation. The resulting energy is used to heat thermal oil, which is pumped through an absorber pipe. The heated oil then passes through a heat exchanger that in turn creates steam to drive a turbine. The key advantage the Fresnel system has over parabolic technology lies in its simplicity. Parabolic mirrors are produced using standard methods but the components are still highly precision optical elements. The curved shape of the parabolic mirrors makes them about 15% more efficient than the Fresnel reflectors. Fresnel technology uses flat reflectors simulating a curved mirror by varying the adjustable angle of the individual rows of mirrors in relation to the absorber pipe. The reflectors are standard glass mirrors. The Plataforma Solar installation is comprised of a primary mirror field, an absorber tube and a secondary mirror. The primary mirror field has 25 rows of flat mirrors on the ground, each 100 meters long by 60-cm wide, which reflect the sun’s rays onto a 100 meter-long absorber tube hanging several meters above the primary field. Above the absorber tube is a secondary mirror, which concentrates any remaining sunlight onto the linear absorber tube. All the mirrors in the primary field are controlled by electric motors that track the position of the sun, focusing sunlight onto the absorber tube in the most efficient manner. The smaller size of the individual mirrors also makes them less sensitive to wind than parabolic trough systems. A key economic benefit is the ability to work with conventional steam turbines and use the generators of existing fossil-fuelled power plants or to operate them as hybrid stations. Solar power can be an essential element in the world’s future power supply. Over the long-term, solar energy can be capable of replacing power generation based on oil and natural gas through an adaptation of existing technologies. This solar technology is critical to developing electric markets which might struggle to invest in fossil fuel plants and then have to update to solar energy systems in the near future. As an alternative to fossil fuels, solar energy plants are increasingly being viewed as important options for future global energy needs. By 2050 it may be possible to achieve half


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of the world’s energy from renewable sources using the technologies already in existence. Solar heat can be stored in molten salts, ceramics, concrete or phasechanging salt mixtures. In Spain the 50-MW Andasol plants are capable of about eight hours of storage increasing the annual availability by about 1000-2500 hours. Molten salts are kept in cool tanks at 290 degrees C and hot tanks at 390°C with about 29,000 tons in each tank. The cold liquid salts are passed through a heat exchanger with the heated oil from the solar concentrated and stored in the hot tank. The process is reversed to extract the heat for steam generation. At the PS10 plant in Spain, steam is stored in pressure vessels to provide one hour of buffer storage for peak power periods. This is known as Ruth’s storage. Concrete storage is done at 400 to 500 degrees C with a modular capacity of 500 to 1000-MWh. The cost is about $40/kWh with a target of less than $30/kWh. The storage modules used have capacities of 300 to 400-kWh. Storage with phase-changing mixtures uses the melting and freezing points of salts, usually sodium or potassium nitrates. The hot heat transfer fluid is sent through a manifold which transfers the heat to the storage material. This method provides volumetric density and a low cost of storage material but there remain some development challenges for commercial applications. SOLAR GROWTH Solar photovoltaic (PV) use is growing across Europe. Spain was Europe’s fastest growing PV market installing about 800-MW in 2008 and estimated to grow to 5.6-GW by 2012. Long-term and relatively stable incentives pushed the total installed grid-connected PV capacity in Germany and Spain 1,440-MW in 2007, accounting for 92% of the 1,562-MW installed in Europe. In the U.S. solar power can reach 10 percent of total power generation by 2025. It is estimated that this will require $450 to $550 billion in capital costs, which is an average of $30 to $37 billion per year. Currently, the U.S. gets only about 0.1 percent of its energy from solar. This jumped from 600-MW in 2003 to 8,000-MW in 2008. About half of this was concentrated solar power.

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A global shortage in silicon pushed prices to over $300/kg in 2008. In the middle of 2009 this price was down to $150/kg which equates about $2/W making PV much more competitive. The high prices in 2008 forced many developers to switch to less efficient, but less expensive, thin film technology. FUELS When oil prices increase, the interest in alternatives increases. Alternate energy becomes more popular but major questions remain to be answered on which fuel or fuels will emerge and to what extent alternative sources will replace gasoline as the main product of crude oil. Dramatic progress in renewable energy technology will be needed if the United States wishes produce 25 percent of its electricity and motor vehicle fuel from renewable sources by 2025 without significantly increasing consumer costs according to a study by the RAND Corporation. The study found that biomass resources and wind power have the greatest potential to contribute to reaching the 25 percent goal. Currently, renewable energy provides about 9.5 percent of U.S. electric power with most of this coming from hydroelectric power. Renewables provide about 1.5 percent of motor vehicle fuel needs. Expanding the use of renewable fuels can lower the demand for crude oil and reduce carbon dioxide emissions. A combination of available alternative fuels should evolve with the most likely choices affected by a number of technical, political and market factors. In order to allow a wider application of alternative fuels, a number of obstacles have to be overcome. These include economic, technological, and infrastructural issues. In the past, gasoline has been plentiful and has had a significant price advantage compared to other fuels. This could change quickly and alternative fuels would need to become more commonplace. However, this will require a major investment in the use of renewable energy technology. Key findings of the study include: • Renewable energy technology has to improve at a significant pace to make any substantial impact on cost issues. • Major increases in the use of wind power are possible, but additional technical advances are needed for the use of less-productive locations.


•

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Government policy in the pricing of renewable motor fuels will greatly affect fuel demand and energy costs. Subsidizing moreexpensive fuels at the pump shifts the expense to the federal budget.

Next generation wind turbines might be able to generate 25% of all U.S. electricity in 5 years, since abundant energy exists, but economic and siting issues impede progress. Solid-state devices for PV technology are projected to provide improvements in performance while reducing costs. PV advances are coming from nanotechnology, new PV materials (organic and inorganic) and manufacturing. A recent MIT study indicates that U.S. geothermal potential at 30,000 times our energy needs, with exploitable heat differentials under every square foot of the Earth’s surface. Another area of technology with potential is biodiesel from algae, where research is growing at a rate of 15-16% per year. OIL SUPPLIES A National Energy Policy Report that was released in 2001 predicted that U.S. requirements for burning 20 million barrels of oil each day will continue to increase and that increases in U.S. dependence on imported supplies of oil will reach two-thirds by 2020. Also, the Persian Gulf countries will be the main source for this amount of oil and the U.S. trade imbalance will continue to grow. U.S. dependence upon imported oil could grow faster depending on oil availability. The petroleum reserves in the U.S. could be depleted more rapidly but U.S. reserves, which were once about as large as Saudi Arabia’s, may be depleted to the point where it may be less than 3% of the world’s remaining oil reserves, which is also essential for the production of food and the manufacture of many products. The U.S. uses oil at a rate that amounts to more than 25% of the world’s production, but both U.S. and world reserves have been growing as improved recovery techniques are applied to older fields. Iraq has oil reserves of about 110 billion barrels which is second only to Saudi Arabia. Russia has about 50 billion barrels and the Caspian states another 15 billion. Iraq is one oil producer that could substantially increase oil production to meet the growing world demand in highly populated countries.

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In the U.S. oil production peaked in 1970. The peak of world oil production has been predicted to occur from 2005 to 2036. For 100 years Americans have enjoyed relatively inexpensive gas, diesel fuel and petroleum products. As recently as the 1990s, gas prices were below one dollar per gallon. Now, prices seem to be rising most of the time along with the cost of a barrel of oil. When prices do drop, they never seem to return to the previous low price. As prices rise and fall, the trend is still upwards. There are even rumors that oil production in Saudi Arabia has already peaked and output may soon decline as worldwide demand increases. Many believe in a simple solution: increase exploration and drilling in other areas. There may be as much as 270 billion barrels of oil in the Caspian Sea region, a part of the former Soviet Union. To use this oil we would have to deal with countries in an unstable area. The U.S. would also compete against other nations of the world, all of which need oil for continued growth. Beyond these problems is a rapidly growing world population and an area with contested borders and conflicting political and religious ideologies. In 1956 a well-known geophysicist, M. King Hubbert predicted that U.S. oil production would peak in 1970 as it did. In 1969 Hubbert predicted that world oil production would peak in 2000. Some suggest that the peak is occurring now. Official USGS studies place the peak in 2036. No new U.S. oil refineries have been built since 1970 for a variety of reasons and giant oil tankers are being retired without replacement. The oil companies have not been investing in refineries because of environmental regulations and they have been able to increase refinery capacities, but that is nearing its end. The environmental restrictions of the EPA have limited the construction of new refineries. These restrictions are now being relaxed and the construction of new refineries may begin. The present refining and delivery system for gasoline is stretched thin. Sudden events, such as Hurricane Katrina, can result in shortages causing price jumps around the country. Hubbert’s prediction is frequently challenged. The world seems so vast that there must be more oil, but oil is a finite resource that will run out some time. If we prepare for other forms of energy, that transition will be smoother. If we are unprepared there may be armed conflicts over oil resources. The remaining oil supplies should be used wisely and alternative sources of energy need to be developed.


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U.S. Petroleum Reserves The U.S. Strategic Petroleum Reserve (SPR) is the largest stockpile of government-owned emergency crude oil in the world. Established after the 1973-74 oil embargo, the SPR provides the President with a response option if a disruption in commercial oil supplies endanger the U.S. economy. It also allows the United States to meet part of its International Energy Agency obligation to maintain emergency oil stocks, and it provides a national defense fuel reserve. The Energy Policy Act of 2005 directs the Secretary of Energy to fill the SPR to its authorized one billion barrel capacity. Since the early 1900s, the Naval Petroleum Reserves program has controlled oil bearing lands owned by the U.S. government. The program was intended to provide U.S. naval vessels with an assured source of fuel. The Naval Petroleum Reserves operated three major oil fields located in California and Wyoming. The government also held oil shale lands in Utah and Colorado that were opened to development during the 1980s as an alternate source of fossil fuels. In 1996 Congress authorized the divestment of several Naval Petroleum and Oil Shale Reserves properties. For most of the 20th century, the Naval Petroleum and Oil Shale Reserves served as a contingency source of fuel for the Nation’s military. That changed in 1998 when Naval Petroleum Reserve No. 1, known as Elk Hills, was privatized, the first in a series of major changes that leaves only two of the original six federal properties in the program. The reserves were mostly undeveloped until the 1970s, when the country began looking for ways to enhance domestic oil supplies. In 1976, Congress passed the Naval Petroleum Reserves Production Act authorizing commercial development of the reserves. Crude oil and natural gas from the reserves were sold by DOE at market rates. One of the largest of the federal properties, the Elk Hills field in California, opened for production in 1976 and became the highest production oil and natural gas field in the lower 48 states at one point. In 1992, the field produced its one billionth barrel of oil. It was only the thirteenth field in U.S. history to reach this number and while managed by the DOE, Elk Hills generated over $17 billion in profits for the U.S. Treasury. In 1996, Congress decided that the properties no longer served the national defense purposes as envisioned in the early 1900s, and authorized steps towards divestment or privatization. In 1998, the Department of Energy and Occidental Petroleum Cor-

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poration concluded the largest divestiture of federal property in the history of the U.S. government. In 1998 the Department of Energy sold Elk Hills to Occidental Petroleum for $3.65 billion. The Department of Energy also transferred two of the Naval Oil Shale Reserves in Colorado to the Department of the Interior’s Bureau of Land Management. Like other federally owned lands, these properties are offered for commercial mineral leasing, primarily for natural gas production and future petroleum exploration. In 2001, the DOE returned the undeveloped Naval Oil Shale Reserve #2 in Utah to the Northern Ute Indian Tribe in the largest transfer of federal property to Native Americans in the last century. OIL SHALE It is generally agreed that worldwide petroleum supply will eventually reach its productive limit, peak, and begin a long term decline. One of the alternatives is the Nation’s untapped oil shale as a strategically located, long-term source of reliable, affordable, and secure oil. The extent of U.S. oil shale resources, which amounts to more than 2 trillion barrels, has been known for a century. In 1912, the President established the Naval Petroleum and Oil Shale Reserves. There have been several commercial attempts to produce oil from oil shale, but these have failed because of the lower cost of petroleum at the time. With future declines in petroleum production, market forces are expected to improve the economic viability of oil shale. Oil Shale Reserves In Rio Blanco County near Rifle, Colorado, is the town of Parachute and the shuttered oil shale refineries from the 1970s. This area contains enough recoverable oil and gas to displace Middle East imports. The energy reserves of the Piceance Basin in Blanco County contain massive petroleum reserves of oil shale. Most of the nation’s oil shale reserves rest under the control of the U.S. government. In 1910, Congress passed the Pickett Act, which authorized President Taft to set aside oil-bearing land in California and Wyoming as potential sources of fuel for the U.S. Navy. From 1910 to 1925 the Navy developed the Naval Petroleum and Oil Shale Reserves Program. The program became official in 1927 and President Roosevelt expanded the program in 1942. The


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shale reserves are still 1,000 feet underground in the Colorado desert. Extracting oil from shale is expensive and the reserves remain almost completely undeveloped. But an emerging new technology may unlock the potential of oil shale. Advances in thermally conductive in-situ conversion may allow shale-derived oil to be competitive with crude oil at prices below $40 per barrel. U.S. oil shale reserves are estimated at 1.5 trillion barrels of oil which is more than five times the reserves of Saudi Arabia. Presidents Gerald Ford and Jimmy Carter encouraged and funded the development of the West’s shale deposits. A shale-boom took off but not much oil flowed. The government spent billions along with Exxon Mobil. Boomtowns shot up in Rifle, Parachute, Rangely, and Meeker, Colorado. But in 1982, Exxon shut down its $5 billion Colony Oil Shale project and the refineries closed. The earliest attempts to extract the oil used a process known as retorting. This requires mining the shale, hauling it to a processing facility that crushes the rock into small chunks to extract a petroleum substance called kerogen. The kerogen goes through the process of hydrogenation which requires large amounts of water and is then refined into gasoline or jet fuel. Once the heating process has desiccated the shale, the desiccated shale contains low levels of heavy metal residue and other toxics which can leach out and contaminate water supplies. Royal Dutch Shell demonstrated in the Mahogany Ridge project where it produced 1,400 barrels of oil from shale in the ground, without mining the shale. Shell used in-situ mining, which heats the shale while it is in the ground and the oil leaches from the rock. In a few months this In-situ Conversion Process (ICP) produced the 1,400 barrels of light oil along with associated gas from a very small test plot. Most of the petroleum products we use today are derived from conventional oil fields where the oil and gas have naturally matured by being subjected to heat and pressure over very long periods of time. The In-situ Conversion Process accelerates this natural process by millions of years. This is done by slow sub-surface heating of the petroleum source rock containing kerogen, which is the precursor to oil and gas. The process takes place with the drilling of holes into the rock and inserting electric resistance heaters into these heater holes. The subsurface is kept at 650700F for a 3- to 4-year period. A very dense oil and gas is expelled from the kerogen which then changes into lighter compounds with the changing of phases into more

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hydrogen rich compounds from liquid to gas. In the gaseous phase, these fractions now move in the subsurface through fractures to conventional wells where they are brought to the surface. The process is very energy-intensive, for each unit of energy used to generate power to provide the heat for the process, on a life cycle basis, about 3.5 units of energy are produced. The energy efficiency is similar to heavy oil fields that use steam injection to get more oil out of the well. The produced hydrocarbon is very different from traditional crude oils. It is much lighter and contains almost no heavy ends. In order to keep any products of the process from escaping into groundwater flows Shell uses ice wall technology to isolate the active area. The freezing of groundwater has been used for many years to isolate areas being tunneled and to reduce natural water flows into mines. Freeze walls were used in Boston’s Big Dig project and at the Strategic Petroleum reserve in Weeks Island, LA. Shell could harvest up to a million barrels per acre, or a billion barrels per square mile, on an area covering over a thousand square miles. One issue is the size and depth of the freeze-wall for each pod or cell. The heaters are at a depth of 2,000 feet and they may not be recoverable. Shell estimates the process is economic at a crude price of $30. The Bureau of Land Management has applications by eight companies for a pilot program to develop Colorado’s shale reserves. These companies include Natural Soda, EGL Resources, Kennecott Exploration, Phoenix Wyoming, Chevron Shale Oil, Exxon Mobil and Shell Frontier Oil and Gas. Commercializing the vast oil shale resources could greatly add to the country’s energy resources. Shale oil could have an effect similar to the 175 billion barrels of oil from Alberta tar sands to Canada’s oil reserves. As a result of the commercial effort, oil from tar sand production now exceeds one million barrels per day. Oil shale in the United States is as rich as tar sand and could become a vital component in America’s future energy security. ETHANOL To satisfy domestic demand for vehicle fuel, control its dependence on foreign sources of oil and attempt to moderate fuel costs, China has embarked on a robust effort to ramp up fuel ethanol development.


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Beginning in 2002, China experienced a spurt of grain-based ethanol refinery development. At that time, with the price of oil rising and China experiencing bumper grain yields, Chinese decision-makers encouraged the development of grain-based ethanol as a substitute for oil. By 2006, the government recognized that the use of grains for ethanol production was putting a strain on food supplies and causing troubling increases in food prices. In 2006, China’s ethanol production was about 3.5 million tons, of which fuel ethanol output was 1.3 million tons, the third largest in the world. Consequently, the Chinese imposed a moratorium on further development of ethanol plants in December of 2006. Instead of corn based ethanol, cellulosic ethanol is preferred, and biodiesel can be made from waste products. By 2006, the U.S. had 77 ethanol plants producing more than 3 billion gallons of ethanol per year. Canada produced an additional 60 million gallons. Corn was the feedstock in 62 of the 77 U.S. plants. Other feedstocks included seed corn, corn and barley, corn and beverage waste, brewery waste, cheese whey, corn and milo, corn and wheat starch, potato waste and various sugars. The U.S. had 11 additional plants under construction and 55 proposed. In the oil industry, biofuels interest has been growing. BP, Royal Dutch Shell and others view these fuels as a possible future replacement for gasoline and are spending millions on research and product development. Along with Chevron and ConocoPhillips, they are developing alternatives such as solar, wind, geothermal and hydrogen as well as biofuels. Oil and natural gas are their primary products, but many are investing in wind, geothermal and biofuel. These investments are a small percent of their total business, but in terms of alternative energy spending, they are significant. Between 2002 and 2006, Chevron spent about $2 billion on alternative and renewable energy technologies, including geothermal, hydrogen, biofuel, advanced batteries and energy efficiency improvements. By the end of 2009, this increased to $4.5 billion on alternative energy. Chevron has invested in Galveston Bay Biodiesel LP, a Texas firm, building a large biodiesel plant that will use soybeans and other renewable feedstock. Chevron has also partnered with the Weyerhaeuser Company in the production of biofuel from wood waste and funded research at the Colorado Center for Biorefining and Biofuels, Georgia Institute of Technology, University of California and Texas A&M, directed at developing cellulosic and hydrogen transportation fuels.

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BP has investments in an ethanol plant with DuPont and Associated British Foods. It is also investing in cellulosic ethanol research and developing jatropha as a biodiesel feedstock. BP and DuPont are planning a biobutanol demonstration plant and BP plans to eventually convert its ethanol plant to biobutanol production. BP has a $400 million investment with Associated British Foods and DuPont to build a bioethanol plant in the U.K. that may be converted to biobutanol. It has spent $500 million over 10 years at the Energy Biosciences Institute in California to research future biofuels and $9.4 million over 10 years to fund the Energy and Resources Institute (TERI) in India to study the production of biodiesel from Jatropha curcas. It also has a $160 million joint venture with D1 Oils to develop the planting of Jatropha curcas. Royal Dutch Shell has invested in cellulosic ethanol company Iogan and Germany’s Choren Industries, which is building a demonstration bio-mass-to-liquids plant using wood feedstock. Royal Dutch Shell has also partnered with Codexis in exploring biomass energy production. Shell has spent about $1 billion on renewable fuels since 2000. Shell has invested largely in next generation cellulosic biofuel which is a longterm commitment. ConocoPhillips will see a more immediate payoff in its agreement with Tyson Foods to process animal fats into renewable diesel. The company already has one renewable diesel plant in operation and another going online. Conoco-Phillips also produces renewable diesel from soybean oil at an Irish refinery and plans similar operations at its Borger, Texas, refinery. It is providing a $100 million upgrade at the refinery to process animal fats from Tyson Foods. Conoco-Phillips also funds research at the Colorado Center for Biorefining and Biofuels and gave Iowa State University $22.5 million over eight years for research on producing renewable fuels from biomass. ConocoPhillips is also studying the use of algae as a renewable diesel feedstock and is a founding member of the Colorado Center for Biorefining and Biofuels in Boulder. This research group is involved with algae, cellulosic and other biofuels. Other group members include Chevron, Dow Chemical, Shell Global Solutions, GreenFuel Technologies, Range Fuels, Solix Biofuels and Blue Sun Biodiesel. ExxonMobil has given $100 million to the Stanford University Global Climate and Energy Project, where research projects are involved with hydrogen power, advanced combustion, solar energy, biomass, advanced materials, catalysts and CO2 storage CO2 capture and separation.


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BIOMASS FUELS One fuel alternative involves the more widespread use of biomass produced fuels. More efficient biomass conversion techniques would help make biofuels more cost-competitive. Land availability and crop selection are major issues in biomass fuel usage. Biomass alternatives can be expected to grow to a significantly larger scale for providing fuel. Land availability may not be a major problem, but land use issues need to be coordinated. The long-term production of biofuels in substantial quantities will require a number of changes. Grain surpluses will not provide sufficient feedstocks for the fuel quantities needed. Producers will need to switch to short-rotation woody plants and herbaceous grasses, these feedstocks can sustain biofuel production in long-term, substantial quantities. The increased use of municipal solid waste (MSW) as a feedstock for renewable fuels is also likely to grow. In spite of significant problems, many are optimistic about the role of biomass for alternative fuels in the future. The U.S. Department of Energy believes that biofuels from nonfood crops and MSW could potentially cut U.S. oil imports by 15 to 20%. Ethanol industry members believe that the capacity for producing that fuel alone could be doubled in a few years and tripled in five years. The U.S. has seen legislation on cleaner-burning gasoline substitutes, gasoline enhancers and more efficient automobiles. This includes the 1988 Alternative Motor Fuels Act (AMFA) and the 1990 amendments to the Clean Air Act (of 1970). The AMFA had demonstration programs to promote the use of alternative fuels and alternative-fuel vehicles. The act also offered credits to automakers for producing alternative-fuel vehicles and incentives to encourage federal agencies to use these vehicles. The 1990 amendments to the Clean Air Act covered a range of pollution issues. New cars sold from 1994 on were required to emit about 30% less hydrocarbons and 60% less nitrogen-oxide pollutants from the tailpipe than earlier cars. New cars were also to have diagnostic capabilities for alerting the driver to malfunctioning emission-control equipment. In October 1993 oil refiners were required to reduce the amount of sulfur in diesel fuel. Starting in the winter of 1992/1993, oxygen was added to reduce carbon monoxide emissions to all gasoline sold during winter months in any city with carbon monoxide problems. In 1996 auto companies were to sell 150,000 cars in California that had emission levels of

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one-half compared with the other new cars. This was increased to 300,000 a year in 1999 and in 2001 the emission levels were reduced by half again. Starting in 1998 a percentage of new vehicles purchased for centrally fueled fleets in 22 polluted cities had to meet tailpipe standards that were about one-third of those for passenger cars. If alternative fuels are to be more widely used, changes must take place both in fuel infrastructure, storage and engine technology. Infrastructural changes will improve the availability of alternative fuels. This may be done by the modification of existing filling stations and by establishing a distribution system that is as efficient as the current gasoline system. FUEL SWITCHING Technological changes in the manufacture of power sources are required if they are to run on alternative fuels. Flexible fuel vehicles (FFVs), which are also known as variable fuel vehicles, (VFVs) are designed to use several fuels. Most of the major automobile manufacturers have developed FFV prototypes and many of these use ethanol or methanol as well as gasoline. More flexible-fuel vehicles are available as manufacturers move away from single-fuels to several fuels. This is also true in many power plants today. A dual-fuel boiler for a turbine generator or an engine to drive a generator might operate on natural gas, fuel oil, gasoline or an alternative fuel. Typically, boilers or engines will switch between a liquid or gaseous fuel. Cars, trucks, and buses that use both gasoline and compressed natural gas have been in use in northern Italy. Flexible-fuel engines are able to use a variable mixture of two or more different fuels, as long as they are alike physically, in usually liquid form. Vehicles with flexible-fuel engines are not in widespread use. There are about 15,000 M85 methanol vehicles in operation in the U.S. While methanol vehicles can provide greater power and acceleration but they suffer from cold starting difficulties. Cold starting problems can occur with these fuels in their pure form, but the addition of a small percentage of gasoline eliminates this problem. Both methanol and ethanol have a lower energy density than that of gasoline and thus more alcohol fuel is needed to provide the same energy.


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The costs for near alcohol automobiles will be very close to the cost of a gasoline automobile. FFVs are expected to cost slightly more. The EPA estimates that with the necessary adjustments, the savings and costs will balance out. The increased costs necessary for fuel tank adjustments and to compensate for cold-start problems could be balanced out by the smaller, lighter engines that these cars can have because of their increased efficiency. Carbon Exchange When fuels are derived from biomass, the net increase in carbon dioxide emitted into the atmosphere is usually considered to be neutral or even negative since the plants used to produce the alcohol fuel have reabsorbed the same or more carbon than is emitted from burning the fuel. The net effect may not be as favorable when the carbon dioxide emitted by equipment for the harvesting of the biomass feedstocks is considered in the balance. Much of this depends on the differences in equipment, farming techniques and other regional factors. HYDROGEN Hydrogen could become a major energy source, reducing U.S. dependence on imported petroleum while diversifying energy sources and reducing pollution and greenhouse gas emissions. Oil and other non-renewable fossil fuels are being quickly consumed, which is creating major impacts on air and water pollution as well as concern on global climate change. A shift to zero-carbon emission solar hydrogen systems could fundamentally resolve these energy supply and environmental problems. The expanded use of hydrogen as an energy source could help to address concerns over energy security, climate change and air quality. It could be produced in large refineries in industrial areas, power parks and fueling stations in communities, distributed facilities in rural areas with processes using fossil fuels, biomass, or water as feedstocks and release little or none carbon dioxide into the atmosphere. Hydrogen has been promoted as a universal fuel that could power automobiles, aircraft, spacecraft, power plants and appliances, including gas stoves that can operate on mountain tops. Hydrogen could be used in refrigerator-sized fuel cells to produce electricity and heat for the home. Vehicles that operate by burning hydro-

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gen or by employing hydrogen fuel cells would emit essentially water vapor. They could also be used as sources of electric power when not in use. Micro-fuel cells using small tanks of hydrogen could operate mobile generators, electric bicycles and other portable items. Large 250-kW stationary fuel cells, alone or in tandem, are being used for backup power and as a source of distributed generation supplying electricity to the utility grid. Hydrogen can be manufactured from water with algae and other microorganism, as well as with any source of electricity. New electrical production options include coal and nuclear power plants or solar technologies, such as photovoltaic, wind and ocean thermal systems. New inventions are rapidly progressing that will enable a solar hydrogen society to enter a non-carbon age of material excellence. Since it is a zero-carbon emission fuel, carbon emissions that may effect pollution and global climate change are eliminated. Shifting to hydrogen energy can have a profound positive impact on the Earth’s biological systems as well as reduce future cost and supply uncertainties and significantly improve the U.S. balance of trade. Hydrogen is the simplest, lightest and most abundant of the 92 elements in the universe. It makes up over 90% of the universe and 60% of the human body in the form of water. As the most basic element, it can never be exhausted since it recycles in a relatively short time. While hydrogen is the simplest element and most plentiful gas in the universe, it never occurs by itself and always combines with other elements such as oxygen and carbon. The hydrogen atoms are bound together in molecules with other elements and it takes energy to extract the hydrogen. Hydrogen is not a primary energy source, but it can be used like electricity as a method of exchange for getting energy to where it is needed. As a sustainable, non-polluting source of power hydrogen could be used in many mobile and stationary applications. As an energy carrier, hydrogen could increase our energy diversity and security by reducing our dependence on hydrocarbon-based fuels. Hydrogen is different than other energy options like oil, coal, nuclear or solar. The transition from nonrenewable fossil fuel should consider the development of technologies that can use the available energy of the sun. It is reasonable to assume that solar energy will eventually serve as a primary energy source. Solar technology is renewable, modular and generally pollution free, but it has some disadvantages, such as not always


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being available at the right time. Many environmental problems are the result of finding, transporting and burning fossil fuels. But, when hydrogen is used as a fuel, its byproduct is essentially water vapor. When hydrogen is burned in the air, which contains nitrogen, nitrogen oxides can be formed as they are in gasoline engines. These oxides can almost be eliminated in hydrogen engines by lowering the combustion temperature of the engine. Some tests have shown that the air coming out of a hydrogen-fueled engine is cleaner than the air entering the engine. Acid rain, ozone depletion and carbon dioxide accumulations could be greatly reduced by the use of hydrogen. After it has been separated, hydrogen is an unusually clean-energy carrier and clean enough for the U.S. space shuttle program to use hydrogen-powered fuel cells to operate the shuttle’s electrical systems while the byproduct of drinking water is used by the crew. Hydrogen could be an alternative to hydrocarbon fuels such as gasoline with many potential uses, but it must be relatively safe to manufacture and use. Hydrogen fuel cells can be used to power cars, trucks, electrical plants, and buildings but the lack of an infrastructure for producing, transporting, and storing large quantities of hydrogen inhibit its growth and practicality. Although the technology for electrochemical power has been known since 1839, fuel cells are still not in widespread use. The electrochemical process allows fuel cells to have few moving parts. Air compressors are often used to improve the efficiency although there are compressor-less designs. Fuel cells operate like batteries expect that they combine a fuel, usually hydrogen, and an oxidant, usually oxygen from the air, without combustion to produce an electric current. HYDROGEN PRODUCTION Hydrogen can be produced from natural gas, gasoline, coal-gas, methanol, propane, landfill gas, biomass, anaerobic digester gas, other fuels containing hydrocarbons, and water. Obtaining hydrogen from water is an energy intensive process called electrolysis, while hydrocarbons require a more efficient reforming process. Hydrogen may be produced by splitting water (H2O) into its component parts of hydrogen (H2) and oxygen (O). Steam reforming of methane from natural gas is one way to do this. It converts the methane and

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other hydrocarbons in natural gas into hydrogen and carbon monoxide using the reaction of steam over a nickel catalyst. The method of electrolysis uses an electrical current to split water into hydrogen at the cathode (+ terminal) and oxygen at the anode (– terminal). Steam electrolysis adds heat to the process. This heat provides some of the energy needed to split water which makes the process more energy efficient. When hydrogen is generated from renewable sources, its production and use becomes part of a clean, natural cycle. Thermochemical water splitting uses chemicals and heat in several steps to split water into hydrogen and oxygen. Photolysis is a photoelectrochemical process that uses sunlight and catalysts to split water. Biological and photobiological water splitting use sunlight and biological organisms. Thermal water splitting uses a high temperature of 1000°C. Biomass gasification uses microbes to break down different biomass feedstocks into hydrogen. Some of the first life forms on Earth were photosynthetic algae that existed about 4 billion years ago. Hydrogenase is an enzyme that can be used in extracting hydrogen from carbon. Chlorophyll uses sunlight to extract hydrogen from water. Developments in Microbiology, Molecular Biology and Nanotechnology are expected to allow biological hydrogen production systems to be fully realized. Cost is one hurdle that is keeping hydrogen from being more widely used as a fuel. Many changes in the energy infrastructure are needed to use hydrogen. Since electricity is required for many hydrogen production methods, the cost of this electricity tends to make hydrogen more expensive than the fuels it would replace. A study by the Massachusetts Institute of Technology and Harvard University, concluded that hydrogen produced by electrolysis of water will depend on low cost nuclear power. Nuclear power can produce hydrogen without emitting carbon dioxide into the atmosphere. Electricity from a nuclear plant could electrolyze water splitting H2O into hydrogen and oxygen. However that nuclear power can create long-term waste problems. Performing electrolysis with renewable energy, such as solar or wind power eliminates pollution problems of fossil fuels and nuclear power. However, current renewable sources only provide a small portion of the energy that is needed for a hydrogen fuel supply. From 1998 to 2003, the generating capacity of wind power increased 28% in the U.S. to


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about 6,500 megawatts, enough for less than 2 million homes. Wind is expected to provide about 6%of the nation’s power by 2020. The University of Warwick in England estimates that converting every vehicle in the U.S. to hydrogen would require the output of a million wind turbines which could cover half of California. Solar panels would also require huge areas of land, but huge tracts of land are available in the southwest, a region ideally suited for solar production. Water sources could be another problem for hydrogen production, particularly in sunny regions that are well-suited for solar power. A study by the World Resources Institute in Washington, D.C. estimated that obtaining adequate hydrogen with electrolysis would require more than 4 trillion gallons of water yearly. This is equal to the flow over Niagara Falls every 90 days. Water consumption in the U.S. could increase by about 10%. Another matter is hydrogen’s flammability since it can ignite in low concentrations and can leak through seals. Leaks in transport and storage equipment could present public safety hazards. Gasoline transport and storage presents similar public safety hazards. Hydrogen gas is odorless and colorless. It burns almost invisibly and a fire may not be readily detected. Compressed hydrogen gas could be ignited with the static discharge of a cell phone. But, an accident may not cause an explosion, since carbon fiber reinforced hydrogen tanks are nearly indestructible. There is always the danger of leaks in fuel cells, refineries, pipelines and fueling stations. Hydrogen is a gas, while most of our other fuels are liquids and easily spread over the ground or other objects. Hydrogen gas will rise into the atmosphere. In a high-pressure gas or cryogenic liquid hydrogen fuel distribution the hydrogen is such a small molecule that it tends to leak through the smallest of cracks. A leaky infrastructure could alter the atmosphere according to researchers from the California Institute of Technology and the Jet Propulsion Laboratory in Pasadena, CA. They used statistics for accidental industrial hydrogen and natural gas leakage which were estimated at 10 to 20% of total volume. Extending these estimates to an economy that runs on hydrogen results in four to eight times as much hydrogen in the atmosphere. The Department of Energy’s Office of Energy Efficiency and Renewable Energy thinks these estimates are much too high. But, more hydrogen in the atmosphere will combine with oxygen to form water vapor and create more clouds. This increased cloud cover

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could alter the weather more and affect global warming. Hydrogen can be stored and transported as a compressed gas, a cryogenic liquid or in solids. Liquid hydrogen is closer to gasoline in the areas of volume and weight. If used in commercial aircraft, the takeoff weight could be reduced by 40 percent. Hydrogen can be transported in underground pipelines, tanker trucks or ships. Hydrogen pipelines can carry both gaseous and liquid hydrogen. Before the wide-scale use of hydrogen becomes a reality in transportation, researchers must develop new technologies that can use hydrogen that is stored or produced, as needed, onboard vehicles. Hydrogen internal combustion engines can be used to convert hydrogen’s chemical energy to electricity using a hydrogen piston engine coupled to a generator in a hybrid electric vehicle. Onboard reforming for fuel cells depends on catalytic reactions to convert conventional hydrocarbon fuels, such as gasoline or methanol, into hydrogen that fuel cells can then use to produce electricity to power vehicles. The FreedomCAR Partnership to develop fuel-cell-powered vehicles committed the U.S. Department of Energy toward a hydrogen-based energy system by making fuel-cell-powered vehicles available in 2010. The FreedomCAR program also sponsored investigation of ultralight materials including plastics, fiberglass, titanium, magnesium, carbon fiber and developing lighter engines made from aluminum and ceramic materials. These new materials can reduce power requirements and allow other fuels and fuel cells to become popular more quickly. When hydrogen is used as fuel, the main emission from fuel cells is potable water. Even when using hydrocarbons as fuel, these systems offer substantial reductions in emissions. Honda’s FCX fuel cell vehicle carries 156.6 liters of compressed hydrogen (about 3.75 kilograms) in two aluminum tanks. The fuel cell’s peak output is 78 kilowatts which drives the electrical motor that moves the vehicle. An ultra-capacitor acts as a reservoir when the electrical load during acceleration exceeds the energy produced by the fuel cell. The ultra-capacitor offers quicker and higher voltage discharges and recharges than nickel-hydride batteries which are also used for this purpose. The batteries are slower to charge but hold it longer. Solid Oxide Fuel Cell (SOFC) systems can reach electrical efficiencies of over 50% when using natural gas, diesel or biogas. When combined with gas turbines there can be electrical efficiencies of 70%, for small in-


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stallation as well as large. In a fuel cell system, these efficiencies can be kept at partial loads as low as 50%. Conventional technologies must run at close to full load to be most efficient. NOx and SOx emissions from SOFC systems are negligible. They are typically 0.06-g/kWhe and 0.013-g/kWhe (kilo-watt hours electrical). SOFCs also produce high-quality heat with their working temperature of 850°C. This makes combined heat and power production possible with SOFC systems. The total efficiency can then reach 85%. Advanced conventional cogeneration of heat and power can reach total efficiencies up to 94% with electrical efficiencies over 50%. This occurs only at full load. A high electrical efficiency is preferred over heat efficiency, since this results in a higher energy with the initial energy source better utilized, in terms of practical end-use. Fuel cell systems are modular like computers which makes it possible to ramp up generating facilities as needed with sections in an idle mode when full capacity is not needed. The capacity is easily adjusted, as the need arise. Hydrocarbons such as natural gas or methane can be reformed internally in the SOFC, which means that these fuels can be fed to the cells directly. Other types of fuel cells require external reforming. The reforming equipment is size-dependent which reduces the modularity. Fuel cell cars must be able to drive hundreds of miles on a single tank of hydrogen. Honda’s prototype fuel cell car had a range of 190 miles in 2004. It stored a little more than 3 kilograms of hydrogen at 4,400 psi. This gave it a mile/kg efficiency of 51 city and 46 highway. The next model had an improved fuel cell and was rated at 62 city and 51 highway. An experimental Honda fueling station in the Los Angeles area produces about 1/2 kg of hydrogen per day. It uses 700 square feet of solar panels to produce 6 kilowatts of power to electrolyze water. Cars and light trucks produce about 20% of the carbon dioxide emitted in the U.S., while power plants burning fossil fuels are responsible for more than 40% of CO2 emissions. Fuel cells can be used to generate electricity for homes and businesses. Hydrogen fuel cells do not emit carbon dioxide, but extracting hydrogen from natural gas, gasoline or other products requires energy and involves other byproducts. Obtaining hydrogen from water through electrolysis consumes large amounts of electrical power. If that power comes from plants burning fossil fuels, the end product can be clean hydrogen, but the process used to obtain it can be polluting.

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After the hydrogen is extracted, it must be compressed and transported, if this equipment operates on fossil fuels, they will produce CO2. Running an engine with hydrogen extracted from natural gas or water could produce a net increase of CO2 in the atmosphere. FUEL CELL APPLICATIONS Fuel cells seem like an energy user’s dream: an efficient, combustion-less virtually pollution-free power source, capable of being sited in downtown urban areas or in remote regions, that runs almost silently and has few moving parts. Based on an electrochemical process discovered more than 150 years ago, fuel cells supplied electric power for spacecraft in the 1960s. Today they are being used in more and more distributed generation applications to provide on-site power and waste heat in some cases for military bases, banks, police stations and office buildings from natural gas. Fuel cells can also convert the energy in waste gases from water treatment plants to electricity. In the future, fuel cells could be propelling aircraft, automobiles and allowing homeowners to generate electricity in their basements or backyards. While fuel cells operate much like a battery, using electrodes in an electrolyte to generate electricity, they do not lose their charge as long as there is a constant source of fuel. Fuel cells to generate electricity are being produced by companies such as Plug Power, UTC, FuelCell Energy and Ballard Power Systems. Most of these are stationary fuel cell generators. Plug Power has hundreds of systems in the U.S. including the first fuel-cell-powered McDonald’s. The installed fuel cells have a peak generating capacity of over 100 megawatts. The fuel cells used in the space program in the 1960s and 1970s were very costly at $600,000/kW. Although some of this cost can be attributed to the high reliability manufacturing required for space application. The cost was far too high for most terrestrial power applications. During the past three decades, major efforts have been made to develop more practical and affordable designs for stationary power applications. Today, the most widely deployed fuel cells cost about $4,000 per kilowatt compared to diesel generator costs of $800 to $1,500 per kilowatt. A large natural gas turbine can be even less.


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Many specialty products are designed for specific applications. One power system from a California company called HaveBlue is designed for sailing yachts. The system includes solar panels, a wind generator and a fuel cell. The solar panels provide 400 watts of power for the cabin systems and an electrolyzer for producing hydrogen from salt or fresh water. The hydrogen is stored in six tanks in the keel. Up to 17 kilograms of hydrogen is stored in the solid matrix metal hydride tanks which replace 3,000 pounds of lead ballast. The wind generator has an output of 90 watts under peak winds and starts producing power at 5 knots of wind. The fuel cell produces 10 kilowatts of electricity along with steam which is used to raise the temperature of the hydrogen storage tanks. A reverseosmosis water system desalinates water for cabin use and a deionizing filter makes pure water for fuel cell use. Other applications include fuel cell-powered forklifts that are being used in a General Motor’s plant in Oshawa, Ontario, Canada. The Hydrogenics forklifts have a 5000 pound lift capacity and are perfect for indoor facilities, such as factories and warehouses, since they produce no significant exhaust emissions, and are quite and offer significant operational advantages over battery-powered forklifts such greatly reduced recharge times. This project was partially funded by the Sustainable Development Technology Canada foundation which was created by the Canadian government to develop and demonstrate clean technologies that address climate change as well as clean air, water and soil quality. Also involved are the Canadian Transportation Fuel Cell Alliance and FedEx Canada, Deere & Co. and the NACCO Materials Handling Group which assisted in the integration of the fuel cell systems into the forklifts. The forklift and refueler project will also be used for FedEx operations in the Greater Toronto Area. The fuel cell power pack includes the fuel cell power module, an ultracapacitor storage unit, hydrogen storage tanks, thermal management and power electronics and controls. Hydrogenics’ HyPM 10 Proton Exchange Membrane (PEM) fuel cells are used. The power pack is 33 inches long x 40 inches wide x 24 inches high. The low-pressure cell is rated 10-kW net continuous power at 39 to 58 Vdc with a maximum system efficiency of 56%. The HyPM 10 fuel cell uses hydrogen with a low-pressure design for quiet operation while maintaining high performance. The four-wheel forklift uses regenerative braking. Electric energy is stored in Maxwell

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Technologies’ Boostcap ultracapacitors. Ultracapacitors have demonstrated a higher recovery of energy from braking than batteries. They are also lighter, have a longer life and are better for the environment. When used with fuel cells in stop-and-go mobility applications such as forklifts, ultracapacitors provide a burst of power for lifting acceleration and enable regenerative braking. A small 12-volt battery is also included to start up the fuel cell. These forklifts had previously been powered by heavier batteries, the fuel cell power pack was smaller and lighter than the lead acid battery system. But, the battery provided part of the counterbalance, so additional weight was added to provide enough stability for the forklift. The fuel cell is supplied with hydrogen from a HyLyzer hydrogen refueling station. The HyLyzer produces hydrogen by the hydrolysis of water using electricity. Depending on the size of the HyLyzer, the unit can produce up to 65-kg of hydrogen daily. The HyLyzer refueling station can refuel a forklift in less than two minutes, much less than batteries can be changed or recharged. The forklift’s 4 pound hydrogen storage capacity is enough for up to eight hours of operation. The modular design of the HyPM fuel cells allows scaling for higher power requirements using a variety of configurations, such as series and parallel systems. Potential applications for the technology include vehicle propulsion, auxiliary power units (APU), stationary applications including backup and standby power units, combined heat and power units and portable power applications for the construction industry and the military. HYDROGEN AIR TRANSPORT The hydrogen economy may be the solution to most of the hydrocarbon problems of today’s oil dependent transport systems. Hydrogen-powered aircraft could reduce greenhouse gas and nitrous oxide pollution from jet engines while being more efficient than present jet fuels. Fuel cells have to compete with the turbine, in installed cost as an aircraft power plant. A study by the U.K.’s Cranfield University concluded that fuel cells are still too heavy for propulsion. A large aircraft requires many megawatts, generated by at least two turbine engines weighing about 3,900 kg (8,600lb) each. Today’s fuel cells that generate 1,000 kW


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weigh over 3,200 kg each. Reforming on board allows the hydrogen to be transported in a form that is easy to move, such as methanol, natural gas and gasoline. The disadvantage is that having reformers on vehicles is not as efficient as central generation. But, a gas-or coal-powered power plant produces more carbon dioxide, defeating one object of using hydrogen. Nuclear power is a low carbon cost option, but faces political opposition. Renewable energy sources, such as solar power, wind and wave power, have been proposed as sources of power for electrolysis. But renewable technology is not mature enough to supply all the power required. Hydrogen and oxygen storage is another issue. There are significant mass impacts for the pressure vessels needed which are insulated to stop boil off losses. Hydrogen aircraft have been studied by NASA. This project involved a fuel-cell-powered aircraft the size of a Boeing 737 in its Revolutionary Aeropropulsion Concepts program. The hydrogen 737 would use a solid oxide fuel cell (SOFC) for power. Boeing will test a SOFC auxiliary power unit (APU) in one of its 737s. The APU is 45% efficient in turning hydrogen into electricity. In contrast, a gas turbine is 15% efficient. The APU will use a reformer to process jet fuel to obtain the hydrogen needed. Boeing hopes to offer the APU on versions of its 787 Dreamliner. The 787 Dreamliner will use 20% less fuel than the comparably sized 767. A completely new manufacturing process is used with sections of the fuselage produced around the world and then flown to the assembly plant in Everett, Washington, in a special 747 large cargo freighter. The body uses composite fibers of carbon graphite held together by epoxy for 50% of the overall fuselage. The engine is an ultra efficient General Electric GEnx with all composite fan case and blades as well as nozzles. It operates at lower temperatures with few hydrocarbon emissions. In the timeframes considered for the introduction of hydrogen-powered aircraft, renewable energy could be a viable option. Even if renewable energy was available for centralized production, the hydrogen would require a method of transport to the aircraft. Hydrogen can be piped, but gaseous hydrogen molecules are able to pass through solids, even stainless steel. In addition hydrogen makes steel brittle and more susceptible to fracture. An option is to store the hydrogen in a medium that releases it when heated. Research on this has focused on hybrids and pure carbon, or carbon nanotubes doped with metals, but there is a weight penalty.

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Liquid hydrogen is the way to store the volume needed for an aircraft according to the United Nations’ International Energy Agency’s hydrogen program. NASA is focusing on liquid-hydrogen power as part of its Vehicle Systems program. This includes a zero-emissions hydrogen-powered fuel-cell aircraft with cryogenic electric motors in the wing. The European Union has similar goals and in 2002 it completed a 3-year program called Liquid Hydrogen-Fueled Aircraft Systems Analysis, also known as Cryoplane. It involved 35 organizations across the EU and assessed practical solutions for the introduction of hydrogen aircraft. Computer models were used for fuel system simulation and aircraft propulsion systems. Defining the airport infrastructure for fuel production and distribution was also a major component. Since 2002, the EU has continued its study of hydrogen fuel and aviation with its Helicopter Occupant Safety Technology Application (HELISAFE) project. A Sustainable Fuel project is researching the use of a sustainable biomass fuel source for aviation that can be integrated into the existing infrastructure. It aims to create a safe and economical way of supplying hydrogen fuel. NASA and the California-based company AeroVironment built the Helios solar-powered remotely operated aircraft. Helios had a 235-kg non-regenerative fuel cell, but crashed into the Pacific in 2003 before it could use power from the fuel cell after breaking up in turbulence. AeroVironment achieved a major milestone when it successfully flew the world’s first fuel cell-powered unmanned air vehicle (UAV). The aircraft was a scale model of the planned Global Observer high-altitude long-endurance UAV and it was the first powered flight of its kind. The flight lasted 1 hour and used a proton exchange membrane cell with platinum catalyst. The Global Observer would use fuel cells and fly for more than a week at 65,000 feet (19,800m). Israel Aircraft Industries is working on mini-UAV applications where flight times last for 4 to 8 hours. Boeing’s fuel-cell-powered manned glider is being developed by the U.S. company’s Spanish operation with Intelligent Energy, a U.K. company, providing the fuel cell. A 50-kW proton membrane exchange fuel cell is used with a battery hydride in the glider. NASA has a partnership with the European Space Agency (ESA) to find catalysts less expensive than platinum, which is used widely in fuel cells. As an alternative to platinum, nickel, cobalt and copper alloys are possible solutions.


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Converting to Hydrogen Iceland has a hydrogen fueling station near Reykjavik for a small fleet of fuel cell buses. The hydrogen is produced onsite from electrolyzed tap water. The Iceland New Energy consortium includes auto manufacturers, Royal Dutch/Shell and the Icelandic power company Norak Hydro. It plans to convert all of Iceland to hydrogen. Almost 75% of Iceland’s present electricity comes from geothermal and hydroelectric power. In the U.S. only about 15% of grid electricity comes from geothermal and hydroelectric sources, while 70% is generated from fossil fuels. Only 16 hydrogen fueling stations are planned to allow Icelanders to refuel fuel cell cars around the country. At almost 90 times the size of Iceland, the U.S. could start with about 1,500 fueling stations. This assumes that the stations are placed to properly cover the entire U.S. with no overlap. The Department of Energy’s hydrogen-production research group expects that a fourth to a third of all filling stations in the U.S. would be needed to offer hydrogen before fuel cells become viable as vehicle power. California has its Hydrogen Highway Project with 150 to 200 stations at a cost of about $500,000 each. These would be situated along the state’s major highways by 2010. There are over 100,000 filling stations in the U.S. The Center for Energy, Environmental and Economic Systems Analysis at Argonne National Laboratory near Chicago estimates that building a hydrogen economy would take more than $500 billion. A hydrogen infrastructure could cost hundreds of billions, since there is a limited hydrogen-generating capacity now. But, decentralizing production, by having reformers in buildings and even in home garages in combination with local power generation, reduces some of that excessive cost. Larger reformers in neighborhood facilities could be the service stations of tomorrow. One study of the near-term hydrogen capacity of the Los Angeles region concluded that hydrogen infrastructure development may not be as severe a technical and economic problem as often stated. The hydrogen fuel option is viable for fuel cell vehicles and the development of hydrogen refueling systems is taking place in parallel with various fuel cell vehicle demonstrations. Hydrogen fuel cells are being prompted by the desire to reduce global warming and control the spread of pollution in the developing world. Fuel cells offer a major step in improved efficiency and reduced emissions.

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Hydroelectric dams could also be impacted by fuel cells. When fuel cells abound, electricity prices may fall and dam owners could make more profit selling hydrogen than selling electricity. Oil companies are not willing to invest in production and distribution facilities for hydrogen fueling until there is enough demand for hydrogen. Automakers will not produce large numbers of hydrogen cars until drivers have access to hydrogen fuel. The government’s FreedomCAR program, funded hydrogen R&D in conjunction with American car manufacturers. The program required that the companies demonstrate a hydrogen-powered car by 2008 and most have done so. Efforts continue to improve fuel cell technology and utilization which should reduce costs. Volume production of fuel cell cars should reduce costs, but one Department of Energy projection with a production of 500,000 vehicles a year still had the cost too high. A potential problem with the proton exchange membrane (PEM) fuel cell, which is the type being developed for automobiles is life span. Internal combustion engines have an average life span of 15 years, or about 170,000 miles. Membrane deterioration can cause PEM fuel cells to fail after 2,000 hours or less than 100,000 miles. Ballard’s original PEM design has been the prototype for most automobile development. This has been the basic design that has been used to demonstrate fuel cell power in automobiles. But, it may not be the best architecture and geometry for commercial automobiles. The present geometry may be keeping the price up. Commercial applications require a design that will allow economies of scale to push the price down. The hydrogen economy could arrive by the end of the next decade or closer to midcentury. But, interim technologies will play a critical role in the transition. One of the most important of these technologies is the gas-electric hybrid vehicle, which uses both an internal combustion engine and an electric motor. Electronic power controls allow switching almost seamlessly between these two power sources to optimize gas mileage and engine efficiency. U.S. sales of hybrid cars has been growing and hybrid sales are expected to rise as gasoline prices continue to increase. The costs associated with making a changeover to hydrogen fuel seems high, but the environmental costs of finding, transporting and burning fossil fuels are not included in the current energy pricing structure. The costs of atmospheric pollution may be billions of dollars in additional health care costs as well as forest and crop losses and the corrosion


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of buildings and other structures. Hydrogen fueled engines tend to be more energy efficient because of their complete combustion. Gasoline and diesel engines form carbon deposits and acids that erode the interior surfaces of the engine and contaminate the engine oil. This increases wear and corrosion of the bearing surfaces. Since hydrogen engines produce no carbon deposits or acids, they should require far less maintenance. Hydrogen can also be used in more efficient Stirling cycle engines. Special burners have also been used by the Tappan Company for hydrogen stoves. Hydrogen burns with an invisible flame, so Tappan used a steel wool catalyst that sits on the burner head. The stainless steel mesh glows when heated and resembles an electric range surface when the burner is on. Hydrogen research programs were started up in the U.S. Air Force, Navy and the Army in the 1940s when fuel supplies were a concern. After World War II and prior to the Arab oil embargo in 1973, oil was selling for less than $3 per barrel. Fuel supply was not a concern. During the Arab oil embargo in 1973, when there were long gas lines in the U.S., the price of oil quadrupled. This started renewed research into alternative energy supplies including solar power. Storing Hydrogen Studies have indicated that large-scale storage could take place with gaseous hydrogen underground in aquifers, depleted petroleum or natural gas reservoirs or man made caverns from mining operations. It is possible to store hydrogen as a high pressure gas in steel containers. Other methods of storage for hydrogen include solid or liquid hybrids or low temperature cryogenic liquids. Liquid hydrogen as a method for storing and transporting hydrogen can have several advantages over gases. The liquid form has a higher energy density and is easier to transport and handle. At atmospheric pressures, hydrogen is a liquid at -253°C (-423°F), which is only a few degrees above absolute zero. It must be stored in highly insulated tanks. Liquid hydrogen is a cryogenic fuel. Cryogenics is the study of low temperature physics. A beaker of liquid hydrogen at room temperature will boil as if it was on a hot stove. If the beaker of liquid hydrogen is spilled on the floor, it is vaporized and dissipates in a few seconds. If liquid hydrogen is poured on the hand, it would feel cool to the touch as it slides through the fingers. This is due to the thermal barrier that is pro-

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vided by the skin. But, place a finger in a vessel containing liquid hydrogen and severe injury will occur in seconds because of the extremely cold temperature. In most accidents, the most serious concern would be a fuel fed fire or explosion. In this case, liquid hydrogen is generally considered to be a preferred fuel. CONSERVATION AND PROGRESS Future developments in energy technology can alter the relative economics of nuclear, hydrocarbon, solar, wind, and other methods of energy generation. Conservation if practiced extensively as a replacement to hydrocarbon and nuclear power means a major step backward for our modern world. The United States is paying more than $300 billion per year for foreign oil and gas. Energy production has surged abroad while domestic production has stagnated. This is largely due to complex government regulations and energy policies which have made the U.S. an unfavorable place to produce energy. The repeal of this conglomerate of regulations, tax incentives and subsidies to energy generation industries would do much to foster energy development and allow a free competition to determine the best energy paths. Technological advances reduce cost, but usually not quickly. International rationing and taxation of energy has also been proposed as energy policy. Nuclear power can be safer, less expensive, and more environmental agreeable than hydrocarbon power. But solid, liquid and gaseous hydrocarbon fuels provide many conveniences and the infrastructure to use them is already in place. Oil from shale or coal liquefaction is more expensive than crude oil at current prices since production costs are higher than developed oil fields. There is an investment risk that crude oil prices could drop and then liquefaction plants could not compete. Nuclear energy does not have this disadvantage. NUCLEAR ENERGY In the U.S. about 20% of the electric power is produced by 104 nuclear power reactors with an average output of almost 900 megawatts per


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reactor or 93-GWe (gigawatts) total. If this were increased by 250-GWe, nuclear power could fill all current U.S. electricity requirements. If the heat from these additional nuclear reactors were used for coal liquefaction and gasification, the U.S. would not need to use its oil resources. According to some estimates the U.S. has about 25% of the world’s coal reserves. This heat could also be used to liquefy biomass, trash, or other source of hydrocarbons. The Palo Verde nuclear power station near Phoenix, Arizona, was originally intended to have 10 nuclear reactors with a generating capacity of 1,243 megawatts each. As a result of public pressure, construction at Palo Verde was stopped after three operating reactors were completed. This installation is on 4,000 acres and is cooled by waste water from the city of Phoenix, which is nearby. An area of 4,000 acres is 6.25 square miles or 2.5 miles square. The power generating facilities occupy a small part of this area. If a facility like Palo Verde were built in half of the 50 states and each installation included 10 reactors as initially planned for Palo Verde, these plants, operating at the current 90% of design capacity, would produce 280-GWe of electricity. Allowing a construction cost of $2.3 billion per 1,200-MWe reactor with 15% for economies of scale, the total cost of this entire project would be $1/2 trillion, or about 2 months of the current U.S. federal budget. This is 4% of the annual U.S. gross domestic product. Along with these power plants, the U.S. could build up a fuel reprocessing capability to allow spent nuclear fuel to be reused which would lower fuel cost and eliminate the storage of high-level nuclear waste. Fuel for the reactors has been estimated to be available for 1,000 years using standard reactors with high breeding ratios and breeder reactors where more fuel is produced than consumed. Only about 33% of the thermal energy in today’s nuclear reactors is converted to electricity. Some newer designs can convert almost 50%. The heat from a 1,243-MWe reactor could produce 38,000 barrels of coalderived oil per day. The additional Palo Verde facilities could provide a yearly output of about 3.5 billion barrels per year with a value, at $90 per barrel, of more of $300 billion per year. This is about the oil production of Saudi Arabia. The current proven coal reserves of the United States are estimated to support this production level for 200 years. This liquefied coal reserve

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exceeds the proven oil reserves of the entire world. The reactors could produce hydrogen or gaseous hydrocarbons from the coal as well. The excess heat from nuclear power plants could also be used for central heating. The U.S. needs more low-cost energy and across the globe, billions of people in all nations seek to improve their lives with abundant lowcost energy, which has become the driving force of technological progress. In newly developing countries, that energy is coming largely from hydrocarbon sources. ENERGY AND WEALTH Energy has become the foundation of wealth and can provide better food production. Energy-intensive hydroponic greenhouses are 2,000 times more productive per unit land area than modern American farming methods. If energy is abundant and inexpensive, there are almost no limits to world food production. Fresh water is also in short supply in many areas. Plentiful inexpensive energy allows sea water desalination to provide almost unlimited supplies of fresh water. Over the last few centuries, technological progress has depended on the use of abundant energy. These advances have improved many aspects of human life. In the 21st century low cost energy will be needed to continue this advance. If the future is harmed by world energy rationing, the result could be human suffering and the Earth’s environment would be a victim as well. Low cost energy is important to the environment. We are beyond the age of subsistence living and prosperous living is needed to provide for environmental preservation and enhancement which an impoverished population cannot afford. THE COST OF ENERGY The accounting cost of a barrel of oil or a ton of coal or a therm of natural gas is normally assumed to be the taking cost and the replacement cost is neglected. If the replacement cost of oil is used to establish the cost of gasoline at the pump, cars would be much more fuel-efficient. If we valued the replacement cost of energy, natural gas would not


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have been vented for decades from oil fields. When the external costs of using fossil and nuclear fuels, including environmental regulations and health care costs are factored into the price of gasoline products, hydrogen becomes one of the least expensive fuels. Many believe that the legislative trigger mechanism for the hydrogen economy is the passage of a Fair Accounting Act that will insure that hydrogen will be the least expensive fuel. Society must become more sustainable to conserve the resources that make humans productive. A more complete economic analysis and accounting would stimulate improved efficiency for economic development and promote a future with sustainable prosperity. The problems of expanding demands for diminishing resources have been important in modern struggles for more oil resources. In World War II Japan and Germany needed access to oil. Limiting this access was part of the Allied efforts to end World War II. There have been more recent struggles to control the Organization of Petroleum Exporting Countries (OPEC) and other oil rich areas, including the pathways from foreign oil fields to markets. The opportunities to harness solar, wind, wave, falling water and biomass-waste resources are projected to exceed any wealth created by the exploitation of oil. Progress beyond the Oil Age means an important economy of wealth expansion from energy-intensive goods and services with renewable energy. As energy-efficient technologies help to release us from fossil fuels, consumers will have a wider and more diverse set of energy sources, the economy will be more robust and the world more stable. A CARBON AGE Carbon reinforced products that require less energy to produce and that are ten times stronger than steel, lighter than aluminum, and that conduct more heat than copper can be increasingly used to reduce the weight of products, improve the performance of appliances and tools and increase the efficiency of heat-transfer systems. Other forms of carbon can provide super semiconductors and advanced optics. Hydrogen powered transportation equipment can use stronger, lighter more compact energy storage tanks made of carbon. Aircraft, ships and buildings can use new forms of carbon materials that are much stronger, more corrosion resistant, and that will withstand higher temperatures than steel.

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References

Behar, Michael, “Warning: the Hydrogen Economy May Be More Distant Than It Appears,” Popular Science, Volume 266, Number 1, January 2005, pp. 65-68.

Braun, Harry, The Phoenix Project: An Energy Transition to Renewable Resources, Research Analysts: Phoenix, AZ, 1990.

Cothran, Helen, Book Editor, Global Resources: Opposing Viewpoints, Greenhaven Press: San Diego, CA, 2003.

Hordeski, Michael F., Hydrogen & Fuel Cells-Advances in Transportation and Power, The Fairmont Press: Lilburn, GA, 2007.

Kemp, William H., The Renewable Energy Handbook, Aztext Press,: Ontario, Canada, 2005.

RAND Corporation Oil Shale Development in the United States—Prospects and Policy

Issues, J.T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson, and G. Cecchine, MG-414NETL, 2005.

Room, Joseph J., The Hype About Hydrogen, Island Press: Washington, Covelo, London, 2004.

Schneider, Stephen Henry, Global Warming, Sierra Club Books: San Francisco, CA, 1989.

Chapter 2

Green Power Trends Keywords: Global Warming Climate Shifts Reducing Emissions Carbon-free Nuclear Power Fuel Cell Power

Fuel Cell Trends Supercritical Coal Plasma Gasification Cogeneration Trigeneration

The greenhouse effect relates to the increased warming of the earth’s

surface and lower atmosphere that occurs from increased levels of carbon dioxide and other atmospheric gases. This is similar to the glass panels of a greenhouse where the heat is let in through the glass but most of it is prevented from escaping. If the earth did not act like a giant greenhouse, temperatures at the earth’s surface would be about 35°C (60°F) colder than they are, and life on earth would be much different. These greenhouse gases might be affected by human actions. A rise in temperature of about 5°C (9°F) in the next fifty years would be equal to a rate of climate change almost ten times faster than the average observed rate of change. Temperature changes of this magnitude could transform patterns of rainfall, drought, growing seasons and sea level. The trace gases in the earth’s atmosphere are only a few percent of its composition but they make the planet livable. They absorb radiant energy at infrared wavelengths much more efficiently than they absorb radiant energy at solar wavelengths, thus trapping most of the radiant heat emitted from the earth’s surface before it escapes. Greenhouse gases also include water vapor and the water droplets in clouds. Besides carbon dioxide, methane is another important greenhouse gas. It has increased in the atmosphere by almost 100% since 1800 but has been stable or even seen a slight decrease since 1990. Methane is produced by biological processes where bacteria have access to organic 41

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matter such as marshlands, garbage dumps, landfills and rice fields. Some methane is also released in the process of extracting coal or transporting natural gas. Methane is 20-30 times as effective at absorbing infrared radiation as CO2. But, it is not as important in the greenhouse effect since the CO2 percentage is much greater in the earth’s atmosphere. Chlorofluorocarbons (CFCs) are even more effective greenhouse gases, but are only a small part of the CO2 greenhouse gases. CFCs are involved in the depletion of stratospheric ozone. Ozone is a form of oxygen (O3), where three oxygen atoms combine into one molecule. Ozone has the property of absorbing most of the sun’s ultraviolet radiation. It does this in the upper part of the atmosphere, called the stratosphere, which is about 6 to 30 miles (10-50 kilometers) above the earth. This absorption of ultraviolet energy causes the stratosphere to heat up. Life on earth has been dependent on the ozone layer shielding us from harmful solar ultraviolet radiation. Ozone is part of the greenhouse effect, although it is not as important as CO2 or methane. Ozone in the lower atmosphere can cause damage to plant or lung tissues and is a pollutant in photochemical smog. Other greenhouse gases, include nitrous oxide (laughing gas), carbon tetrachloride, and several other minor gases. The total greenhouse effect of these gases is estimated to add 50-150% to the increase in greenhouse effect expected from CO2 alone. In the century from 1890 to 1990, the average surface temperature of the earth increased by 0.3 to 0.6 degrees Celsius. This temperature rise, which has lengthened the growing season in parts of the northern hemisphere, may have occurred naturally, although such a change would be notable. Besides some indications that the data may be skewed, some argue that reporting stations are not siting their sensors properly, data is being emitted that would reduce any temperature increases. GLOBAL WARMING Global warming has become a major concern. However, it was not that long ago that global cooling was the issue. In the 1970s, several extreme weather events, including freezing conditions in Florida, produced fears over decreasing temperatures. In 1974, the CIA even issued a report claiming that decreases in temperature could have an affect on our geopolitical future. In the 1980s, the focus shifted to global warming, as a result

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of the unusual drought and heat wave of 1988. When climate scientist James Hansen reported to Congress that he was 99% sure that the greenhouse effect was contributing to global warming, a growing anxiety over rising temperatures caught the attention of the media and the public. Environmentalists became obsessed over the role of modern life in global warming and used this to push goals such as improving air quality and preserving forestland. Some studies indicate that human influence accounts for 75% of the increase in average global temperature over the last century, while others point to nine other factors that may be more important than human activity and the fact that Mars and Venus are also experiencing warming trends. Changes in global ocean currents or in the amount of energy emitted by the sun play an important part in any changes. Most of industry including the oil, gas, coal and auto companies have viewed the issue as a theory in need of more research, while many cry for major actions to curtail fossil fuel use. Climate scientists are using computer simulations to investigate possible global warming contingency plans. One proposal being studied involves an array of sulfur particles to reflect solar radiation. This is partly based on a study of the cooling effects of a 1991 volcanic eruption. These reflective particles in the upper atmosphere could cost $400 million per year to maintain. But, this is less expensive than another proposal that was in the Journal of Science in 2006. It involved cooling the Earth by orbiting 16 trillion solar mirrors at a cost of trillions of dollars. Even if these schemes would reduce warming of the earth, excess greenhouse gas emissions could result in more acidic oceans since the oceans would continue to absorb excess carbon dioxide and this could affect rainfall patterns. Some see global warming as a threat that could create problems ranging from large-scale property losses and forced migrations to conflicts over food and water. But, news reports on global warming effects tend to neglect all of the possible consequences. Some of these include more rainfall and longer growing seasons which can benefit higher latitudes while less rainfall and harsher droughts may occur in some of the world’s poorest areas such as Africa. An open-water Arctic Ocean in summers could be a threat to polar bears but there may be new shipping lanes that are thousands of miles shorter resulting in improved economics in many areas. There is little agreement about the amount of temperature change,

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sea levels and storm strength effects. Warmer waters could produce stronger hurricanes, but new studies find that hurricanes can be broken up by winds caused by rising temperatures. The question remains if we are altering the environment faster than we can predict the consequences and take preventive actions to minimize the consequences. Responding to the greenhouse challenge may be as much about hedging against uncertain risks as it is about dealing with what is clearly known. The risks are largely unknown but there remains a chance that things could be worse than the projections of a few degrees of warming in this century. How do we deal with these uncertain but potentially calamitous risks and can the global economy be moved away from carbon-rich oil, coal, and natural gas? Some argue that the only way to force a change is with taxes on fuels that produce greenhouse gases. An increase in the federal gas tax of 2.5 cents a gallon would triple the federal energy-research budget, this research could help to increase the use of alternative fuels. Others push for emission-reduction treaties, such as the Kyoto Protocol or legislation that requires emissions reductions. But, there are major economic impediments, both globally and domestically. It could impede economic growth and mean higher taxes and heating bills for many. The faster the climate warms up, the more likely it is that feedback processes will change the greenhouse gas buildup. There are many that believe that CO2 and other trace greenhouse gases could double sometime within the next century. Estimates on fossil fuel growth suggest a 1-2% annual growth rate. This could double the amount CO2 based on preindustrial levels. The different greenhouse gases may also have complex interactions. Carbon dioxide can cool the stratosphere which slows the process that destroys ozone. Stratospheric cooling can also create high altitude clouds which interact with chlorofluorocarbons to destroy ozone. Methane may be produced or destroyed in the lower atmosphere at different rates, which depend on the pollutants that are present. Methane can also affect chemicals that control ozone formation. The removal of CO2 from the atmosphere takes place through biological and chemical processes in the oceans, which may take decades or centuries. Climate changes also modify the mixing processes in the oceans. Biological moderation involves biological feedback processes that can affect the amounts of carbon dioxide that might be injected into the

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air over the next century. As CO2 increases, green plants could take up more carbon dioxide into plant tissues through photosynthesis reducing slightly the buildup of CO2. This could moderate some of the greenhouse effect. However, raising the temperature in the soils by a few degrees may increase the activity rates of bacteria that convert dead organic matter into CO2. This is a positive feedback loop since warming would increase the CO2 produced in the soils, further increasing the warming. The EPA thinks there is a real potential for major positive feedback that could greatly increase greenhouse effects. There are more than a dozen biological feedback processes that could affect estimates of the temperature sensitivity to greenhouse gases due to human activities. If all of these operate in unison, it could double the sensitivity of the climatic system to the initial effects of greenhouse gases. This would be a possible but worst case situation. The time frame over which these processes could occur is estimated at several decades to a century or more. Climate Modeling Most climate models indicate a climate in stable equilibrium. If the 1900 condition of 300 parts per million doubles to 600 ppm, most threedimensional models indicate an equilibrium with an average surface temperature warming of 3.5° to 5°C (5.6° to 9°F). If the carbon dioxide content of the atmosphere doubled in one month, the earth’s temperature would not reach its new equilibrium value for a century or more. If we were able to limit all CO2 emissions, we could still expect about one degree of warming while the climatic system catches up with the greenhouse gases already released. It is not the global average temperature that is most important but it is the regional patterns of climate change. Making reliable predictions of local or regional responses requires models of great complexity, but most calculations imply wetter subtropical monsoonal rain belts, longer growing seasons in high latitudes and wetter springtimes in high and middle latitudes which implies in greater crop yields in some areas. But, in other areas there could be drier midsummer conditions in the midlatitudes, increased probability of extreme heat waves and an increased probability of fires in drier/hotter regions. Increased sea levels over the next century could also be expected, the estimates here vary from several inches to several feet. There are potential health consequences for humans and animals in already warm climates with a reduced probability of ex-

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treme cold weather in colder areas. Most scientists do not debate whether global warming has occurred, they accept it, but the cause of the warming and future projections about the results is questioned. The proposed National Energy Policy Act of 1988, called for controls on industrial and agricultural emissions producing greenhouse gases. There were regulations to ensure energy efficiency, controls on deforestation, curbs on population growth and increased funding for energy alternatives, including nuclear power. In the early 1990s, the Information Council on the Environment, which was a group of coal and utility companies, used a public relations firm to push global warming as theory. The U.S. auto industry has also played a role since much lobbying took place to depose global climate change and fight legislation on fuel economy which is an important factor in carbon emissions. A global warming treaty was signed at the 1992 Earth Summit in Rio de Janeiro, Brazil. In this treaty, industrialized nations agreed by the year 2000 to voluntarily cut back their carbon dioxide emissions to the level they were at in 1990. To meet this goal, U.S. vehicles would need to be three to four times more efficient than they were, averaging about 80 to 90 MPG. By the 1990s, U.S. carbon emissions were rising while Americans were spending more time on the road and traveling in more of the least fuel-efficient vehicles. Minivans, SUVs, and pickup trucks made up about 40% of all vehicles sold in the United States. The average fuel economy of all cars and trucks in the United States in 2003 model year remains at about the same level since the decade of the 1990s. Today’s automobiles may be up to 96% less polluting than cars 35 years ago but automobiles still produce a quarter of the carbon dioxide generated annually in the United States. Although a global accord on reducing hydrocarbon emissions was reached at the 1992 Early Summit in Brazil only Great Britain and Germany came close to meeting their 2000 targets. The United States was short of its goal by 15 to 20%. This was a commendable effort at international cooperation but almost every country is filling its roads with more and more autos. The international agreement on global warming signed by 150 countries in Kyoto, Japan, in 1997 required a drastic reduction in automobile exhaust emissions. Greenhouse gases were to be reduced to 5.2% below 1990 levels by 2012.

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Objectors to Kyoto said it is based on questionable science and would damage the U.S. economy. It exempts two of the world’s biggest polluters, China and India, which together produce about as much CO2 as the United States. China and India have plans to build over 600 coal-fired plants. The emissions of these plants could be 5 times the total saving of Kyoto. Tightening the corporate average fuel economy (CAFE) standard for cars and trucks would be one requirement since a 12-mile-per-gallon car or truck emits four times as much carbon dioxide as a 50-mile-per-gallon subcompact. The auto industry has always resisted attempts to tighten CAFE and certain vehicles like SUVs and pick-up trucks have not been subject to CAFE standards. The average fuel economy has declined since 1988, as the auto industry moved away from fuel-efficient smaller vehicles and pushed more profitable trucks and SUVs. The Coalition for Vehicle Choice (CVC) is a lobbying group sponsored by carmakers, which has pushed to rescind the CAFE standards. The CVC has stated that CAFE causes 2,000 deaths and 20,000 injuries every year by forcing people into smaller cars. The auto industry has questioned the science behind global warming and claimed there are not enough facts to allow a judgment. Toyota was the first auto company to announce, in 1998, that it was joining others such as British Petroleum, Enron, United Technologies, and Lockheed Martin in an alliance to fight global warming. The question is not if the greenhouse effect exists, it pivots on the theory that emissions have an effect on global warming. Many reports concern the effects of global warming, many of these go unchallenged but some are questioned and reported on. The general agreement on climate change and hurricanes is that hurricanes may not become more common but that they may increase in intensity. The theory and hypothetical effects of global warming have become a reality to many. In 1979 the National Academy of Sciences undertook its first rigorous study of global warming, through the nine-member Ad Hoc Study Group on Carbon Dioxide and Climate. The panel concluded that if carbon dioxide continues to increase, there was no reason to doubt that climate changes would result and that these changes would not be negligible. Since then, global carbon-dioxide emissions have continued to rise, along with the planet’s temperature. But in 2007 temperatures appeared to decrease, still most major glaciers in the world are shrinking.

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Two global climate models show that even if the concentrations of greenhouse gases in the atmosphere had been stabilized by the year 2000, we were already committed to further global warming. No matter what is done at this point, global temperatures may continue to increase in the coming decades although there has been no major temperature changes measured in the upper atmosphere. There may be changes in monsoon patterns, ocean currents, or major droughts which will all be blamed on global warming. Many activists and environmentalists believe that climate change is the major threat facing human civilization in the 21st century and that institutions are doing little to battle the problem. Climate change has become a burning issue, but given the way some environmentalists and others exploit it, and the inaccurate record of past predictions of ecological disaster, skepticism is still a reasonable position. The hyping of the issue may even have begun to backfire on environmentalists. A 2004 Gallup Poll indicated that there was declining public interest in global warming. Part of this may be the inability of the scientific community to provide a probability estimate of either a rise in temperature or the effects of such a rise, either regionally and globally. This tends to show how limited the present knowledge of the world’s climate actually is. If the basic theory of global warming is correct, then much more work is needed to provide a true understanding of regional and global climate change. During the past millennium the average global temperature was essentially flat until about 1900, then spiked upward, like the upturned blade of a hockey stick. Some view this as a clear indication that humans are warming the globe, but others hold that the climate is undergoing a natural fluctuation not unlike those in past eras. One theory is that farming practices started global warming. Many point to human actions that first began to have a warming effect on Earth’s climate in the past century. But other evidence indicates that concentrations of carbon dioxide began increasing about 8,000 years ago, in spite of natural trends indicating they should have been decreasing, and that methane began to increase in concentration about 3,000 years later. In the past few decades methane increases seem to be leveling at about 1.7 parts per million in the atmosphere. There is an effort to tighten up estimates of how the Earth will respond to climate warming. The sensitivity of new climate models has improved, but to fully understand the Earth’s response to climate warming, a better knowledge of clouds and aerosols is needed, as well as improved

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and more and better records of past climate changes and their drivers. Some studies indicated that between 1900 and 2100, temperatures will increase between 1.4 and 5.8°C. Many scientific questions remain regarding climate change for both policy makers and the public. CLIMATE SHIFTS The climate may shift into radically different states according to ice cores extracted from Greenland’s massive ice sheet. These rods of ice, up to three kilometers long provide a set of climate records for the past 110,000 years. The annual layers in the ice cores are dated using a variety of methods and the composition of the ice provides the temperatures at which it formed. These cores show a record of wild fluctuations in climate, long deep freezes alternating with brief warm spells. Central Greenland has experienced cold spikes as great as six degrees Celsius in just a few years. It has also experienced almost half of the heating sustained since the peak of the last ice age (more than 10 degrees C) in just one decade. This spike occurred about 11,500 years ago and is the difference in temperature between Moscow and Madrid. Warming spikes appear more than 20 times in the Greenland ice records. During the colder periods, icebergs moved as far south as Portugal and one of the cold spells probably forced the Vikings out of Greenland. This period is known as the Little Ice Age, which lasted from about 1400 to 1900. Cold periods in the north brought drought to Saharan Africa and India. About 5,000 years ago a sudden drying spell changed the Sahara from a green region spotted with lakes to a hot sandy desert. In more modern times, changing patterns in the North Pacific have been strong enough to cause severe droughts, such as the one that triggered the U.S. dust bowl of the 1930s. REDUCING EMISSIONS Seattle, Portland, San Diego, Salt Lake City, Austin and Minneapolis are among the cities that have implemented programs to cut carbon dioxide emissions along with Boulder and Fort Collins, Colorado; Burlington, Vermont; Cambridge, Massachusetts, and New Haven, Connecticut. Chi-

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cago and Los Angeles have also adopted Climate Protection Programs. San Francisco plans to reduce its greenhouse gas emissions by more than 2.5 million tons with mass transit and hybrid vehicles, energy conservation, green building codes and solar power for buildings and homes. Seattle’s municipally owned electric utility has adopted a climate-neutral program where it invests in emissions reductions programs around the world to offset its own carbon dioxide output. DuPont has reduced carbon emissions from its plants in the U.S. and around the world by 67% since the Kyoto treaty appeared. The company believes that these reductions have made their factories more efficient and prepared their businesses for future markets 2 to 5 decades from now. Electric power companies are also making changes. American Electric Power Company, one of the major utilities in the country, is building a $40-billion plant that uses coal gasification. The facility will turn coal into synthetic gas before burning it, sharply reducing emissions including carbon dioxide. Coal gasification is more costly compared with conventional coal-fired power generation but AEP says the plant considers environmental prospects over a 30-year life. General Electric has a partnership with power plant builder Bechtel to develop a standard commercial design for gasified coal generating systems. GE also acquired a subsidiary of Chevron Texaco that produces synthetic gas by infusing oxygen into the methane found in coal. Coal is the most abundant energy resource in the United States, China and other countries, but it is more polluting than other fuels. It is the source of 52% of America’s electricity and the worldwide use of coal is expected to grow 40% in the next few decades. The Pew Center on Global Climate Change thinks it is highly unlikely that the world’s energy needs can be met without coal. Research and business investment is up in making coal use a cleaner process. Energy price volatility and uncertainty are also forcing American industry to think more about the diversification of energy sources. Wind power is seeing more use in Europe. Denmark is using the North Sea coastal wind to turn electrical generators. GE shipped its 10,000th 1.5MW wind turbine in 2008 to NextEra Energy Resources for the Ashtabula Wind Energy Center in North Dakota. Wind turbine plants opened in Newton, Iowa; Brighton, Colorado; Little Rock, Arkansas; Muncie, Indiana; and Faribault, Minnesota, during this time period. The U.S. wind industry employed 85,000 workers by 2009 up from 50,000 in 2007. The

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U.S. now manufactures 50% of its wind turbines up from about 30% in 2005. By 2009 the global solar PV industry had over 8-GW of cell manufacturing which included 1-GW of thin-film capacity. The Spanish Olmedilla de Alarcon plant became the largest solar PV plant in the world. In 2008, 31 new Ethanol refineries came online in the U.S. bringing total capacity to 40 billion liters/year with an additional 8 billion liters/ year under construction. In the U.S. cellulosic ethanol plants totaled 12 million/liters per year with an additional 80 million/liters under construction. Canada had a capacity of 6 million/liters year and Germany, Spain and Sweden had an additional 10 million liters/year under construction. Europe has more than 200 biodiesel facilities in operation with an additional 3 billion liters/year under construction. Europe’s carbon market has been growing quickly after the 2005 introduction of tradable annual allowances for greenhouse gas emissions under the Kyoto treaty. In this market-based emission-trading system, light polluters can sell some of their surplus allowances to heavier polluters. This can result in a reduction of emissions at a lower cost than if each installation had been obliged to meet an individual target, but the allowances to produce one kilowatt-hour of coal-fired power can cost more than the coal itself. In 1950 the U.S. CO2 emissions were almost 40% of the global total. By 1975 this had dropped to about 25%, and by the late 1980s it was about 22%. If the U.S. held emissions constant at 1985 levels, a reduction of 15% from the emissions in 1995 and a 28% reduction from the forecast emissions in 2010, then global emissions would be reduced by only 3% in 1995 and 6% in 2010. Even if U.S. emissions were cut by 50% below the 1985 levels, global emissions would continue to grow and would drop by less than 15% in the year 2010. If the U.S. employed technology to reduce CO2 emissions, then the resulting cost reductions would provide a competitive advantage for a while and would then be imitated by foreign competitors. This could energize global emission reductions. The calls for a reduction of U.S. hydrocarbon use by 90% would eliminate 75% of America’s energy supply and are unrealistic. This 75% of U.S. energy cannot be replaced by alternative green sources in the near future. In spite of wide support and subsidies for decades alternative sources still provide a small percent of U.S. energy. The U.S. cannot continue

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to be a net importer of energy without losing its economic and industrial strength and its political independence. CARBON-FREE NUCLEAR POWER A Massachusetts Institute of Technology (MIT) study on the future of nuclear power argues that nuclear power could be an important carbon-free source of power. The study found that a survey of adults in the United States indicated that those who are very concerned about global warming are no more likely to support nuclear power than those who are not. Other evidence suggests that the responses in Europe would not be very different. The MIT report concluded that more of the public needs to understand the links among global warming, fossil fuel usage and the need for low-carbon energy sources. The DOE is predicting the need for 50% more electric power by 2030. This new demand could be met by nuclear power instead of pollutants spewing fossil-fuel plants. Worldwide power is anticipated to double by 2030 as more developing nations buy electrical products. Almost 50 reactors have been under construction in China, India, Russia and other nations. While important issues remain such as the toxic byproducts, nuclear power is in resurgence. The World Energy Council has said that meeting new demands for electricity while reducing the current level of emissions will require tripling the world’s nuclear plant capacity by 2050. Global-warming concerns are pushing a new interest in nuclear power. After a decade where no nuclear power plants came online in the United States, 31 new reactors are planned. Nuclear plants cost about $1.72 kilowatt-hour to operate according to the Nuclear Energy Institute while that figure is $2.21 for coal plants, $7.51 for gas and $8.09 for oil. The difference is due to fuel costs, which make up 78% to 94% of the cost for producing electricity at fossil-fuel plants but only 26% at nuclear plants. Although the price of uranium for nuclear plants has risen sharply, it has much less impact on overall costs. It is more expensive to build nuclear plants which cost $4,000 per kilowatt of output, compared with $2,700 for coal plants and $1000 for gas plants. It takes years to go through the regulatory process for a new nuclear plant, build it and obtain a license to operate. Any new plants conceived today may be 10 years away.

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Nuclear power presents many challenges. Progress toward the safe final disposition of nuclear waste must be attained. Tightening safeguards against the diversion of commercial technology to weapons use also must be given a high priority among all nations. All of these challenges can be met. Nuclear power plants have better safety records today and new generations of reactors have designs that improve safety even further. Debate continues about Yucca Mountain as a disposal site for nuclear waste, but the scientific community agrees that deep geological disposal sites are suitable for the disposition of spent fuel. Stronger international commitments hold the promise of preventing nuclear power from contributing to the proliferation of nuclear weapons. Nuclear energy can be less expensive and more environmentally sensitive than hydrocarbon energy, but it has been the victim of the politics of fear. The problem of high-level nuclear waste has been mostly created by government barriers to American fuel breeding and reprocessing. Spent nuclear fuel can be recycled into new nuclear fuel as is done in France and other countries. Reactor accidents have been greatly publicized, but there has not been one death associated with an American nuclear reactor accident. However, the dependence on automobiles results in more than 40,000 deaths each year. All forms of energy generation, including alternatives like solar and wind involve industrial deaths in the mining, manufacture, and transport of materials they require. Nuclear energy requires the smallest amount of resources and thus has the lowest risk of deaths. Nuclear power should be seen as part of the solution, bridging more advanced technology until other carbon-free energy options become more readily available. A variety of energy options should be pursued: increased use of renewable energy sources, carbon sequestration at fossil-fuel plants, improved efficiency of energy generation and use, and the increased use of nuclear power. Public misunderstanding is likely to begin in the political arena and a greater appreciation of the relation between nuclear power and emissions reduction is critical if the use of nuclear power is to be expanded. Environmental groups include a large and dedicated antinuclear majority and some environmentalists who might favor nuclear will vacillate over that view publicly. The nuclear industry may be impeded because power companies have been forced to rely on fossil-fuel plants for so long.

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FUEL CELL POWER Power generation is being advanced by fuel cell technology as many fuel cell generators are being marketed now. Fuel cells can be used to generate electricity, heat, and hydrogen. One fuel cell provider is FuelCell Energy uses a molten carbonate fuel cell. Some solid oxide fuel cell (SOFC) companies have been developing similar products. Fuel cells operate much like a battery, using electrodes in an electrolyte to generate electricity. But, unlike a battery, fuel cells never lose their charge as long as there is a constant source of fuel. Fuel cells are also flexible, like the batteries in a flashlight, the cells can be stacked to produce voltage levels to match specific power needs. Fuel cells can be used to power a variety of portable devices, from handheld electronics to larger equipment such as portable generators. Thousands of portable fuel cell systems have been developed and operated worldwide, ranging from 1 watt to 1.5 kilowatts in power. The two primary technologies for portable applications are polymer electrolyte membrane (PEM) and direct methanol fuel cell (DMFC) designs. The U.S. Department of Energy’s Office of Fossil Energy has had a joint program with fuel cell developers to develop the technology for stationary power applications which includes central power and distributed generation. The joint government-industry fuel cell program is aimed at giving the power industry a new option for generating electricity with efficiencies, reliabilities, and environmental performance beyond conventional electricity generation. In the 1970s and early 1980s, the program focused on the development of the phosphoric acid fuel cell system which is considered the first generation of modern-day fuel cells. Largely because of the support provided by the Federal program, United Technologies Corporation and its subsidiaries manufactured and sold phosphoric acid fuel cells throughout the world. In the late 1980s, the DOE shifted to the development of advanced higher temperature fuel cell technologies, especially molten carbonate and solid oxide fuel cell systems. Federal funding for these technologies resulted in private commercial manufacturing facilities and commercial sales. The Department of Energy formed the Solid State Energy Conversion Alliance (SECA) with a goal of producing a solid-state fuel cell module that would cost no more than $400/kW. This would allow fuel cells

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to compete with gas turbine and diesel generators. The plan is to develop a compact, lightweight, 3-kW to 10-kW building block module that can be mass-produced using many of the same manufacturing advances that have greatly lowered costs for electronics equipment. These building blocks would be clustered into a number of custom-built stacks for a variety of applications ranging from small portable power sources to megawatt generating systems. SECA is made up of fuel cell developers, small businesses, universities and national laboratories. It is administered by the Energy Department through the National Energy Technology Laboratory (NETL) and its Pacific Northwest National Laboratory (PNNL). The High Temperature Electrochemistry Center (HiTEC) Advanced Research Program provides crosscutting, multidisciplinary research supporting SECA, Fuel Cell Coal Based Systems, and FutureGen. HiTEC is centered at Pacific Northwest National Laboratory (PNNL) with satellite centers at Montana State University and the University of Florida. Research includes the development of low-loss electrodes for reversible solid oxide fuel cells, the development of high temperature membranes for hydrogen separation, and the study of fundamental electrochemical processes at interfaces. HiTEC is also pursuing the development of high temperature electrochemical power generation and storage technologies and advanced fuel feedstock. Distributed power has grown with stationary fuel cells that generate on-site power in critical areas: schools, apartment buildings or hospitals. The waste heat the fuel cell generates can be used in a cogeneration process to provide services like heating, cooling, and dehumidification. Instead of the 50% efficiency of a fuel cell with a reformer, or 60-70% without one, 90% or better is possible for the total system efficiency. In most situations, the waste heat is enough of a commodity to pay for a natural gas line and a mass-produced reformer to turn it into hydrogen. Then, the effective net cost of providing electricity to the building approaches a few cents per kilowatt hour. As the market for fuel cells grows, costs will come down and allow more economical fuel cells for transportation and power. Buildings use 2/3 of all electricity in the United States, so there is the possibility of large fuel cell volumes. Both the building and vehicular fuel cell markets are potentially so large that when either of them starts moving it will push the other. Stationary and mobile fuel cells could have a potential relation-

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ship beyond cost and volume. A fuel cell in a vehicle is a multi-kilowatt power generator, which is driven about 5% of the time and parked the other 95% of the time. Fuel cell cars could be used to provide power and even water to buildings where people live or work. Commuters could drive their cars to work and connect them to a hydrogen line. While they worked, their cars would be producing electricity, which they could then sell back to the grid. The car, instead of just occupying a parking space, could provide extra income. The idea of using cars as power plants would be revolutionary, but it is just an indication of how fuel cells could impact our lives. Most cars are used for a few hours of the day. When they are not used, they are often parked where electricity is needed near stores, homes or factories. If all cars were fuel cell powered, the total power generation capacity would be several times greater than the current U.S. power requirements. If the major source of hydrogen is reformed natural gas, the cost of generating electricity with a low-temperature fuel cell could be more than double the average price for electricity. It would also produce 50% more carbon dioxide emissions than the most efficient natural gas plants which are combined cycle natural gas turbines. Cogeneration also adds to the complexity of the vehicle and connecting a vehicle to the electric grid requires auxiliary electronics. Extracting useful heat would involve new ductwork and possibly heat exchangers. Most homes could probably use the heat from a fuel cell, and cars will probably have a 60/80-kW fuel cell. Home power generation with either a stationary or a mobile fuel cell may not provide any cost savings that would jump-start commercialization. Also, a method is needed to get hydrogen to your home or office to power the fuel cell after your car’s onboard hydrogen is consumed. For relatively small amounts of hydrogen, bottled hydrogen is likely to be expensive per kilogram. Fuel Cell Emissions Fuel cells are among the cleanest and most efficient technologies for generating power. Since there is no combustion, fuel cells do not produce any of the pollutants commonly emitted by boilers and furnaces. For systems designed to consume hydrogen directly, the only products are electricity, water and heat. If a fuel cell consumes natural gas or other hydrocarbons, it produces some carbon dioxide, though much less than burned fuel. Ad-

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vanced fuel cells using natural gas, for example, could potentially reduce carbon dioxide emissions by 60% compared to a conventional coal plant and by 25% compared to modern natural gas plants. This carbon dioxide is emitted in concentrated form which makes its capture and storage, or sequestration, much easier. Fuel cells are so clean that, in the United States, over half of the states have financial incentives to support their installation and the South Coast Air Quality Management District in southern California and regulatory authorities in both Massachusetts and Connecticut have exempted fuel cells from air quality permitting requirements. Several states have portfolio standards or set asides for fuel cells. There are major fuel cell programs in New York (NYSERDA), Connecticut (Connecticut Clean Energy Fund), Ohio (Ohio Development Department), and California (California Energy Commission). Certain states have favorable policies that improve the economics of fuel cell projects. For example, some states have net metering for fuel cells which obligates utilities to deduct any excess power produced by fuel cells from the customer’s bill. The goal of the DOE’s Fossil Energy fuel cell program is to develop low cost fuel cells with a cost of $400 per kilowatt or less. This is significantly lower than today’s fuel cell products. Fuel cells are not being installed in more applications because of their cost. The fuel cells used in the space program were very expensive and impractical for commercial power applications. Gas or diesel generation costs about $800 to $1,500 per kilowatt and natural gas turbines can be even less. A modern unit is General Electric’s 7H turbine, which is 40 foot long and, 400,000 pounds. It runs on natural gas and produces 50% more power than the earlier 7FA with lower NOx and CO2 emissions. Conventional gas turbines use air for cooling, but the 7H uses steam at 700 degrees F. The steam absorbs heat better than air which allows a higher peak operating temperature without increasing the temperature in the combustor, where most the unit’s greenhouse gases are produced. Two 7H turbines are used at Riverside, California, where they provide 775-MW for about 600,000 homes. The goal to cut costs to $400 per kilowatt would make fuel cells competitive for most power applications. The objective is to develop a modular, all-solid-state fuel cell that can be mass-produced for different applications.

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FUEL CELL GROWTH Fuel cells are receiving more acceptance around the world. In Italy, Centro Ricerche Fiat (CRF) is supplying Nuvera fuel cell-powered Panda vehicles to the municipality of Mantova as part of the Zero Regio demonstration project. The Pandas will use an ENI multi-fuel refilling station, offering pressurized hydrogen at 350 bar. In Japan a Toyota FCHV went from Osaka to Tokyo on one tank of fuel. The FCHV is Toyota’s latest version of its fuel cell hybrid vehicle. The distance of approximately 560 kilometers was covered on a single tank of hydrogen. The newer FCHV is 25% more fuel efficient than earlier versions, due to improvements in the high-performance fuel cell stack and in the control system that manages fuel cell output and battery charging/discharging. The 70Mpa high-pressure hydrogen tanks used are able to store almost twice the amount of hydrogen as previous tanks. General Motors has developed HydroGen4, the European version of the Chevrolet Equinox fuel cell vehicle. HydroGen4 is designed for a lifecycle of two years/80,000 kilometers, and can start and run at sub-zero temperatures which is a considerable advance from HydroGen3. The i-Blue Fuel Cell Electric Vehicle is Hyundai’s third-generation fuel cell technology which was developed at its Eco-Technology Research Institute in Korea. The i-Blue is powered by a 100-kW electrical engine and fuel cell stack. It is fueled with compressed hydrogen at 700 bar which is stored in a 115 liter tank. The i-Blue is able to run more than 600km per refueling and has a maximum speed of 165-km/h. Global Thermoelectric has a residential 2-kW fuel cell system and a 5-kW propane partial oxidation (POX) reformer that allows Global’s SOFC technology to use propane as a feedstock. The reformer is based on a natural gas fuel processor that was modified to reform propane. Global’s SOFCs can use propane reformat using partial oxidation reforming with only a minor impact on performance when compared to operating on hydrogen. Global also has a dual-stage, low-temperature adsorbent desulfurizer. Sulfur in propane can exceed as much as 300-ppm compared to natural gas, which ranges from 2 to 15-ppm sulfur and it must be removed to block any poisoning of the fuel cell. Test results indicate that no sulfur compounds were present in the outlet gas of the desulfurizer. The system uses a modular assembly and layout, including a circular hot box where the fuel cell stacks and the fuel processor are located and easily accessed.

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Code Restrictions Hydrogen-powered fuel cells have great potential as a clean and cost-competitive source of electricity. As this technology gets closer to widespread commercialization, there is concern that the use of fuel cells is being slowed by conflicting local and regional safety and building codes. Unresolved issues such as conformance with electrical, plumbing, fuel-management, and emissions rules and other safety considerations could hinder the efforts of companies that manufacture, sell, and install natural-gas-powered fuel cells for residential, industrial, and commercial applications. Companies such as United Technologies Corp. (UTC), Ballard Energy Systems, Plug Power, M-C Power, AlliedSignal, and Siemens-Westinghouse have been developing fuel cell products for the commercial market and may be impacted by this trend. There are existing standards covering electrical, fuel handling, and pressure issues applicable to fuel cells. But, there are almost no standards in place that address fuel cells specifically. The standards that do exist, such as those provided under American National Standards Institute (ANSI) Z21.83, only cover part of the product market. In the installation of fuel cells for residential use, the ANSI standard does not apply. If it were, some of the requirements could be excessive and push up costs. The standard may also miss problems unique to residential users. Besides the interest in safety, installation, and operational standards for fuel cells, there’s also a demand for performance standards measuring energy output, fuel consumption, efficiency, and emissions. The establishment of standards is important to product acceptance and broader public understanding of the overall safety of fuel cells. Residential fuel cells have potentially huge markets in North America and other parts of the world. Plug Power, LLC, a joint venture of DTE Energy Co., Mechanical Technology Co., of Latham, N.Y., and General Electric began mass production of 7-kW residential fuel cell units in 2001. The fuel cells are based on proton exchange membrane technology. Competitors include Ballard, UTC, and others. Proton Power Systems plc has developed the world’s first triplehybrid forklift system. The triple-hybrid system combines a fuel cell, a battery and supercapacitors to replace the standard battery package for the Class 1 forklift. A fuel cell system designed for backup power needs is the Electra-

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Gen XTi system which is available in 3 and 5 kilowatt outputs, and operates on HydroPlus, a fuel mixture of methanol and water chosen for its low reforming temperature, extremely low freezing temperature and industrial availability. IdaTech has installed a 5-kW ElectraGen 5XTR fuel cell backup system at Investec in London. The fuel cell system will provide extended run backup power to operate the building’s security during any power interruption. The fuel cell is integrated with a Chloride UPS system and installed in the loading dock of the Investec building. Plug Power has installed GenCore fuel cell systems for backup power for a New York State Police radio tower in eastern Rensselaer County. The units can provide 10 kilowatts of power, and have enough stored hydrogen to provide backup power for 72 hours without refueling. The emergency response radio tower requires approximately 7.5 kilowatts. Heliocentris Fuel Cells AG and SMA Technologie AG have developed a photovoltaic backup combined with a fuel cell system. The combination unites SMA’s Sunny backup system with a fuel cell system from Heliocentris to provide users with a photovoltaic installation, which feeds its electricity into the public network, linked with a standalone energy supply in the event of a power failure. Protonex Technology and Raytheon are developing a portable fuel cell power system for the U.S. Army. This will be a 250-watt portable fuel cell power source that is considerably smaller, lighter, quieter and more efficient than alternative battery or generator systems. PolyFuel has developed a fuel cell stack that is able to deliver a notable 500 watts per liter of stack volume, significantly advancing direct methanol fuel cells (DMFC). A stack which fits in the palm of the hand delivers a peak power of 56 watts which is more than twice that required by a typical laptop computer. NanoLogix uses hydrogen gas produced from its bioreactor prototype facility at Welch Foods in Pennsylvania to power a 5.5-kW generator. NanoLogix uses a fermentative approach in the microbial production of hydrogen, reducing or eliminating methanogens to increase the yield of hydrogen. The Voller Energy Group PLC and the University of Cambridge are developing a diesel, bio-diesel, kerosene or JP-8 fuel reformer. This will be used for fuel cell systems developed by Voller and will extend the range of fuels which can be processed to include hydrocarbons such as kerosene, diesel or JP-8.

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The Long Island Power Authority (LIPA) is installing fuel cell systems in Long Island homes. Twenty-five of the 5-kW fuel cell systems called GenSys5CS will be used at LIPA’s West Babylon Fuel Cell Demonstration Site, which currently has fuel cell systems feeding directly into the Long Island electrical grid. Another 20 systems will generate on-site heat and power for single or multi-family residential sites. The GenSys5CS unit transforms natural gas to hydrogen. LIPA is using the fuel cells for heat, power generation and backup supply, which will aid in achieving a goal of 25 percent of New York’s electricity needs supplied by alternative energy technologies. LIPA has been placing Plug Power fuel cells at commercial locations around Long Island, including Hofstra University and the Babylon and East Hampton Town Halls. Plug Power has delivered enough systems to generate over 1.6 million kilowatt-hours. Besides fuel cells, we can deploy large scale renewables to replace the use of fossil fuels, but the U.S. cannot do it alone, to actually affect emissions, it must be a worldwide effort including wind energy, conservation, better grids and limiting or improving coal-fired generation in the U.S. as well as the developing world. There is a need to accelerate the methods that will increase renewable generation capacity including affordable storage, geothermal energy from hot dry rocks, wave power, fusion and others. Wind and rooftop PV could ultimately become a cheap but relatively small component of the energy generation mix. Coal is the most abundant fossil fuel in the U.S. and many other countries. In the U.S. coal makes up about 95% of all fossil energy reserves. These reserves could last several hundred years at the current level of coal consumption. Major developing countries such as China and India, which are now using more and more of the world’s oil, also have large coal reserves. Coal is also a source of hydrogen. The coal is gasified and the impurities are removed so the hydrogen can be recovered. This results in significant emissions of CO2. Fluidized bed combustion is a newer technology that burns coal in an efficient manner and can produce both electricity and heat. A mixture of finely crushed coal and limestone rides on a stream of air, which allows the coal to be burned at temperatures lower than conventional coal burners. This reduces the nitrogen oxide produced. The limestone absorbs sulfur from the coal, which reduces the sulfur dioxide.

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SUPERCRITICAL COAL Supercritical coal-fired power plants have efficiencies of 45% and much lower emissions than subcritical plants for a given power output. Early experiences with supercritical plants in the U.S. indicated a poor availability since forced outages were greater than subcritical plants. However, the experience of plants in Japan, Europe, China and South Africa shows that these plants are just a reliable as subcritical plants. Worldwide, more than 400 supercritical plants are in operation. The differences between subcritical and supercritical power plants are limited to a few components, mainly the feedwater pumps and the high-pressure feedwater train equipment. The rest of the components are common to subcritical and supercritical coal-fired power plants and can be manufactured in developing countries. Power generated from coal currently accounts for about 40 percent of worldwide totals. Coal is an abundant fuel resource in many areas of the world and forecasts show that it is likely to remain a dominant fuel for power generation in many countries for years to come. Power plant suppliers have invested heavily in generation technologies that produce power more efficiently. Enhanced plants reduce the emissions of pollutants and carbon dioxide by using less fuel per unit of electricity generated. The efficiencies of older power plants in developing countries such as China and India are about 30% lower heating value (LHV), modern subcritical cycles have efficiencies close to 40% LHV. Further improvements in efficiency can be gained by using supercritical steam conditions. Current supercritical coal-fired power plants have efficiencies above 45% LHV. A one percent increase in efficiency can reduce by two percent targeted emissions such as NOx and CO2. Supercritical refers to the state of a substance where there is no clear distinction between the liquid and the gaseous phase (a homogeneous fluid). The efficiency in the thermodynamic process of a coal-fired power plant depends on how much of the energy that is fed into the cycle is converted into electrical energy. If the energy input to the cycle is kept constant, the output can be increased by selecting elevated pressures and temperatures for the watersteam cycle. Up to an operating pressure of about 19-MPa in the evaporator section of the boiler, the cycle is subcritical. At this point, there is a non-

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homogeneous mixture of water and steam in the evaporator section. A drum-type of boiler is used because the steam needs to be separated from water in the drum of the boiler before it is superheated and fed into the turbine. Above an operating pressure of 22.1-MPa in the evaporator section, the cycle is supercritical. The cycle medium is a single phase fluid with homogeneous properties so there is no need to separate steam from water in a drum. Once-through boilers are always used in supercritical cycles. Operating pressures of up to 30-MPa may be used, but this requires advanced steels for components such as the boiler and the live steam and hot reheat steam piping that are in direct contact with steam under these elevated conditions. Steam conditions up to 30-MPa at 600-620 degrees C are achieved using steels with 12% chromium content. Up to 31.5-MPa is possible with Austenite. Nickel-based alloys such as Inconel, allow 35-MPa at 700-720 degrees C, providing efficiencies up to 48%. Other improvements in the steam cycle and components may provide over 50% efficiency. These technologies include double reheating where the steam expanding through the steam turbine is fed back to the boiler and reheated for a second time as well as heat extraction from flue gases. The turbine designs used in supercritical power plants are not fundamentally different from the designs used in subcritical power plants. But, the steam pressure and temperature are more elevated in supercritical plants and the wall-thickness and the materials used for the high-pressure turbine section need special consideration. The turbine generator set must allow flexibility in its operation. Subcritical power plants using drum-type boilers are limited in load change rate because the boiler drum component requires a very high wall thickness but supercritical power plants using once-through boilers can provide quick load changes if the turbine is of a matched design. Once-through boilers have been favored in many countries, for more than 30 years. They can be used up to a pressure of more than 30MPa without any change in the process engineering. In the water-steam cycle equipment in subcritical and supercritical coal-fired power plants the differences are limited to a small number of components such as the feedwater pumps and the equipment in the high pressure feedwater train downstream of the feedwater pumps. These components represent less than 6% of the total value of a coal-

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fired power plant. There are more than 400 supercritical power plants operating in the U.S., Europe, Russia and Japan. The rapid introduction of very large plants in the U.S. in the early 1970s created problems in availability, due to forced outages, at these plants. The availability of supercritical plants is now equal or even higher than those of comparable subcritical plants. Several power plants operate with once-through boilers and supercritical steam conditions in developing countries. The South African utility ESKOM operates a number of once-through boilers and the 2x600-MW supercritical coal-fired power plant Shidongkou in the Shanghai area of China has been in operation since the early 1990s. Once-through boilers are better suited to frequent load variations than drum type boilers, since the drum is a component with a high wall thickness, requiring controlled heating. This limits the load change rate to 3% per minute, while once-through boilers can step-up the load by 5% per minute. This makes once-through boilers more suitable for fast startup as well as for transient conditions. One of the largest coal-fired power plants equipped with a once-through boiler in Germany, the 900MW Heyden power plant, is operating in two shift operation as is the 3x660-MW power plant in Majuba, South Africa. In once-through boilers various types of firing systems including opposed, tangential, corner, four wall, arch firing with slag tap or dry ash removal and fluidized bed are used to fire a variety of fuels including all types of coal as well as oil and gas. Once-through boilers do not need to have a boiler blowdown. This has a positive effect on the water balance of the plant with less condensate needing to be fed into the water-steam cycle and less waste water to be disposed of. All developing countries using coal in base load such as China and India have a large manufacturing capacity in the components for subcritical and supercritical plants. The turbine generator set and boiler for the 2 x 900-MW Waigaoqiao supercritical plant was built in China. The life cycle costs of supercritical coal-fired power plants are lower than those of subcritical plants. Current designs of supercritical plants have installation costs that are only 2% higher than those of subcritical plants. Fuel costs are considerably lower due to the increased efficiency and operating costs are at the same level as subcritical plants. Explicit installation costs including the cost per megawatt (MW) decreases with increased plant size. For countries like India and China,

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unit ratings from 500-MW up to 900-MW are possible due to their large electrical grids. In countries with smaller grids, unit sizes of 300-MW are more appropriate and the specific installation cost will be higher than that of larger plants. The world’s largest lignite-fired steam power plant Schwarze Pumpe in Germany has two 800-MW steam turbine generators designed for supercritical steam conditions of 25-MPa at 544-562 degrees C. The net efficiency of this plant is about 41% which is high for a plant using lignite. The Schwarze Pumpe concept was based on research by RWE Energie AG and VEBA Kraftwerke Ruhr AG. It is a twin unit plant of 2 x 800-MW and employs flue gas heat for condensate heating and dual train flue gas discharge via the cooling tower. Boiler feedwater is raised to a pressure of 320 bar by a single pump driven by a steam turbine before being fed through a multi-stage preheating zone and into the boiler at a temperature of about 270 degrees C. In the boiler the feedwater is further heated and then superheated to 547 degrees C. PLASMA GASIFICATION The recovery of energy from waste can be done with the plasma gasification and pyrolysis. These processes can convert almost any waste material into usable products such as electricity, ethanol and vitrified glass. This waste to energy system goes beyond incineration and standard gasification processes. Although plasma technology has been known for years, its application to garbage disposal was not considered since using landfills was less expensive even with tipping and transportation costs. Recently, with landfills becoming scarce and sharply rising transportation costs, plasma gasification is getting real consideration. Plasma gasification has the potential to use up most trash, leaving only energy and valuable materials. Taiwan, Japan, England, and Canada are already using the technology. There are more than 100 plasma gasification plants around the world and a similar number of gasification plants. Plasma arc gasification is the latest generation of thermal treatment techniques. A high voltage current is sent through a pressurized, inert

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gas, creating extremely high temperatures of up to 30,000 degrees Fahrenheit, which is three times as hot as the surface of the sun, in an arc of plasma. This plasma arc is able to atomize any type of waste excluding some very rare, high-energy nuclear wastes and converting them into elementary gases and an obsidian-like slag material. This process is highly exothermic so there is a surplus of energy produced, once the arc is initiated it feeds on itself. A high-voltage current is passed between two electrodes to create a high-intensity arc which rips electrons from the air and converts the gas into a plasma field of intense and radiant energy. This is the same process in fluorescent and neon lighting where a low voltage electric current is passed between electrodes in a sealed glass tube containing an inert gas which excites the electrons in the gas. The gas releases radiant energy and in electric arc welding this current passing between the welding electrodes creates a plasma that can melt metal. Plasma gasification and pyrolysis processes allow for the virtual elimination of landfills, recycling without sorting and the complete thermal conversion of all types of waste to energy in the form of green electricity or ethanol. There are over 70 different gasification processes, 36 plasma gasification processes, 5 pyrolysis processes, 3 hybrid thermal processes, 4 ethanol processes and 5 water distillation processes that are available. The various gasification and plasma gasification technologies have specific applications. Plasma gasification has fewer emissions than gasification and treats certain types of waste better. The waste may be gasified to produce synthesis gas (syngas), which can be used to produce electricity. The syngas can be used to make ethanol using certain gasification/pyrolysis processes. Waste steam from the steam turbine can also be used to make large quantities of pure distilled water. The EPA estimated in 2005 that 33% of our waste was recovered by recycling procedures. But, this figure does not include hazardous, industrial or construction waste if it did, many say the figure would be closer to 10%. About 70% of this ends up in landfills and the rest in incinerators. Landfills use practical methods of compacting, isolating, and maintaining trash deposits to maximize land use and minimize ecological damage. Landfill sites are also carefully evaluated for their suitability (the composition of the underlying bedrock is a major concern) and must be meticulously sustained (for example, most landfills require a fresh, six

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inch covering of soil everyday). In spite of careful planning and maintenance, landfills still emit large quantities of greenhouse gases. The anaerobic decomposition of solid waste releases methane and carbon dioxide almost in equal parts. Landfills have been the greatest man-made source of methane emissions over the past decade. Although much of the methane can be reclaimed and put to use as a renewable, green energy source it has not been done on any large scale in the U.S. Incinerators use combustion to reduce waste into ash, gas, and heat in a volume proportion of about nine to one. Incineration can handle types of waste deemed too dangerous to store in landfills, including biological and medical refuse. However, the often toxic ash produced by incineration and other thermal techniques must be landfilled as well, and in addition to greenhouse gases, other emissions such as dioxins pose health and environmental risks. New York City produces enough trash each day to fill the Empire State Building. The city relies on incinerators and landfills to dispose of the 36,000 tons of trash generated. The majority of this is contracted out to private industries, only 12,000 tons is handled by the Department of Sanitation. Since the closing of the Fresh Kills Landfill which was a large landfill in Staten Island in 2002, all municipal waste now goes to other states, specifically New Jersey, Pennsylvania, Virginia, Ohio, and South Carolina. Transport costs bring the costs up to $90 per ton of waste compared to an average of $35 for other areas. The emissions from gasification are syngas and can be converted onsite into hydrogen and other valuable gases. Startech, a developer of gasification technology, estimates that the sale of the power and hydrogen production would allow a profit of $15 from each ton of waste processed. This would help defray the $1.25 billion spent annually on the collection and disposal of New York City’s trash which is up from $660 million in 2000. Plasma gasification plants are operating in Taiwan, Japan, Canada, and England. Two plants are planned for Florida and another for Los Angeles. A plant that processes 2,000 tons of waste a day, which is what a city of one million produces daily, costs about $250 million to construct. In a plasma gasification plant, the trash is fed into an auger, which shreds it into smaller pieces, these are then fed into a plasma chamber which is a sealed, stainless steel vessel filled with either nitrogen or ordinary air. A 650-volt electrical current is passed between the electrodes which rips electrons from the air and creates the plasma.

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A constant flow of electricity through the plasma maintains a field of extremely intense energy powerful enough to break down the shredded trash into its component elements. The byproducts are a glass-like substance used as raw materials for high-strength asphalt or household tiles and the syngas mixture of hydrogen and carbon monoxide which can be converted into fuels such as hydrogen, natural gas or ethanol. The syngas leaves the converter at a temperature of about 2,200 degrees Fahrenheit and is fed into a cooling assembly which generates steam. The steam is used to drive turbines which produce electricity, part of which is used to power the converter, while the rest can be used for the plant’s heating or electrical needs, or sold back to the utility grid. Aside from the initial power supplied by the electrical grid, the system can produce the electricity it needs for operation. It also produces materials that can be sold for commercial use. The system could also be used to dispose of accumulated landfill garbage for land reclamation. The syngas can be used as a base for producing hydrogen in commercial quantities for fuel cells. COGENERATION AND FUEL CELLS Cogeneration combines the production of heat and the generation of electricity to provide a higher total efficiency than that of either process occurring separately. As the costs of fossil fuels and electricity continues to increase, cogeneration becomes more attractive. Cogeneration systems can use renewable fuel sources such as wood, waste products, wood, gas or methane from sewage and garbage. The Sun-Diamond plant in Stockton, California, used waste walnut shells into electricity for the plant and nearby homes. The walnut shells were used as fuel to produce steam to drive a turbine generator. The low-pressure steam output was then used for heat as well as to refrigerate the plant. The Sun-Diamond cogeneration system produced about 32 million kWh of electricity per year. It only used 12 million and sold the surplus power to Pacific Gas and Electric Company. Small-scale cogeneration units are those in the 5- to 20-kilowatt range. In smaller cogeneration units, more heat is supplied than can be used, so these systems may also include heat storage components. Largescale systems can be more cost-effective, but if cogeneration is properly sized and installed, it will cost less per unit of energy produced.

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As stationary fuel cells reduce their costs with continuing growth, they will be able to compete with other small- to medium-sized power generation sources for on-site generation, particularly cogeneration for factories and commercial buildings. Panasonic has developed a home-use polymer electrolyte fuel cell (PEFC) cogeneration system. The cogeneration system has a generating efficiency of up to 39% Lower Heating Value(LHV), a durability of 40,000 operation hours and 4,000 start-stop times, and a predicted lifetime of over 10 years. Large-scale field testing was conducted between 2006 and 2008. In a typical household, the new system can reduce energy consumption by about 22% and cut carbon dioxide emissions by 12%. In a year it can save over 3,200 kWh of energy and reduce carbon dioxide emissions by 330 kg. The three-year field tests also found that the system was often operated in a power output range between 500 W and 1 kW in ordinary households. The PEFC cogeneration system has an output range of 300 to 1000 W with a weight of 125 kg and a noise level of 41 dB while generating power. The hot water storage capacity is 200 L. Many studies indicate a large potential. A 2000 study for the DOE’s Energy Information Administration found that the total power needs for combined heat and power (CHP) at commercial and institutional facilities was 75,000 MW. Almost two thirds of these required systems of less than 1 MW. The California Air Resources Board AB32 scoping plan is based on the installation of 4000-MW on CHP units throughout the state. There would be a net green house gas reduction by using CHP units since they would replace large boilers providing only steam for industrial uses. Replacing these boilers with CHP units supplies some of the facilities power needs along with steam. These systems are a good match for fuel cell generation. The remaining power needs in the industrial sector are almost 90,000-MW. This does not include heat-driven chillers or systems below 100-kW. In South Windsor, Connecticut, funding from the Connecticut Clean Energy Fund was used to install a natural gas powered 200 kW PC25 fuel cell system, from UTC Fuel Cells, at the South Windsor High School. The system provides heat and electricity to the high school. The Department of Defense (DOD) Fuel Cell Demonstration Program is managed by the U.S. Army Corps of Engineers. It was begun in

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the mid-1990s to advance the use of PAFCs at DOD installations. Under this program, stationary fuel cells were installed at 30 facilities and locations in the Armed Services. The fuel cells are used for primary and backup power as well as heat. The competition is entrenched in very mature, reliable, low-cost technologies compared to fuel cells and many barriers exist to impede their widespread use as small-scale CHP systems. These existing technologies and existing companies can be formidable for the spread of new technologies and new companies. On-site combined heat and power includes turbines, reciprocating engines and steam turbines. Gas turbines in the 500-kW to 250-MW range produce electricity and heat using a thermodynamic cycle known as the Brayton cycle. They produce about 40,000-MW of the total CHP in the United States. The electric efficiency for units of less than 10-MW, is above 30%, with overall efficiencies reaching 80% when the cogenerated heat is used. They generate relatively small amounts of nitrogen oxides other pollutants. Several companies have developed very low NOx units. Their high temperature exhaust may be used to make process steam and operate steam-driven chillers. A 1-MW unit can cost $1,800/kW installed while a 5-MW unit may cost $1,000/kW installed. In these systems, the turbine generator is about 1/3 of the total cost with the other costs including the heat recovery steam generator, electrical equipment, interconnection to the grid, labor, project management and financing. Reciprocating engines are another mature product used for CHP. These stationary engines may be spark ignition gasoline engines or compression ignition diesel engines. Capacities range from a few kilowatts to over 5-MW. Natural gas or alcohol fuels may also be used in the spark ignition engines. Electrical efficiency ranges from 30% for the smaller units to more than 40% for the larger ones. Reuse of the waste heat can provide overall efficiencies to 80%. The high-temperature exhaust of 700°F-1,000°F can be used for industrial processes or an absorption chiller. About 800-MW of stationary reciprocating engine generation is installed in the United States. Development has been closely tied to automobiles and in the last few decades increases in electric efficiency and power density have been dramatic as well as emission reduction. Some units can even meet Califor-

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nia air quality standards when running on natural gas. A 100-kW reciprocating engine generating system may cost $1,500-kW installed, while an 800-kW unit can cost $1,000-kW. The engine is about one fourth of the total price with the rest going to the heat recovery system, interconnect/ electrical system, labor, materials, project management, construction and engineering. A gas turbine power plant requires hot, high-pressure gases produced by burning oil or natural gas. The hot exhaust gases can be used to create steam in a boiler system. The efficiency can approach 90% if the system is properly designed. The Chuck Lenzie Generation Station near Las Vegas is a natural gas plant with four General Electric 7FA turbines, exhaust from the turbines is used to produce steam for two General Electric D-11 steam turbines. The nearby Harry Allen Generating Station was originally a single cycle plant. It is being expanded to include two General Electric 7FA turbines with the exhaust used to produce steam for a General Electric D11 steam turbine. About a one-hour drive from Las Vegas is the Edward W. Clark Generating Station, a multi-technology natural gas complex with 19 generating units. The oldest unit is a General Electric MS-7000 turbine generator now used for peak summer demands. The plant has four upgraded Westinghouse 501B6 turbine generators that use their exhaust heat to power two Mitsubishi steam turbines for electric power. The newest units include 12 FT8 Pratt & Whitney peaking units that can provide up to 600MW for short-term requirements. Fiat has its TOTEM (Total Energy Module) using a four-cylinder automobile engine that burns natural gas and other fuels, including liquid petroleum gas (LPG) and alcohol. It has a heat recovery efficiency of about 70% and an electrical generating efficiency of about 25%. The heating efficiency is similar to a conventional heating system, but since the unit also generates electricity its total efficiency is over 90%. The 380 volt, 200 amp asynchronous generator unit can produce 15 kilowatts of electrical power and heat 4 to 10 apartments. Larger systems that produce 50 to 100 kilowatts can heat larger apartment buildings. They are fueled by natural gas or diesel fuel. Units of 200 to 2,000 kilowatts that operate on fuel oil or diesel fuel are suitable for large apartment buildings or small district heating systems. The heat from a cogeneration unit can be used as a heat pump source, with electricity from the unit powering the heat pumps. If some of the electricity gen-

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erated is used for space heating, the system can be downsized by about 1/3. If the electricity is used to power water source heat pumps, an even smaller system is required. Cogeneration equipment must be safely connected to the utility grid. Utilities have objected to independent power generation by arguing that safety hazards can exist for their workers if independent systems continue to operate during system-wide blackouts. Such problems can be avoided by the installation of appropriate, standard safety equipment at the cogeneration site. A cogeneration system may use different fuels including natural gas, residual fuel oil, heating oil, diesel fuel and gasoline. Alternate fuel sources also include coal liquids, wood gas and plant derived alcohol. Ceres Power has an integrated, wall-mountable combined heat and power unit (CHP). The integrated CHP Unit is capable of generating electricity and all of the central heating and hot water requirements of a typical home, avoiding the need for a separate boiler. The CHP Unit uses the same natural gas, water and electricity connections as a boiler, and is thus easy to install. Ceramic Fuel Cells Limited (CFCL) has developed a fuel cell combined heat and power (CHP) unit that can be fitted into homes in the U.K. CFCL also collaborated with Nuon NV and De Dietrich-Remeha Group to jointly develop a fully integrated micro-combined heat and power (mCHP) unit for the residential market in the Netherlands and Belgium. A typical fuel cell system that is commercially available in the United States is the 200 kilowatt PAFC unit produced by UTC Fuel Cells. This is the type of unit used to provide electricity and heat to the U.S. Postal Service’s Anchorage Mail Handling Facility. In 2000, the Chugach Electric Association installed a 1 megawatt fuel cell system at the Anchorage Mail Handling Facility. The system consists of five natural gas powered 200-kW PC25 fuel cells developed by UTC Fuel Cells. The fuel cell station provides primary power for the facility as well as half of the hot water needed for heating. Excess electricity from the system flows back to the grid. A steam turbine power plant uses high-pressure steam produced in a boiler from burning fossil fuels or product waste to generate electricity. The low-pressure steam output can be for heating. The efficiency for this process can approach 85%. In a diesel engine generator, waste heat can be recovered from the water-filled cooling jacket around the engine or from the exhaust gases.

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This heat can be used to heat water or to produce steam. Diesels often have lower efficiencies than either gas or steam turbans, but with cogeneration the total conversion efficiencies reach 90%. They are also capable of generating more electricity than comparable gas or steam turbines and are more appropriate for small-scale applications. One potential problem with diesel cogeneration is air pollution, but the newer diesel engines are cleaner than those produced in the past. Steam turbines are an even older technology, providing power for over 100 years. Most utility power is produced by steam turbines. The steam turbine generator depends on a separate heat source for steam, often some type of boiler, which may run on a variety of fuels, such as coal, natural gas, petroleum, uranium, wood and waste products including wood chips or agricultural byproducts. Steam turbine generators range from 50 kW to hundreds of megawatts. By 2000, almost 20,000 MW of boiler and steam turbines were used to provide CHP in the United States. For distributed generation, a boiler and steam turbine system can be expensive. But, a process that already uses a boiler to provide high pressure steam can install a back pressure steam turbine generator for low cost, high efficiency power generation. The pressure drops in the steam distribution systems are used to generate power. This takes advantage of the energy that is already in the steam. A back-pressure turbine is able to convert natural gas or fuels into electric power with an efficiency of more than 80%, which makes it one of the most efficient distributed generation systems. The CO2 emissions are low as well as pollution emissions. The installed capital cost for these systems is about $500/kW. High efficiency, low cost and low maintenance allow these back-pressure installations to have payback times of two or three years. In the 1930s the government tried to encourage electrical generation by allowing monopolies to power generators. The rate-setting formula they created actually penalizes efficient generation. If a utility buys less fuel because of better efficiency, their costs are less so rates must come down. The clean air act also makes it risky for utilities to make efficiency improvements since it invites regulators to tighten emission controls as conditions for approval. The clean air act regulates the percent of pollutants (PPM) not the amount per kilowatt-hour (kWh) output. If you double efficiency, the amount of pollutants you are allowed will be halved. Pollution standards could be changed to an output-based standard, such as grams per megawatt-hour (g/MWh). In Europe there is a $6 billion project called Lo-Bin to develop a 98% efficient geother-

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mal power project based on these concepts. Where it isn’t convenient to pipe hot water or steam, an ORC generator can convert the waste heat to power. The generator acts as an air conditioner running in reverse. The heat boils a low boiling point liquid to operate a turbine generator. Small ORC generators are beginning to appear on the market. The ORC (Organic Rankine Cycle) Turbine Generator is a closed cycle electrical power generation system driven by an external heat source, no internal combustion is needed. An organic chemical refrigerant type is used in the closed cycle. The FREEPOWER Microturbine Generator System uses a highspeed generator similar to a car alternator which is directly coupled to a multi-stage turbine. The turbine is driven by high pressure hot gas. The gas or working fluid is a refrigerant which, in liquid state, is pumped from a reservoir by an electric pump into a compact heat exchanger, where it is heated and vaporized by a source of waste heat. It then passes to and drives the turbine, losing heat and pressure. Next, it passes into the first of two small heat exchangers where it gives up most of the residual heat to preheat the liquid working fluid, and then to a second small heat exchanger where it condenses back to a fluid, and then to the electric pump to begin the cycle again. The system is closed so no working fluid is lost to the atmosphere. The efficiency of the system, heat to electricity, is 10% at 110 degrees C to more than 22% at 270 degrees C. The system can be driven by any external source of heat including hot air, steam, hot exhaust gases, manufacturing waste heat and solar thermal energy. The FREEPOWER system was developed to run on low grade waste heat. Solar thermal heating and hot water are popular in China where the cost of rooftop solar collectors has become very competitive. Fifty million rooftops have solar thermal collectors and this is growing by 25% per year. The collectors are generally arrays of concentric glass tubes with an insulating vacuum between them. A hot water tank provides energy storage since these systems could be converted to also provide power by adding an ORC generator. Combined Heat and Power (CHP) cogeneration can be done in the home with 85% efficiency. Honda has sold over 45,000 of its Freewatt micro-CHP home heater/generators in Japan. The generator uses a quiet, natural gas powered, internal combustion engine that has about 20% efficiency. The unit is installed in place of the furnace and runs only when

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heat is needed. When it is running, it puts out 1200 watts of power. A company called Cool Energy has a small-scale solar thermal CHP system that uses evacuated tube collectors for the solar heat gain and a Stirling engine for power generation. The system provides a building with solar space heating in the winter months and power generation in the summer months. The heating and power functions are set with a controller that uses the heat in the most cost-effective manner. The market for these systems are areas with high heating and electricity costs, such as the Northeast and mid-Atlantic regions, where system paybacks are twice as fast as for other technologies. Electric utilities have tended to view small power producers as competitors. The Public Utilities Regulatory Policy Act (PURPA), which did not cover certain diesel engines, requires utilities to buy surplus power from and to supply back-up power to small power producers and cogenerators. When the local utility learns that a company is considering cogeneration, it sometimes offers a lower electricity rate in return for an agreement not to cogenerate for a certain period of time. This is especially true for bigger projects. A lower utility bill reduces the future energy cost savings from the CHP project and thus reduces the return on investment and increases the payback time. Other barriers to distributed energy projects besides costs include project complexity and regulations. A report by the National Renewable Energy Laboratory studied sixty-five distributed energy projects and found that various technical, business practice, and regulatory barriers can block distributed generation projects from being developed. These barriers include lengthy approval processes, project-specific equipment requirements and high standard fees. Distributed projects are not always given the proper credit for their contributions in meeting power demand, reducing transmission losses and improving environmental quality. In New York City the New York Power Authority (NYPA) and MTA New York City Transit (NYC Transit) are powering an expanded subway and bus maintenance facility with a 200-kilowatt (kW) fuel cell. The stationary fuel cell produces enough electricity to displace some 2,800 barrels of oil per year. Fueled by natural gas, the 200-kW fuel cell will be a continuous source of power. The residual heat of almost 700,000 Btu per hour will be used for the shop’s domestic hot water system. In case of a power disruption, the fuel cell will automatically supply electricity to the building’s non-emergency lights.

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The New York State Public Service Commission approved a Renewable Portfolio Standard (RPS) providing for increased use of renewable energy sources, including fuel cells. The project in Queens will help to implement the vision that 25 percent of the state’s energy come from renewable sources by 2013. The maintenance facility includes lay-up tracks, circuit breaker houses, a signal relay room and a car washer to service the 7 Flushing Line. The facility is the first major maintenance facility with sustainable Green design. Integrated into the design are photovoltaic roof cells, natural light and ventilation, motion detector light switches and a storm water retention system to wash the subway car fleet. Combined with other sustainable green design elements, NYC Transit expects to use 36% less energy over the life of the new facility. This project adds to NYC Transit’s use of clean energy power sources. NYPA has installed a 300-kW roof-mounted solar power array at the Gun Hill bus depot in the Bronx. During warm weather months, the solar array supplies 15 percent of this bus depots’ electrical needs. NYC Transit has been using solar energy to provide power to the Maspeth Warehouse Facility in Queens and the Jackie Gleason Bus Depot in Brooklyn since the late 1990’s. NYC Transit also has a 100-kW solar canopy at the reconstructed Stillwell Avenue Terminal in Coney Island. The New York Power Authority is the nation’s largest state-owned electric utility, with 18 generating plants in various parts of the state and more than 1,400 circuit-miles of transmission lines. The New York Power Authority is a major national proponent of clean distributed energy technologies with 2.4 megawatts of installed capacity. It has installed 11 fuel cells in the New York City metropolitan region including eight at wastewater treatment plants, operated by NYC, where the units generate power using as fuel the gases produced through the wastewater cleansing process. NYC Transit became a full signatory of the International Association of Public Transportation’s (UITP) charter on Sustainable Development in Mobility in 2004 and was the first public transit agency in the world to attain international certification for environmental management (ISO 14001). The Minnesota Power Biomass Initiative is a long-range energy plan to add renewable generation to the Minnesota Power’s portfolio. Several biomass opportunities were screened to advance the most economically feasible projects. The initiative includes a 50 megawatt biomass fueled unit at the Laskin Energy Center in Hoyt Lakes, using biomass

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fuel at Minnesota Power facilities and developing projects at customer sites which provide process improvements and generation additions. The electricity from biomass will be produced by the combustion of material such as wood waste and forest residue. State legislation requires all electric utilities in Minnesota to generate 25% of its energy through the use of renewable fuel by 2025. A cogeneration unit may fall under the provisions of one or more environmental and regulatory acts that cover power generation and industrial installations. Most systems of 5 to 100 kilowatts are likely to be exempt from environmental regulations except local building and zoning codes. Larger systems with a capacity in the area of some 500 to 2,500 kilowatts must comply with emission limits for five pollutants: nitrogen oxides, sulfur dioxide, small suspended particulates in the air, carbon monoxide and the photochemical oxidants found in smog. State regulations may also apply to small cogeneration systems. Regulations that affect small cogeneration systems include those governing noise pollution, water discharge and solid waste disposal. Systems with a generating capacity of 75,000 kilowatts or less are exempt from most federal regulations governing power generation. Systems larger than about 75,000 kilowatts, or that sell 25,000 kilowatts or 1/3 of their generating capacity must comply with the Environmental Protection Agency’s Stationary Sources Performance Standards for Electric Utility Steam Generating Units. In densely populated areas, a large cogeneration system may be required to comply with emission standards and install pollution control technology. There may also be noise pollution standards and water, air discharge and solid waste disposal permits. TRIGENERATION Trigeneration combines heat, cooling and power using absorption chillers as an alternative to conventional refrigeration. Combining high efficiency, low emission power generation equipment with absorption chillers allows maximum fuel efficiency, elimination of HCFC/CFC refrigerants and reduced overall air emissions. As with cogeneration, the waste heat byproduct that results from power generation is utilized, thus increasing the overall efficiency of the system. Trigeneration can also involve the production of electricity, heating, cold and some product mainly chemicals and gasses.

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Often space heating and hot water storage tanks are used as a heat sink for waste heat utilization. In summer, heat demand is low but the heat of the generation process can be converted into cooling energy by an absorption chiller. In warm climates the need for heating is limited to a few winter months. There is a significant need for cooling (air conditioning) during the summer months. Heat by a cogeneration plant in this case can be used to produce cooling, via absorption cycles. This expanded cogeneration process is known as trigeneration or combined heat, cooling and power production (CHCP). Trigeneration is sometimes referred to as CCHP (combined cooling, heating, and power generation). A newer American acronym is BCHP, Building Cooling, Heating and Power, for trigeneration applications in buildings. In a cogeneration system with an absorption refrigeration system that utilizes seasonal excess heat for cooling, the hot water from the cooling system of the cogeneration unit serves as the drive energy for the absorption chiller. The hot exhaust gas from a gas engine can also be used as an energy source for steam generation, which can then be used as an energy source for a highly efficient, double-effect steam chiller. Up to 80% of the thermal output of the cogeneration unit is converted to chilled water. The year-round capacity utilization and the overall efficiency of the cogeneration unit may be increased significantly. GE uses a Jenbacher engine for refrigeration which is fueled by natural gas, the Jenbacher module sends waste heat through a peak load boiler to absorption and compression refrigeration equipment, while generating electricity for on-site consumption. References

Alley, Richard B., “Abrupt Climate Change,” Scientific American, Volume 291 Number 5, November 2004, p. 64. Appell, David, “Behind the Hockey Stick,” Scientific American, Volume 292, pp. 34-35, March 2005. Cape Cod Trigen, Distributed Energy Magazine, Sept./Oct. 2007, p. 18. Collins, Will D., Gerald A. Meehl, and Warren M. Washington, “How Much More Global Warming and Sea Level Rise? Science, Volume 307, pp. 1769-1772, March 18, 2005. Cothran, Helen, Book Editor, Global Resources: Opposing Viewpoints, Greenhaven Press: San Diego, CA, 2003. Gelbspan, Ross, “Boiling Point: Excerpt from The Boiling Point,” The Nation, Volume 279, pp. 24, August 16-23, 2004. Gore, Albert; Nancy Pelosi; and Harry Reid, June 29, 2007, “The Seven Point Live Earth Pledge, Speaker of the House. Greenblat, Alan, “Say Hello to Kyoto,” Governing, Volume 18, p. 63, September 2005. Halweil, Brian, “The Irony of Climate,” World Watch, Volume 18, pp.18-23, March/April 2005.

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Hayward, Steven F., “Cooled Down: Global Warming.” National Review, Volume 57, pp. 3639, January 31. 2005. Kolbert, Elizabeth, “The Climate of Man—III: Stabilizing Carbon Dioxide Emissions.” The New Yorker, Volume 81, pp, 52-63, May 9, 2005. Kolbert, Elizabeth, “Storm Warnings: Global Warming and Hurricanes.” The New Yorker, Volume 81, pp. 35-36, September 19, 2005. Kunzig, Robert, “A Sunshade for Planet Earth” Scientific American, Volume 299, Number 5, pp. 46-55, November 2008. Levine, Joshua, “A Pro-nuke CEO Crusades for a Greener World” Forbes, Volume 180 Number 5, September 17, 2007. Michaels, Patrick J., “The Global-Warming God: Research Pertaining to Cause of Hurricanes.” National Review, Volume 57, pp. 24-28, October 10, 2005. Pierrehumbert, Raymond T., “Warming the World.” Nature, Volume 432 p. 677, December 9, 2004. Pinholster, Ginger, “Facing the Impact of Global Warming,” Science, Volume 304, pp. 19211922, June 25, 2004. Pope, Carl, “Global Thawing,” Sierra, Volume 90, pp. 10-11 May/June 2005. “Projected Costs of Generating Electricity, 2005 Update,” Nuclear Energy Agency, OECD Publication No. 53955: Paris, France, 2005. Reiss, Spencer and Peter Schwartz, “Nuclear Now: How Clean, Green Atomic Energy Can Stop Global Warming,” Wired, Volume 13, pp. 78-80, February 2005. Ruddimaan, William F., “How Did Humans First Alter Global Climate?” Scientific American, Volume 292, pp. 46-53, March 2005. Schiemeir, Quirin, “Trouble Brews over Contested Trend in Hurricanes.” Nature Volume 435, pp. 1008-1009, June 23, 2005. Schneider, Stephen Henry, Global Warming, Sierra Club Books: San Francisco, CA, 1989. Schueller, Gretel H., “For the Earth, the Heat Is One.” Popular Science, Volume 266, pp. 52-53, January 2005. “The Future of Coal—Options for a Carbon Constrained World,” An Interdisciplinary Massachusetts Institute of Technology (MIT) Study, Released: March 14, 2007. http://web.mit.edu/coal/ Vogel, Jennifer, “Extreme Weather,” E: The Environmental Magazine, Volume 16, pp 16-19, May/June 2005. Wang, Jone-Lin and Hansen, Christopher J., “Is the ‘Nuclear Renaissance’ Real?,” Cambridge Energy Research Associates (CERA), Cambridge, MA, April 4, 2007. http://www/coolenergyinc.com http://www.edmunds.com/insideline/do/News/articleId=121541 http://www.heliocentris.com/en/news http://www.idatech.com/press180932169.asp http://www.idatech.com/Media-Center-Investec.asp http://www.nanologixinc.com/pr-9-17-07-HistoricalFirstinEnergy- Welch.htm http://www.nuvera.com/news/press_release.php?ID=33 http://www.plugpower.com/news/press.cfm http://www.polyfuel.com/pressroom/press_pr_092507.html http://www.protonex.com/09-12-07%20Raytheon%20US.pdf http://www.toyota.co.jp/en/news/07/0928.html http://www.voller.com/press.asp

Chapter 3

Building Trends Keywords: Energy Management Building Automation Systems Building Control Trends Managing Power Shedding Loads Heating Efficiency Trends

District Heating Techniques Seasonal Energy Storage Solar Storage Low Energy Cooling Sustainable Building Green Roofs

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eriods of slow growth and recession in 1990 and 2008 forced industry to cut costs and reorganize. There were cutbacks, layoffs and delayed purchases for capital equipment. This reduction of personnel usually pressures the surviving departments to increase automation and become more efficient. The financial staff analyzes operations more closely and offers areas that might be improved. These economic factors along with technological advances in electronics and control hardware allowed plant automation changes in the 1990s that were not possible before and are expected to produce similar changes in the near future. As companies find new ways to lower the once fixed cost of their energy use, newer options also allow companies to protect themselves against unexpected power outages. In Somerset, KY, Toyitetsu America is an automotive stamping division of Toyota. It recently installed an air conditioning and filtration system for its 330 welding stations. Electrical power demands were reduced by using a variable frequency drive for each air collector unit which automatically adjusts the air based on filter loading. The new filtration system showed immediate utility savings which are expected to approach $700,000 annually. 81

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ENERGY MANAGEMENT The growth of energy control systems spiked during the energy crisis of the 1970s, along with the shortages of imported oil triggered which restricted energy use and led to more efficient energy management and control techniques. The development of the modern energy management system (EMS) occurred during this period for monitoring energy usage. These systems continue to grow over the years in both sophistication and scope. Another energy management system appeared in the 1980s called building automation systems (BAS). These systems included historical data, trend logging and fire and security functions in addition to conventional energy management functions. Direct digital control (DDC) systems appeared in the mid-1980s and replaced older analog closed-loop schemes for temperature control. These digital systems improved both accuracy and reliability. The earlier systems did not contain intelligent, standalone field devices. There were numerous interfaces to the various building systems and the major decisions were made at a central computer. BUILDING AUTOMATION SYSTEMS Modern building automation systems (BAS) have limited interfaces in order to provide a more seamless, integrated network. Ideally, all of the various components communicate with each other in a common language. Several levels of control are generally used with several levels of hierarchy in a distributed architecture. Each level serves its own purpose, but all levels are interconnected, similar to the operating structure of a corporation. In building control the controlled parameters include basic functions such as discharge air temperature, space temperature, humidity and fan control. The benefits of such a control system in an intelligent, integrated heating and cooling network include repeatable and individual parameter or area (zone) control. Individual comfort control is known to increase employee output and can produce annual productivity gains of over $1000 per employee. Networking takes building automation beyond traditional heating and cooling functions. Intelligent devices can be tied into the network,

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allowing data to be collected and energy usage to be measured. A networked system may also manage lighting, fire and access control. If these systems are fully integrated, then the expanded integrated control functions can also address environmental issues such as indoor air quality. The present energy management climate coupled with increasing costs and the need for improved efficiency of building systems require a new look at building automation systems. Intelligent instrumentation allows better performing devices to provide functions such as advanced diagnostics. Intelligent devices also provide the flexibility to apply control centrally or at local processing points for improved performance and reliability. Building automation, wireless technology, and the internet have been changing the business of managing buildings and their energy use. Tenants can call the building on the weekend and program it to be running when they arrive for some needed after-hours use. They may also use an integrated security system that makes them feel safer without invading their privacy. This increased functionality is possible with building communications technology such as BACnet or LonWorks. This type of bus technology allows products of various building systems to communicate. In one school district’s main energy management system, a BACnet gateway allows the district’s energy management system to transmit a setpoint to one or more of the rooftop unit controllers. In another application, BACnet communication is used between an ice rink’s building automation system (BAS) and the controls for the chillers that make the ice in the rink. The city of Memphis, Tennessee, installed new control systems as an upgrade to its Fairgrounds Complex. The controls are BACnet-compatible, and will be networked into a centrally monitored system via the city’s existing municipal system. A centralized network of BACnet-based building automation systems is used in Tucson, Arizona, for some 25 municipal facilities. The system replaced a group of 5 to 10 year-old direct digital control systems. The city was concerned about the reliability of their existing control systems causing major system failures. The U.S. General Services Administration (GSA) is using BACnet controls from Alerton Technologies and the Trane Company at its 450 Golden Gate Building, located in San Francisco. This large-scale implementation of the BACnet open communications protocol replaced an

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older pneumatic control system. The building houses several government departments and agencies, including GSA and federal courts. Its 22 floors with 1.4 million square feet makes it one of the largest buildings in San Francisco. Each floor is larger than a football field. The building-wide energy management control system cost $3.5 million and should save over $500,000 in energy costs per year. The Trane Tracer summit system is used with BACtalk for Windows. A network hub is used on each floor with remote terminals connecting to the network through a local area network (LAN). The retrofit involved over 800 dual-duct and 60 single-duct variable air volume (VAV) terminal units with BACtalk controllers. Each controller is programmable and communicates on the BACnet LAN. The pneumatic operators have been replaced with electronic actuators and pneumatic thermostats replaced with intelligent digital-display wall sensors. The eight main dual-duct air handling units have been retrofitted with programmable controllers. Other HVAC systems like the one in the Knickerbocker Hotel in Chicago have reduced operating costs by automating the building’s mechanical systems with a LonWorks-based building control system. A single, common twisted-pair wire backbone is shared among elements allowing the system devices to work as intelligent zone controls. Rather than individual wires, the functions are handled by messages over a network. The plug-and-play device characteristics allow easy connection of HVAC components. The building automation involves multi-zone air handling devices, refrigeration equipment, and the chilled and hot water systems. The volume of air flowing into the lobby area is controlled by variable frequency drives. The control of dampers and zones is done with LonWorks-based intelligent actuators. In areas such as the ballroom, the lobby, and the restaurant, intelligent space sensors are used to transmit network messages back to the actuators that control the zone dampers. The system operates in a Windows environment and allows the monitoring of control system data, fan temperatures, equipment switching and adjustment of operating parameters. Dedicated channels on the CATV backbone used are available for guest services such as monitoring the mini-bar, controlling the heating, and providing real-time security through a door locking system. Contemporary building automation systems attempt to limit the interfaces required and provide a more seamless, integrated network. Digital control networks provide an architecture that can be fully distrib-

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uted with independent controllers for the systems and subsystems in a building. Intelligent, versatile instrumentation at the lowest control level allows the energy management data to be easily organized for more flexible efficient management. Highly organized data collection means the facilities and operations staff can be more effective. Energy audit trails also go more quickly and can be used to demonstrate proof of performance, as well as limit future costs. Most building control software is based upon the operation of such software as Microsoft Windows. Building systems may do alarm dial outs to pagers and telephones with voice synthesis. Control sequences include start/stop of non-HVAC loads and the on/off control of lighting and other electrical equipment. In these applications there are greater requirements for control integration due to the distributed nature of the control system. General-purpose controllers can provide full local control requirements and integrate with both the building wide controller and the appropriate zone level controllers to provide building wide functions. Equipment level applications are energy intensive and include air handlers, chillers and boilers. The characteristics of the control include data point monitoring and multiple control sequences such as reset and warm up. BUILDING CONTROL TRENDS The early control panels used individual pilot lights, then came single line light emitting diode displays. The next evolution in control interfaces came with text only, monochrome displays. Now, high resolution color graphics provides users with realistic images that are updated every second. Virtual reality systems may allow the operator to experience the environment with special headsets and gloves. After a complaint of a hot or cold temperature or a draft, an operator may zoom in to the space to feel and measure the temperature. Zooming inside the VAV box, the operator could check the damper position and view readouts of air volume and temperature. The thermostat or damper control could be adjusted while observing the system’s operation. The operator could also check the operation of fans, boilers and chillers using this zoom control. Adding a sensor to a room would be a simple operation. The sensor may have a

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self-adhesive backing and stick to the wall. Power could be supplied to the unit by a built-in solar cell with battery backup. The sensor would broadcast using infrared, radio wave, or microwave. The computer will recognize the sensor and assign a point number and the system would map the location of the sensor using triangulation of the signal and its internal map of the building. A self-optimization routine would be used to search for the optimum control strategy to utilize the new sensor. Demand limit control is a technique that raises the cooling setpoint in order to reduce some stages of cooling. This is a building wide sequence that requires equipment turn-off and avoids demand peaks. Power measurement is becoming easier with intelligent devices and systems can monitor, measure, protect, coordinate, and control how power is used. Power and control monitoring systems use meters, protective relays, circuit break trip units, and motor starters. They can communicate information over an Ethernet network to a central location for remote monitoring, alarming, trending, and control. Power-monitoring software can be used to analyze energy use and power quality. It can identify load profiles to help with rate negotiation. If companies know their energy profiles, how and when they consume power, they can negotiate better rates for the type and amount of power they need. Building Management Systems Building management systems can meet most control needs including problem areas in an existing building to a total system for a major complex or campus. Capabilities and features of building management systems include: • • • • • • • •

scheduling for weekdays and holidays, after-hours tracking, management reports and logs, interactive graphics, direct digital control, comfort monitoring by zone, energy-saving software, and simple operator interfaces.

Total integrated systems include HVAC, controls and building management. A building management panel on the monitor screen is used to

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coordinate the control of HVAC equipment and related building systems. It provides the user with management information and networking with packaged HVAC equipment, zone controllers and others on a communications link, creating an integrated system. A system like the Trane Tracer provides building automation and energy management functions through standalone control of HVAC equipment. It offers direct digital control (DDC) capabilities, and full monitoring and control of conventional HVAC equipment. The system provides a graphical user interface, high-speed communications and distributed intelligence. Advances in computer technology include local area networking, powerful operating systems and object-oriented databases. These advances allow the system to provide valuable diagnostic data from unitmounted controls on the HVAC equipment. A building automation system (BAS) can be used to automatically implement operation and maintenance strategies that lower costs and enhance comfort levels. A BAS can provide other benefits such as increased operating efficiency and reliability, safer environments and better returns on investments. It can be an effective troubleshooting tool when used to collect historical and current data for analysis and documentation. Rising energy costs are a growing concern for building owners. As buildings grow older, the operating efficiencies of building systems drop and energy costs go up. A BAS can improve operating efficiencies and eventually lower energy costs. Energy management is a continuous process. Before an energy retrofit is implemented, a BAS can be used to develop a baseline of energy usage and environmental conditions. This makes it easier to calculate energy savings and compare environmental conditions to verify the performance of the retrofit. Once a retrofit is complete, performance variables need to be monitored and adjusted to maximize the savings potential. The energy consumption is compared to the baseline consumption to calculate savings. The process can be done using a BAS. Some building management systems can interface with other Windows-based applications, such as MS Word, Excel or Access. This allows the BAS to generate energy reports for analysis on standard programs. A BAS can also be used to track operating efficiencies and alert the energy manager when efficiencies drop below a certain level. This includes automatic trending and reporting of a building’s key performance

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indicators such as energy cost per square foot, energy cost per unit produced or energy cost as a percentage of net income. A BAS can link the operating efficiencies to the building’s core business output. A comparison of operating efficiencies between several floors of a building can be made. This type of checking can indicate that a piece of HVAC equipment, such as a chiller needs replacement or repair. Studies indicate that the operating efficiencies of a building can be improved by 10-20% using a BAS. Depending on the equipment controlled by the BAS, there are several ways of using a BAS to lower energy costs. The BAS can conduct scheduled Start-Stop of light, HVAC, and process or manufacturing equipment. Automatic control of HVAC and process-controlled variables, such as temperature, static pressure, humidity and flow can be based on actual load conditions. Automatic load shedding and load shaving can take advantage of cheaper power during certain hours of the day. This is a major advantage in a deregulated market. Equipment interlocking can be used to ensure that equipment consumes energy only when necessary. This can reduce energy consumption by 15-30%. Integrating end-use metering into the building management system using evolving communication protocols is now possible. Systems are available that use networked power metering with multiple metering points on a single RS-485 network. Building Safety Most of the automatic responses to a fire condition are set in the local codes. This includes turning off the air handling unit on the floor of incidence and homing the elevator. The types of responses required by the fire codes are under the direct control of the fire alarm system. Other building systems can provide a secondary response. The secondary responses, that can be coordinated by a BAS include turning on lights on the floor of incidence to aid evacuation. Air handling units on the floors above and below the floor of incidence can be activated to contain the migration of smoke. This is sometimes called a sandwich system. Message control includes inhibiting HVAC alarm reporting on air handling units turned off to limit distraction and sending audible evacuation messages based on the occupancy of the zone. The system could also send textual and graphical evacuation messages to users of the office

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automation network at information kiosks and other public displays. Unlocking security doors can be done to aide evacuation. Inhibiting alarm reporting on security doors (fire exit doors for leaving the building) should also take place along with printouts of lists of occupied zones and floor planes showing fire devices and exits. Many security systems use a security alarm trigger for local CCTV cameras with displays on a dedicated monitor and recorded on a VCR. Locking out the elevator operation for the floor in response to a security alarm can delay the intruder. Another response to a security alarm is to turn on all lights in the area. Turning on lights in response to a security alarm can limit damage by intruders as well as protect the guard sent to investigate. Local CCTV cameras will also be able to record a better image with the lights on. Information management can provide both environmental compliance and energy management. Financial decision-making is also allowed along with environmental quality assurance. Networked control provides quality assurance which can be used to identify, analyze and improve building operations related to both comfort and security. Energy Management and Control Control system technology had been evolving but a number of factors combined to make computer-based control technology more viable. One of these was the decreasing cost of electronics which made control systems more affordable. At about the same time the interest in energy savings jumped and a number of incentives and tax credits became available which stimulated the market. These factors resulted in a demand for technology that would allow building owners to save energy. These newly developed systems came to be known as Energy Management and Control Systems (EMCS). The computer in use at this time was the minicomputer. These systems utilized energy saving features for optimizing equipment operation, offsetting electrical demand and initiated the shut-down of equipment when not in use. Next in the control evolution was the utilization of Direct Digital Control. This technology was used in industrial process control and even for some building applications as early as the 1950s, but it was not until much later that it became an acceptable technique for heating and cooling systems. DDC is a closed loop control process that is implemented by a digital computer. In closed loop control, a condition is controlled by sensing

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the status of the condition, taking control action to ensure that the condition remains in the desired range and then monitoring that condition to evaluate if the control action was successful. Proportional zone control is a type of temperature control. First, the zone temperature is sensed and compared to a setpoint. When the temperature is not at the setpoint, a control action is taken to add heat or cooling to the zone. Then, the temperature is sensed again for a new control cycle. The control may go beyond basic proportional temperature control and to integral or derivative control. In this case, the integral or derivative is used to calculate the amount that the temperature is from the setpoint. The control action is now limited to avoid overshooting the setpoint and the oscillations that cause delays in control response. These delays can often occur with proportional control. Derivative control is often used in dynamic applications such as pressure control. Derivative control will measure the change of speed in the controlled condition and adjust the action of the control algorithm to respond to this change. The use of a combined Proportional, Integral and Derivative (PID) control loop allows the control variable to be accurately maintained at the desired levels with very little deviation. A combined sequence like PID can be used to integrate the control of several pieces of heating and cooling equipment to provide a more efficient and seamless operation. Combining this type of more accurate control with networking has been an important advance in building control. In the past when there was cheap oil, there was little demand for energy management systems. The slow but continuous growth of these systems led to an awareness of the benefits of computerized control. Real energy cost reductions were noted as well as the other benefits of improved control. These benefits include longer equipment life, more effective comfort levels and expanded building information. The use of heating and cooling controls are driven by higher energy costs and potential energy crises. These also force a return to growth in the use of demandside management. The growing requirements of indoor air quality and related environmental requirements force more applications for intelligent buildings and the control integration that they utilize. A distributed control system might control heating and cooling equipment and other loads such as lighting. Distributed control is applied at each piece of equipment to provide application specific control. A number of products have been introduced that use a type of com-

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munication network known as sensor or field buses. This technology has been growing quickly. Remote support can take place through a modem interface over telephone lines or through the internet. Building systems may also do alarm dial outs to pagers and telephones with voice synthesis. Using building wide controllers that support plug-and-play and objects, the system stores all critical system information at the controller level. Intelligent controllers of this type make it possible to dial into a system from a remote location, upload from the controllers and have full access to the system. Another related building wide control trend is integration at the functional level. This trend also includes a movement toward integrated control between systems with different functions such as security and building control systems. In the future, communications between sensors and multiplex boxes and the rest of the system may use a combination of technologies including traditional means such as twisted wire and coaxial and nontraditional methods such as infrared or radio wave. The controllers may be used for continuously interrogating the network for sequences such as morning warm-up. This feature would have been centralized in older systems. A single condition such as outside air temperature might have been monitored, and the building wide device would make a decision on start time based on this data and a stored sequence. When start up was required, that controller would signal the start of the sequence. With integrated control of this type, each controller can make independent decisions based on building wide data as well as local controller data. This results in a more reliable and effective building control system. In future systems, virtual reality may allow the operator to experience the environment. Special headsets and gloves may be used. After a complaint of a hot or cold temperature or a draft, an operator may zoom in to the space to feel and measure the temperature. Zooming inside the VAV box, the operator could check the damper position and view readouts of air volume and temperature. The thermostat or damper control could be adjusted while observing the system’s operation. The operator could also check the operation of fans, boilers and chillers using this zoom control. Adding a sensor to a room could be a simple operation. The sensor may have a self-adhesive backing and stick to the wall. Power could be supplied to the unit by a built-in solar cell with battery backup. The sensor would broadcast using infrared, radio wave, or microwave. The computer will recognize the sensor and assign a point number. The

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system would map the location of the sensor using triangulation of the signal and its internal map of the building. A self-optimization routine would be used to search for the optimum control strategy to utilize the new sensor. Equipment level applications that are energy intensive include air handlers, chillers and boilers. Control sequences include such expanded applications as start/stop of non-HVAC loads and the on/off control of lighting and other electrical equipment. MANAGING POWER Power management devices regulate the on and off times of selected loads, such as fans, heaters, and motors. These devices reduce the electrical demand (kilowatts) and regulate energy consumption (kilowatt hours). The operation of one or more loads is interrupted by the power management system based on control algorithms and building-operating parameters, such as temperatures, air flow, or occupancy. The savings in electrical energy use and cost range can be 50% or more. Electrical demand is defined as the average load connected by a user to an electrical generating system. It is measured over a short, fixed period of time, usually 15 to 30 minutes. The electrical demand is measured in kilowatts and recorded by the generating company meter for each measurement period during the billing month. The highest recorded electrical demand during the month is used to determine the cost of each kilowatt hour (kWh) of power consumed. Demand limit control is a technique that raises the cooling setpoint in order to reduce some stages of cooling. This is a building wide sequence that requires equipment turn-off and avoids demand peaks. Load-shaping involves the prediction of demand excursions for shedding loads or starting power generators to avoid setting new peaks. Power-monitoring software can be used to analyze energy use and power quality. It can identify load profiles to help with rate negotiation. If companies know their energy profiles, how and when they consume power, they can negotiate better rates for the type and amount of power they need. The linking of power management systems to control systems allows the power information to flow from both systems. Load profiles can be developed to find any energy inefficiencies. Energy scheduling can be

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used to find the optimum energy schedule for new product lines or processes. With real-time utility pricing production schedule energy requirements can be compared with energy rate schedules for optimum energy benefits. The new energy supply market requires more companies to give back energy capacity during peak energy use times by scheduling lowerenergy production. This can provide significant savings. The use of intelligent metering and monitoring systems gives companies a low-cost method for quickly implementing energy saving practices. The Cutler-Hammer plant in Asheville, NC, installed a power management system when energy bills were almost $45,000 a month. After 6 months of the installation, the plant energy savings reached $40,000. The power management system allowed plant engineers to identify wasteful procedures, shift loads to level the demand and perform preventive maintenance. Better control of area lights during off hours was possible. Large electric oven loads were timed during the late shifts when the total energy demand was lighter. Maintenance technicians were able to locate abnormal conditions with monitoring screens and then service the equipment before it broke down. The total return on investment was predicted to be less than two years. SHEDDING LOADS Among the different power management devices are load shedders which reduce the demand or average load in critical demand periods by interrupting the electrical service to motors, heaters, and other loads for short periods. Since the load which has been turned off would normally have been operating continuously, the overall effect is to reduce the average load or demand for that period of time. The instantaneous load when the load is operating remains the same. If the period involved has a high monthly demand, significant savings are possible in rate reductions. Before the era of high energy costs, load shedding was used mainly to avoid demand cost penalties. Now, it is used to limit energy consumption, by cycling loads on and off for brief periods, as well as to reduce demand. Other techniques used to limit energy use include the computer optimization of start times, setpoints, and other operating parameters based on the weather, temperatures, or occupancy.

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Demand limiting involves devices to monitor and measure the actual demand and then provide control actions to limit the operation of attached devices when the measured demand reaches a specified value. These devices require two signals, the kilowatt hour (kWh) or demand pulse, which indicates the units of electrical energy consumed and a timing pulse, which indicates the end of one demand pulse and the start of the next one. Some load shedders use a demand target that is not fixed but increases at a steady rate. Other devices allow the off-on setpoints to be adjusted independently for individual loads. Loads can be cycled based on the maximum demand target, time of day and day or week, rate of demand increase, heating and cooling temperatures, pressures, fuel flow and rates, occupancy schedules, inside and outside temperatures, humidity, wind direction and velocity and combinations of the above factors. Durations can be variable and changed automatically according to these parameters. In air conditioning systems, intake and exhaust dampers can be controlled on the basis of air temperatures, so that the mix of air requiring the least energy is obtained at all times. The start-up and shut-down of air conditioning, heating, and lighting systems can be regulated according to inside and outside temperatures as well as occupancy to produce the conditions which consume the least energy. Building Conditioning Building conditioning involves the use of a system designed to keep occupied spaces comfortable or unoccupied spaces at desired levels of temperature and humidity. This generally consists of fans, heat-exchanger coils, dampers, ducts and the required instrumentation. Building control involves optimization techniques for the Heating, Ventilation, Air Conditioning system (HVAC). The payback can be bold reductions in operating costs due to the increased efficiency of operation. In many systems, the amount of outdoor air admitted is often excessive and based on criteria when energy conservation was given little attention. Some studies show that infiltration of outdoor air accounts for almost half of the total heating and cooling loads. One study indicated that 75% of the fuel oil in New York City schools was used to heat ventilated air. Since building conditioning accounts for about 20% of the energy consumed in the U.S., optimized HVAC systems can make a major contribution in reducing energy use. Smart thermostats are programmable with

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some memory capability. They can be monitored and reset by a central computer using wireless or cable communication links. HVAC operating modes include start-up, occupied, night and purge. Optimizing the start-up time involves automatically calculating the amount of heat that needs to be transferred. Computer-optimized control can initiate an occupancy mode of operation. The system can be programmed for weekends and holidays and provides a flexible system for time-of-day control. A purge mode also allows a high degree of optimization. When the outside air is preferred to the inside air, the building can be purged. Free cooling is used on summer mornings and free heat is utilized on warm winter afternoons. A computer controlled system also allows the heat storage of the building to be used for optimization. Purging during the night before a warm summer day allows the building structure to be utilized in the optimization scheme. Another optimization mode is summer/winter switching. A computer control system may recognize that summer-like days can occur in winter and cool days may occur in summer. Optimized summer/winter operation takes place in an enthalpy-like basis. Heat is added in winterlike days and removed in summer-like days. A heat balance calculation is be made by computer using the following parameters: cold- and hot-deck flows, exhaust airflow and enthalpy, cold- and hot-deck temperatures, mixed air temperature and outside air enthalpy. A major source of inefficient operation in conventional HVAC control systems is the uncoordinated operation of temperature control loops. When there are several temperature control loops in series, these can cause simultaneous heating and cooling operations to occur. A coordinated control system can reduce energy costs by 10% or more. Besides eliminating simultaneous heating and cooling, other wasteful interactions such as cycling are reduced or eliminated. In some HVAC systems, outdoor air is provided by keeping the outdoor air damper at a fixed open position when the building is occupied. In an optimized system the open position can be a function of the number of occupants of the building or the building’s carbon dioxide levels. A constant damper opening is incorrect since a constant damper opening does not provide a constant airflow. The flow varies with fan load. The system can waste air conditioning energy at high loads and provide insufficient air at low loads. An optimized control can reduce operating costs with a constant minimum rate of airflow, which is unaf-

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fected by fan loading. As energy costs continue to grow in relation to overall operating costs, the need for more refined HVAC control becomes more important. HVAC strategies such as optimizing start-up time and supply air temperature and minimizing fan energy and reheating are not only possible but are becoming essential. HEATING EFFICIENCY TRENDS Furnaces are categorized by their efficiency. This is a measure of how much usable energy they can deliver from each unit of fuel. The U.S. Department of Energy tests and rates oil and gas furnaces, assigning each model an Annual Fuel Utilization Efficiency (AFUE). Furnace performance can also be measured by combustion efficiency. AFUE ratings can range from 78% efficiency to the high nineties. Furnaces with efficiencies of about 90% are known as high-efficiency or condensing furnaces. Installation costs of a high-efficiency furnace are about 25 to 30% more than a conventional model. Since they burn less fuel, these high-efficiency units are a better investment over time, especially for larger units. High-efficiency furnaces use two separate heat exchangers. The hot combustion gases that would ordinarily be lost are forced through a loop of pipes (the second heat exchanger) where they give up more heat. The hot gas cools enough where water vapor condenses from it. In these condensing furnaces the heat exchangers are built with special types of stainless steel and other alloys that can stand the hot, corrosive environment that is created. The flue gas temperature is so low that a special type of plastic pipe can be used for the flue. Trends in heating system technologies include modifications to conventional heat exchangers or the burn design. These changes provide steady-state efficiencies approaching 90%, with seasonal efficiencies to 85%. This is about 10% better than the steady-state efficiencies of 78 to 80% for the most efficient conventional designs. The use of spark ignition in the combustion chamber will keep exhaust gases at 120°F instead of 400°F or more. The process allows almost all the useful heat to be removed and the gases are cool enough to be exhausted through a plastic pipe. This type of system allows seasonal and steady-state efficiencies to reach 90%.

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Air and natural gas are mixed in a small combustion chamber and ignited by a spark plug. The resulting pressure forces the hot exhaust gas through a heat exchanger, where water vapor condenses, releasing the latent heat of vaporization. In subsequent cycles, the fuel mixture is ignited by the residual heat. One system manufactured by Hydrotherm has efficiencies of 90 to 94%. The cost of the system is between 50 and 100% higher than a conventional one, but the improved efficiency can pay back the difference in 5 years or less. Conventional flame retention burners produce a yellow flame, while modified flame retention burners produce a blue flame in the combustion chamber. This is done by recirculating unburned gases back through the flame zone which produces more complete burning of the fuel and results in lower soot formation. These flame systems are available as a burner for retrofit to furnaces, or as a complete burner and boiler system for hot water distribution systems. Variable fuel flow can be used in burners to throttle or cut back the fuel flow rate, which reduces the flame size, as the system heating load varies. These burners have conventional steady-state efficiencies and higher seasonal efficiencies. They are available for large apartment boilers and furnaces. There are also burners that can burn either oil or gas. They offer no efficiency advantages, but the ability to switch fuels in the event of a shortage or price differences is an advantage. They are available as combination burner and boiler units. The advantages of tankless boilers lies in their seasonal efficiencies, compared to conventional units. There is less water to heat up and cool off and the savings are similar to that of an automatic flue damper. Flue economizers include small auxiliary air-to-water heat exchangers that are installed in the flue pipe. The unit captures and recycles the usable heat that is usually lost up the flue. The recaptured heat is used to prewarm water as it returns from the distribution system. Depending upon the age and design of the boiler and burner, a flue economizer can provide annual fuel savings of 10 to 20% and a payback of 2 to 5 years. Air-to-air flue economizers are also available for about 1/5 the cost, but these save much less energy and are usually not tied into the central heating system. They are best for heating spaces near the flue. Several technologies are well suited to groups of buildings. These include cogeneration, district heating and seasonal energy storage systems. Cogeneration involves the simultaneous production of both space heat and electricity from an electrical generating system and is discussed

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in Chapter 2. A district heating system supplies heat and hot water from a central production facility to a number of residential, commercial and office buildings. Cooling towers usually discard the wasted heat of a power plant into the air. If a utility sells steam they are not allowed to keep any of the profits since the income reduces their operating expense base. Hot water or steam could be piped to homes and other buildings for heating. If the utility and energy regulations encouraged the sale of excess heat, as they do in Europe, wasteful cooling towers and discharge outlets would cease to exist. Iceland is one country that views power generation as a complete system where heat is used with about 90% overall efficiency. The hot water from geothermal wells is first used to generate electrical power. If the waste heat were discarded, this would be less than 20% efficient. But, the wastewater is piped to factories and used to run absorption chillers for refrigeration. The hot water that exits these applications is sold for district heating to apartment buildings. A seasonal energy storage system is designed to store heat or cold energy during one season, when it is not needed, for use during another season. DISTRICT HEATING District heating usually involves supplying hot water for space heating and hot water use from a central production facility to a group of residential or commercial buildings. District heating networks in Europe serve large portions of the populations of some countries. In Sweden, 25% of the population is served by district heating, in Denmark the number is over 30%, in Russia and Iceland it is over 50%. In the United States, district heating serves only about 1% of the population through older steam supply systems. In Europe, many of the district heating systems were installed during the rebuilding that followed World War II. District heat replaces relatively inefficient home heating systems with a more efficient, centralized boiler or cogeneration system. There is the potential of major energy savings, although some heat is lost in the distribution. A centralized boiler or cogeneration system can be used to produce heat. Large, centralized oil-fired boilers can remove as much as 90% of the energy contained in the fuel. Cogeneration systems can also have a total

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heat and electricity efficiency close to this. District heating systems can use the waste heat from electric generation and industrial plants that would be released to the air or to nearby water supplies. It is estimated that district heating could save as much as one billion barrels of oil per year in the United States. Some European cities use waste heat from fossil fuel electric power plants for district heating with an overall energy efficiency of 85%. Many of these plants were not originally constructed as cogenerating units. Waste heat from industrial process plants can also be used. Geothermal sources are used to provide heat for district heating systems in Iceland and Boise, Idaho. Hot water can be transported over longer distances with little heat loss compared to steam heat distribution systems which can only serve high-density regions. The largest steam system in the U.S. is a part of New York’s Consolidated Edison (ConEd) and serves part of Manhattan. The larger pipes or mains carry 200 to 250°F water under pressure. Return mains carry the cooler, used water at 120°F back to the central facility. In Aktau, Kazakhstan, the city is provided with hot water from the local nuclear power plant. Central heating costs can be lowered with the use of newer types of pipes, insulating materials and excavation techniques. Plastic piping in long rolls is laid in plastic insulation and placed in narrow trenches. Using these techniques, hundreds of feet of pipe can be laid quickly. Metal radiators can also be replaced by plastic units. Since district heating systems are generally financed by municipal bonds at low interest rates, they are repaid over a 30- to 40-year period which makes the annual cost per home competitive with or less than that of conventional heating systems. SEASONAL ENERGY STORAGE A seasonal energy storage system stores heat or cold during one season, when it is not needed, for use during another season. These systems have a large energy storage component. They collect essentially free heat or cold when they are plentiful and save them until required. The only energy consumed is that needed to run the various parts of the system. There are three types of systems: annual cycle energy systems, integrated community energy systems and annual storage solar district heating. The first two can provide both heating and cooling while the third is

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used for heating only. The annual cycle energy system (ACES) uses a large insulated storage tank of water and a heating-only heat pump. The tank contains coils of pipe filled with brine (salt water) warmed by the water in the tank. The brine circulates through a heat exchanger and transfers its heat to the heat pump refrigerant. During the heating season, heat is removed from the water tank by the brine and transferred to the building at a temperature of 100 to 130°F. The system may also be used to provide domestic hot water. As heat is removed from the tank, the temperature of the water drops below the freezing point and ice begins to form on the brine circulation coils. By the end of the heating season, ice fills the entire tank. This ice is then used during the summer to provide chilled water for air conditioning. While the ice remains in the tank, the only power required for cooling is for the operation of a circulator pump and a fan. These systems have been shown to use about 45 to 50% of the electricity consumed in a similar building with conventional electric resistance heating. It is more efficient than a conventional air-to-air heat pump system, since the heat source is maintained at a constant, known temperature. In moderate cold climates with 6,000 degree-days, an ACES uses about 25% less electricity than a conventional heat pump with a coefficient of performance of 1.5. The cost of an ACES is much higher than that for conventional heating and cooling systems, mainly because of the storage tank. Energy savings in a home with electric resistance backup can be over $1,000 per year, which provides a 10- to 15-year payback. The system is normally sized to meet the summer cooling requirements, rather than the winter heating load, of the building. In order to meet the total heating requirements of a building, an ACES is best suited for climates where the heat provided to the building from the tank during the winter is nearly equal to the heat removed from the building for cooling and transferred back into the tank during the summer. This is possible in areas where the winter and summer climates are not too extreme, such as Maryland and Virginia. An integrated community energy system (ICES) is used for district heating and cooling system with heat pumps used to collect and concentrate energy. The heat pumps allow free heat that would otherwise be lost to be removed from fuel cells, boiler waste heat, groundwater, lakes, solar and geothermal sources. An ICES in areas with moderate winter temperatures may use air as a heat source. Systems that use lakes or reservoirs rely

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on the natural collection of heat by these water sources throughout the year. An ICES has three major components: heat pumps, a heat source which may also act as heat storage and a distribution system. Depending on the winter climate, the heat source can be a lake, reservoir, underground storage tank, aquifer (underground river or lake), solar-heated water, sewage or waste water, geothermal energy or waste heat from industrial or commercial facilities. The heat pumps may be centralized, distributed or cascaded. In a centralized system, one or more large heat pumps are used in a manner similar to the centralized boiler of a district heating system. The heat pumps are located in a central facility so they can remove heat directly from the heat source. This heat is then used to warm distribution water, which is then pumped to individual buildings. The distributed system uses small heat pumps located in each building. Water from the heat source is sent directly to each individual heat pump. Heat removed from the distribution water is used to warm the building. Some heat pumps may be used to also provide cooling. A cascaded system employs both centralized and individual heat pumps. A central heat pump removes low temperature heat from the primary source and adds it to the distribution water, which is sent to individual buildings. Heat pumps in the buildings then use this distribution water as a secondary heat source. This system is used when the primary source water is too corrosive, such as salt water, or contaminated, such as waste water. The distribution system of an ICES is the same as that of a conventional district heating system. Each ICES has warm water supply and cool water return mains. Systems that supply both heating and cooling at the same time may have independent distribution systems for hot and cold water. Distributed systems using groundwater as a heat source may have only a distribution water supply line. Cascaded and distributed ICESs have separate heating distribution systems for each building. The operation of an ICES depends upon the nature of the heat source and if the system is centralized, distributed or cascaded. If an ICES serves both small and large buildings, the surplus internal heat from the large buildings can be used to provide source heat to smaller ones. An ICES using a large fabricated tank of water can operate as a community-scale ACES. The water in the tank is slightly higher than 32°F. During the winter a centralized heat pump removes heat from the tank, causing the formation of ice. This ice is then used for summertime air

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conditioning or for winter cooling of large buildings. Sewage and wastewater heat sources are usually not much colder than the buildings from which they come. A cascaded ICES can remove heat from waste water and transfer it to the distribution system which then acts as a secondary heat source for heat pumps in individual buildings. Waste heat is often lost into the environment by industrial facilities in the form of hot water. This hot water can be used directly by the heat pumps in a centralized ICES. ICES have several advantages over conventional district heating systems or individual building heating systems. An ICES will often serve business, commercial and residential districts. Since the peak heating and cooling demands of these different sectors may not occur at the same time of the day, a single moderately sized system can meet the varying peaks of the different sectors. If the ICES contains a short-term heat storage component, such as a water tank, the system can operate continuously and at a steady level around the clock with peak heat demand requirements drawn from storage. Conventional heating systems burn fossil fuels at high temperatures to heat water to 120°F. Most district heating systems operate in the same way. In these cases, when the hot water cools to 90°F or less, it is no longer warm enough to supply heating. This remaining heat is eventually lost to the environment. An ICES can recover this low-temperature heat that would otherwise be wasted. This helps to increase system efficiency. An ICES is often found to be economically competitive with conventional heating systems such as furnaces and/or boilers in individual buildings or district heating systems using fossil fuels. Capital costs are a good deal higher than those of conventional systems, but ICESs have lower energy requirements. Free environmental energy is substituted for the burning of fossil fuels. In some ICESs, electricity consumption may be greater than in conventional systems lacking heat pumps, but the total consumption of all forms of energy is lower. SOLAR STORAGE Solar energy can be used to warm heat pump source water. In this system solar collectors are mounted on a large, insulated water tank where the warmed water is stored. Most of the heat is collected in the summer

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for use during the winter. In the winter, the hot water can be used directly for space heating until it cools to about 85 to 90°F. The remaining heat can be removed and concentrated by a centralized heat pump. ACESs and ICESs rely on heat pumps and storage systems, and need notable amounts of energy to operate. An annual storage solar district heating system could supply most of a community’s annual space heating requirements with a minimum of nonrenewable energy. An annual storage solar district heating system requires a heat store, a collecting area and a distribution system. The storage can be either an insulated earth pit or a below-ground concrete tank. Both have insulated concrete covers and are filled with water. Collectors are mounted on the cover of the storage tank and are rotated during the day so they always face the sun. During the summer, the collectors heat water for storage and for domestic hot water. During the winter, the collecting system heats water that is used directly for heating purposes. When additional heat is required, the hot water stored in the storage tank or pit is used. Water is removed from the top layers of the storage tank. The cooler used water is pumped back through the collectors or into the bottom of the storage tank. These systems cannot provide air conditioning so they are mostly suited to northern climates. This is because over the course of a year even northern locations such as Canada receive as much sunlight per square foot as Saudi Arabia. The problem is that most of the sunlight falls in the summer when it is not needed for heating. In annual solar storage the system collects heat in the summer for use during the winter. A large rock cavern is used in Sweden to provide district heating for 550 dwellings. A housing project near Copenhagen in Denmark, uses a central solar collector and a large insulated water tank buried in the ground. Solar heat provides most of the space heating requirements for 92 housing units. When the temperature of the heat store falls below 45°C, heat is transferred with a heat pump, powered by a gas engine, which boosts the temperature to 55°C. This process continues until the temperature of the heat store has fallen to 10°C, at the end of the heating season. Waste heat from the engine is also delivered to the heating system, and a gas boiler is used as a back-up. In the summer, the main heating system is shut down and 90% of the domestic hot water requirements of the housing units are provided by additional solar collectors on each of the eight housing blocks. This type of system can also be implemented by a gas furnace. All of these systems

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operate in latitudes far to the north of American cities. Solar district heating offers a number of advantages over conventional single-residence active systems. The collectors can be set aside in an open area and problems with access to the sun do not arise. The heat storage capacity is not constrained by space limitations in any one building and the storage tank can be as large as necessary. Since the system is equipped for annual storage, solar collection is not dependent on the dayto-day weather conditions. To be cost-effective, these types of technologies are usually applied to groups of buildings, but cogeneration and seasonal energy storage systems may be sized for small-scale applications. District heating may include cogeneration or summer storage of solar energy for winter space heating. An annual storage solar district heating system is capable of supplying 90% of the annual heating requirements for the homes in a community. Depending upon the climate zone, the required collector area per house can range from 70 to 300 square feet. This can be reduced if residential heat loads are lessened through increased weatherization and the addition of passive solar features. LOW-ENERGY COOLING Most of these systems seek to provide some or all of the cooling without using electricity during the high cost, peak period. Hybrid plants are often used because the cost of cooling with electricity during some periods may be less than the cost of cooling with natural gas. Low-energy systems to provide cooling may include electric chillers, absorption chillers, engine-drive and/or dual-drive chillers, thermal storage systems and the use of a water-side economizer cycle. Absorption chillers, especially the double-effect type, are used for utility rate structures with high peak period demand. These include usage charges or rate schedules with ratchet clauses for the demand charges. There is a significant first cost premium for this equipment. Maintenance costs are generally comparable with electric chillers, but the absorption chiller requires more day-today maintenance. Engine-driven chillers provide an alternative to absorption chillers when natural gas cooling is desired. Engine-driven chillers utilize the same type of equipment as electric chillers for cooling, but replace the

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electric motor with a natural gas fueled engine. Especially for truck-derivative engines, maintenance costs are significant and must be accounted for in the operating costs. A major benefit of engine-driven chillers is the opportunity to capture waste heat from the engine as a mechanical cogeneration system. Another option is the use of dual-drive chillers with both an electric motor and a natural gas engine available to drive the chiller. Warehouses, and other buildings often have a number of loads or zones which are served by an evaporator coil. There are a number of positive-displacement refrigerant compressors which are turned on or off to follow that load. The optimization of these systems involves minimizing the cost of operation by meeting the cooling loads with a minimum of compressor horsepower. The compressors must be operated in such a way that the total run-time of each machine is about the same. Each cooling zone may be a separate room, freezer, or other cooled area with its own temperature control. If a balancing valve is provided for each zone and located in the refrigerant vapor line leaving the zone, when all zones are at the same temperature, the balancing valves are full open, which minimizes the pressure drop on the suction of the compressors and maximizes their efficiency. An optimized control system eliminates wasted energy by using high and low pressure switches for turning additional compressors on or turning unnecessary compressors off. Additional optimization is achieved by increasing the control gap between the pressure switches as high as the loads will allow. Energy consumption is minimized by maximizing temperature setpoints. When the zone temperatures are at setpoint or below, the suction pressure of the compressor station is increased and the amount of work the compressors must do is less. The total energy savings from this type of control system is about 20%. The larger chillers in refrigeration units of the 500 ton (1760-kw) or larger sizes are capable of continuous load adjustment. They can also use an economizer expansion valve system or hot gas bypass to increase rangeability. If the hot gas bypass allows the chiller to operate at low loads without going into surge, there is an increase in operating costs from the work wasted by the compressor. An optimized control system can reduce this waste by using a variable speed compressor. An optimized control can recognize cooling water temperature variations and open the hot gas bypass valve only when needed.

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An economizer can increase the efficiency of operation by 10%. There are savings in compressor power consumption, reduction of condenser and evaporator surfaces, and other effects. The economizer is a two-stage expansion valve with condensate collection chambers. The savings are a result of vaporization in the lower chamber from precooling the liquid that enters the evaporator. A typical cooling system involves four heat transfer substances (chilled water, refrigerant, cooling tower water, air) and four heat exchanger devices (heat exchanger, evaporator, condenser, cooling tower). The system operating cost is the cost of circulating the four heat transfer substances. In an unoptimized system each of these four systems operate independently in an uncoordinated manner. The transportation devices operate at constant speeds and introduce more energy than is needed for the circulation of refrigerant, air, or water. This results in a waste of energy. Load-following optimization can eliminates this waste. The system must be operated as a coordinated single process to maintain the cost of operation at a minimum. If water temperatures are allowed to float in response to load and ambient temperature variations, this eliminates the waste needed to keep them at fixed values and reduces chiller operating costs. The costs of operating a cooling system can be divided up as follows: fans 10-15%, cooling tower water pump 15-20%, compressor 5060% and chilled water pump 15-20%. Fan costs increase in geographic regions with warmer weather. Longer water lines with more friction cause an increase in pump costs. Compressor costs become lower as the maximum allowable chilled water temperature rises. The goal of optimization is to find the minimum chilled water and cooling tower water temperatures which will result in meeting the cooling needs of the installation at minimum cost. If the temperature of the water supplied by the cooling tower is controlled by modulating the fans, a change in cooling load means a change in the operating level of the fans. If the fans are single-speed units, the control must cycle them on or off as a function of the load. Fans running at half speed consume about a seventh of the design horsepower but produce more than half of the design air rate or cooling effect. Most of the time the entering air temperature is less than the design rating, so two-speed motors can be used for minimizing fan operating costs.

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Thermal storage systems can be used to shift the cooling load from high cost periods to low cost times of day. One concern is allowing for sufficient storage and recharging capacity to allow for some load and temperature increase for overnight periods. Primary-secondary chilled water distribution systems were developed to allow a constant flow through chillers, with variable flow for the load side of the system to improve efficiency. These can be used in multibuilding systems or systems with larger variations in load. The use of variable speed drives and DDC control systems makes the operation of these systems much more effective. Another advantage of the primary-secondary system is the system flexibility that makes it easier to incorporate hybrid systems, as well as thermal storage systems and water-side economizers. Condenser water systems for electric chillers are usually designed with a 10°F temperature differential. Absorption chiller systems may operate with higher temperature differentials due to the greater amount of heat rejected from these units. The higher temperature improves the efficiency of the cooling tower, but will reduce the efficiency of the chiller. An oversized cooling tower affects operating costs, since there is a reduction in pumping energy, perhaps a reduction in cooling tower energy, offset by an increase in chiller energy. The net affect depends on the size of the system, amount of pumping, climate and hours of operation, but usually results in a net reduction in energy consumption. Exhaust fans do not consume a lot of energy compared to other HVAC equipment, but exhaust air needs to be made up by fresh outside air. Some buildings use almost 100% outside air during winter heating season. When excessive exhaust occurs, the supply system needs to supply more outside air than the minimum required for proper ventilation which results in more heating and cooling energy. An exhaust system retrofit was done by the Eldec Corporation, an aerospace electronic manufacturer. The goal was to reduce exhaust air by up to 30% for the first shift and 60% for the rest of the time. Significant savings were achieved with a one year simple payback. Control of the exhaust fan speeds was done with variable frequency drives (VFD). The fans are now monitored and under the control of the building direct digital controls (DDC) system to ensure proper operation and save energy. The VFDs were set to run at minimum and the building achieved a 30% energy reduction during occupied hours and 60% during unoccupied hours.

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SUSTAINABLE BUILDING Sustainable or green building is based on a design philosophy that focuses on increasing the efficiency of resource use, energy, water, and materials, while reducing building impacts on human health and the environment during the building’s lifecycle. This is accomplished with better siting, design, construction, operation, maintenance, and trash removal. The HVAC system, the lights, the water, the elevators, the power and cooling for technology all contribute to making buildings a leading energy user. By 2025, buildings will use more energy than any other category of user. In 2006, buildings used 40 percent of the total energy consumed in both the U.S. and European Union. In the U.S., about 55 percent of the total percentage was consumed by residential buildings and 45 percent by commercial buildings. In 2002, buildings used almost 70 percent of the total electricity consumed in the United States with about half for residential use and half for commercial use. Almost 40 percent of the total amount of carbon dioxide in the U.S. can be attributed to buildings, about half from homes and half from commercial uses. Today, many of the systems in a building are managed independently and many of them are not managed at all for their occupancy, energy use or thermal effect, due to a lack of sensors and monitors. Intelligent, instrumented and interconnected buildings allow better utilization of the building’s energy. Green building policies and standards for energy efficiency along with incentives for architects, builders, developers and owners are combined with incentives for utilities to achieve major reductions in buildings’ demands for energy and water. One misconception is that energy efficient buildings are also green buildings. While energy efficiency is an important part of a sustainable building, energy efficiency alone does not qualify a building as green. Green building emphasizes the use renewable resources; sunlight through passive solar, active solar, and photovoltaic solar, green roofs, rain gardens and the reduction of rainwater run-off. Other techniques include using packed gravel or permeable concrete instead of conventional concrete or asphalt to enhance the replenishment of ground water. The green building concept involves a wide spectrum of solutions and practices. The green building should be designed and operated to reduce the overall impact of the built environment on health and the natu-

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ral environment. It does this by efficiently using energy, water, and other resources. The natural building concept tends to focus on the use of natural materials that are available locally. Practitioners of green building often seek to achieve ecological and aesthetic harmony in the structure and its surrounding natural and built environment. Other common terms include sustainable design and green architecture. Green building can result in: 1. Reduced operating costs by increasing productivity and using less energy and water. 2. Improved public and occupant health due to improved indoor air quality. 3. Reduced environmental impacts such as decreased storm water runoff. Green buildings require careful, systemic attention to the full life cycle impacts of the resources in the building and to the resource consumption and emissions over the building’s life cycle. Sustainable buildings use green building materials from local sources and generate on-site renewable energy. Green building materials include rapidly renewable plant materials like bamboo, lumber from forests certified to be sustainably managed, ecology blocks, dimension stone, recycled stone, recycled metal and other products that are non-toxic, reusable, renewable, and/ or recyclable such as trass, linoleum, sheep wool, panels made from paper flakes, compressed earth block, adobe, baked earth, rammed earth, clay, vermiculite, flax linen, sisal, seagrass, cork, expanded clay grains, coconut, wood fiber plates, calcium sand stone and high and ultra high performance, roman self-healing concrete. The EPA (Environmental Protection Agency) also suggests using recycled industrial goods, such as coal combustion products, foundry sand, and demolition debris in construction projects. Polyurethane blocks provide more speed, less cost and are environmentally friendly. Green buildings often include high-efficiency windows and insulation in walls, ceilings and floors. Passive solar building design uses awnings, porches, and trees to shade windows and roofs during the summer while maximizing solar gain in the winter. Effective window placement provides more natural light and reduces the need for electric lighting during the day. Solar water heating also reduces energy needs. Onsite generation of renewable energy using solar power, wind, hydro or biomass

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reduces the environmental impact of the building. In the Mexican town of San Felipe, Baja California, is the largest solar-powered community in North America with 3000 home sites completely off-the-grid in the 30,000-acre development. The green building initiatives that have been implemented include Straw-Bale Home Construction, allowing insulation factors of R-35 to R-50 and the use of xeriscaping, a type of landscaping that reduces water consumption, energy consumption and chemical usage. Green architecture also reduce the energy, water and materials used during construction. In California almost 60% of the state’s waste comes from commercial buildings. Centralized wastewater treatment systems can be costly and use significant amounts of energy. An alternative to this process is converting waste and wastewater into fertilizer, which avoids these costs and shows other benefits. By collecting human waste at the source and running it to a semi-centralized biogas plant with other biological waste, liquid fertilizer can be produced. This concept was demonstrated by a settlement in Lubeck, Germany, in the late 1990s. GREEN ROOFS A green roof system is an extension of the existing roof which involves a high quality water proofing and root repellant system, a drainage system, filter cloth, a lightweight growing medium and plants. Green roof systems can be modular, with drainage layers, filter cloth, growing media and plants already prepared in movable, interlocking grids, or, each component of the system may be installed separately. Green roof development involves the creation of a contained green space on top of a human-made structure. The green space could be below, at or above grade, but in any case the plants are not planted in the ground. A green roof installation needs to consider the slope, structural loading capacity, existing materials of the roof, along with the character of drainage systems, waterproofing, and electrical and water supply. It needs to consider who would have access to it, maintenance, and what kind of sun and wind exposure the roof gets. Plant selection depends on a number of factors, including climate, type and depth of growing medium, loading capacity, height and slope of the roof, maintenance expectations and the type of irrigation system.

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The cost of a green roof varies considerably depending on the type and factors such as the depth of growing medium, selected plants, size of installation, use of irrigation, and if the plants are to be accessible or inaccessible, intensive, semi-extensive or extensive. Intensive green roofs normally require greater investment but have the benefit of accessibility. Intensive systems may require 10 inches or more of soil and growth medium. These systems can be used for full gardens with trees and shrubs. They require more watering and maintenance. Semi-intensive systems use between 6 to 10 inches of soil and growth medium. They can be used to grow grasses, bulbs, small shrubs and evergreens. An extensive system requires less than 6 inches of soil and growth medium. It is used to grow hardy plants, small shrubs and mosses that are drought resistant. Some extensive systems use modular trays with preassembled layers of soil. An installed extensive green roof with root repellant/waterproof membranes can be installed for $10 to $24 per square foot. While green roofs typically require a greater initial investment, they can extend the life of the roof membrane while reducing heating and cooling costs of the building. A garden roof with about 4 inches of growth can reduce cooling needs by 25 percent. A roof with about 6 inches of growth can prevent heat losses by 25 percent compared to a conventional roofing membrane. A 10-square-foot green roof can remove about 0.2 kilograms of particles from the air every year and improve the air quality. The Rice Fruit Company in Gardners, PA, installed a vegetative roof on its 22,000 square foot cold storage facility. Potential problems with green roofs include leaks, collapse, and corrosion. A green roof can also be a possible fire hazard if not properly irrigated. A dry green roof which is accessible by building occupants could be a potential problem. In Germany where green roofs are extensively used there has never been a roof fire and as a result green roofs are given a 10-20% discount on fire insurance. Some studies have shown that the threat of fire is 15-20 times higher on bare roofs with bituminous waterproofing than on green roofs with grasses or perennials. A significant amount of research in green roof infrastructure is taking place in different climate zones, different built environments and at different scales. Green Roofs for Healthy Cities (GRHC) encourages research through the GRHC Research Committee. Green Roofs for Healthy Cities works with local partners in cities to develop cost effective direct and indirect financial support for green roof construction that meets local

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and regional needs. Green roofs can provide a wide range of public and private benefits. In North America, the use of green roof technologies is growing while the market is developing. Wind uplift and fire resistance have been a concern in the past, but most of these concerns have been addressed. In Europe, these technologies are more established. The result of government legislative and financial support has led to a healthy market for green roof products and services in Germany, France, Austria and Switzerland and other countries. In Germany there were over 13 million square meters of green roofs in 2001. The use of green roofs has grown because of their ability to reduce rainwater that can swamp urban sewage systems while keeping buildings warmer in winter and cooler in summer, lowering electricity use. Across the U.S. commercial-scale rooftop farms have begun to supply this market. Among the products for green roofing are the sedum blanket which is a grass-like roof that absorbs water instead of letting it run off. In the Adnams Brewery warehouse facility in Southwold, England, the green roof is vegetated with pregrown sedum blankets. In the Italian city of Nola, located near Mt. Vesuvius, the Vulcano Buono is a coneshaped commercial center with a sloping green roof. Like the surrounding landscape, Vulcano Buono has a gently sloping profile that rises from the earth as a grassy green knoll. The structure’s roof is carpeted with a vegetative layer of over 2,500 plants that help to insulate the interior spaces. In Paris there are the vertical gardens, designed by the celebrated botanist Patrick Blanc. In 2009, Quezon City in the Philippines passed a new law requiring private and government-owned buildings to reserve part of their rooftops for greening. New commercial/residential buildings under the Green Roof Ordinance would devote at least 30% of their roof area for plants and trees. The City of Toronto has a green roof bylaw which consists of a green roof construction standard and a mandatory requirement for green roofs on all classes of new buildings. The bylaw requires up to 50 per cent green roof coverage on multi-unit residential dwellings over six stories, schools, non-profit housing, commercial and industrial buildings. Larger residential projects require greater green roof coverage, ranging from 20 to 50 percent of the roof area. In 2007 the Toronto City Hall offered subsidies for green renovations, including greenroofs. The City provided incentives of $50 (Cana-

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dian) per square meter up to $100,000 for building owners who installed green roofs. Another green roof subsidy was administered by DC Greenworks which funded $5 a square foot up to $20,000 per project for green roofs up to 4000 square feet of vegetative space. This was part of the expansion of the Washington, D.C. Green Roof Subsidy Program. In Tacoma, Washington, local developers converted Tacoma’s old Park Plaza South parking garage structure into a new retail-office building with a rooftop garden. They found that adding the green roof did not only benefit the building owners, but also improved the entire downtown area. In Harrisonburg, Virginia, the Urban Exchange has a green roof with dozens of ginkgo and myrtle trees with native plants. This retreat is two floors up on the roof of the retail space and parking garage. In Roanoke, Virginia, the roof of the Carilion Clinic’s Riverside 3 building is covered with 25,000 square feet of sedum plants that help to keep the building cool. The five-story building cost $70 million and contains Southwest Virginia’s largest green roof. Indianapolis will spend more than $8 million for projects to create green jobs and reduce energy consumption in the city, including installing 10,000 square feet of green roofs and at least 5-kW of solar power in the city’s parks and buildings. In Toronto, Canada, the Metro Central YMCA planted a green roof. The San Francisco 49ers new stadium will include solar panels and a green roof. Green roof technologies provide the owners of buildings with a proven return on investment, but also present significant social, economic and environmental benefits, especially in cities. Green roofs can provide a significant improvement in the LEED rating of a building, which can be as many as 15 credits depending on the design and level of integration with other building systems. In some cases, green roofs may not contribute points directly, but they contribute credits when used with other sustainable building components such as reduced site disturbance, open space landscape design, storm water management, water efficient landscaping, wastewater use and design innovation. LEED Trends The U.S. Green Building Council (USGBC) is a non-profit trade organization that promotes sustainability in buildings. USGBC developed

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the Leadership in Energy and Environmental Design (LEED) rating system and has more than 17,000 member organizations from all sectors of the building industry. The National Association of Home Builders has created a voluntary residential green building program known as NAHBGreen which includes online scoring, national certification and education and training. The Green Building Initiative (GBI) is a non-profit network of building industry leaders. The GBI has a web-based rating tool called Green Globes. The Environmental Protection Agency’s Energy Star program rates commercial buildings for energy efficiency and provides Energy Star qualifications for new homes that meet its standards. In 2005, Washington State became the first state to enact green building legislation. Major public agency facilities with a floor area exceeding 5,000 square feet including state funded school buildings are required to meet or exceed LEED standards in construction or renovation. The projected benefits are 20% annual savings in energy and water costs, 38% reduction in waste water production and 22% reduction in construction waste. Charlottesville, Virginia, became one of the first small towns in the U.S. to enact green building legislation. This represented a major shift as LEED regulations were formerly focused on commercial construction. HB 1975 and SB 1058 authorizes localities to grant regulatory flexibility and incentives to promote the construction of vegetative roofs and solar roofs on private homes and businesses. The incentives or regulatory flexibility include a reduction in permit fees when green roofs are used, a streamlined process for the approval of building permits when green roofs are used, or a reduction in any gross receipts tax on green roof contractors as required by local ordinances. HB 1828 allows water authorities to offer rate incentives for vegetative roof construction. The bill also authorizes localities to establish a rate incentive program designed to encourage the use of green roofs in the construction and remodeling of residential and commercial buildings. Local incentives must be based on the percentage of storm water runoff reduction the vegetative roof provides. The Virginia Association of Counties headquarters building was constructed in 1866 and entirely renovated to LEED standards. The Renew Virginia initiative makes it easier for localities to encourage green construction and green roofing. It should provide incentives for the de-

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velopment and deployment of green roofs across Virginia. IBM is a leader in building green data centers and specialized facilities that are firmly integrated with technology, such as trading floors and automated factories. IBM’s Green Sigma approach involves activities such as carbon trading and software that makes it possible to create management dashboards and operational control centers so that building managers can control the wide variety of their buildings’ subsystems for optimal use and conservation. Canada implemented its R-2000 in 1982 to promote building code construction to increase energy efficiency and sustainability. One feature of the R-2000 home program is the EnerGuide rating service which allows home builders and buyers to measure and rate the performance of their homes. Regional initiatives based on R-2000 include Energy Star for New Homes, Built Green, Novoclimat, GreenHome, Power Smart for New Homes, and GreenHouse. The Canada Green Building Council obtained an exclusive license in 2003 from the United States Green Building Council to adapt the LEED rating system to Canada. LEED’s entry into Canada had been preceded by BREEAM-Canada, an environmental performance assessment standard released by the Canadian Standards Association in 1996. The authors of LEED-NC 1.0 borrowed from BREEAM-Canada in the outline of their rating system and in the assignment of credits for performance criteria. In 2006, Canada’s first green building point of service, Light House Sustainable Building Centre, opened in Vancouver, BC. The BeamishMunro Hall at Queen’s University features sustainable construction methods such as high fly-ash concrete, triple-glazed windows, dimmable fluorescent lights and a grid-tied photovoltaic array. The Gene H. Kruger Pavilion at Laval University uses largely nonpolluting, nontoxic, recycled and renewable materials as well as advanced bioclimatic concepts that reduce energy consumption by 25% compared to a concrete building of the same size. The building is made entirely out of wood products. The City of Calgary Water Centre opened in 2008 at the Manchester Centre with a minimum Green Building Council of Canada’s Gold LEED (Leadership in Energy and Environmental Design) level certification. The 183,000-square-foot office building is 95 percent day lit, conserves energy and water and provides a productive, healthy environment for visitors

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and employees. A development in Newmarket, Ontario, was the first in Canada to be built entirely to the LEED platinum eco-standard. The 34 homes in the EcoLogic development use at least 50 percent less water, have 35 percent fewer discharge flows and generate 60 percent less solid waste, greenhouse gas production and energy consumption than conventional homes. In Europe the Energy Performance of Building Directive (EPBD) has been a mandatory energy certification program since 2009. A mandatory certificate called the Building Energy Rating system (BER) and a certification Energy Performance Certificate (EPC) is needed by all buildings that measure more than 1000 square meters in Europe. In the U.K. the Association for Environment Conscious Building (AECB) has promoted sustainable building practices since 1989. In Wales, sustainable building advice is available from a not-for-profit organization called Rounded Developments Enterprises which has a Sustainable Building Centre in Cardiff. In 2007, the French government established six working groups to redefine France’s environment policy. The recommendations included an investment of 1 billion Euros in clean energy, a 20% reduction in France’s energy consumption by 2020 and a 20% increase in the use of renewable energy by 2020. German developments for green building include The Solarsiedlung (Solar Village) in Freiburg which features energy-plus houses. There is also the Vauban development in Freiburg which uses passive solar design, heavily insulated walls, triple-glaze doors and windows, non-toxic paints and finishes, summer shading, heat recovery ventilation, and greywater treatment systems. Israel has a voluntary standard for Buildings with Reduced Environmental Impact. This standard uses a point system for energy analysis and sustainable products. The LEED rating system has been utilized in several buildings including the recent Development Center in Haifa and there is a movement to produce an Israeli version of LEED. In India The Energy and Resource Institute (TERI) developed a rating system called GRIHA which was adopted by the government as the National Green Building Rating System (GRIHA) which rates even nonair conditioned buildings as green and puts the emphasis on local and traditional construction knowledge. THE CESE building in IIT Kanpur became the first GRIHA rated building. The Indian Green Building Council (IGBC) has licensed the LEED

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Green Building Standard from the U.S. Green Building Council and is responsible for certifying LEED-New Construction and LEED-Core and Shell buildings in India. All other projects are certified through the U.S. Green Building Council. There are many energy efficient buildings in India, in a variety of climatic zones. One of these is the RMZ Millenia Park in Chennai, which is India’s largest LEED gold-rated Core & Shell green building. The Shree Ram Urban Infrastructure will be the first LEED Platinum rating (Core & Shell) in India and the first residential building in the world to have this rating. The Palais Royale building in Worli, Mumbai, has an estimated height of over 1,000 feet. The Hyderabad based AliensSpace Station 1 and Space Station 2 Residential project will have a gold Green building rating. The Indian Bureau of Energy Efficiency (BEE) launched the Energy Conservation Building Code (ECBC) in 2007. The code sets energy efficiency standards for the design and construction for buildings with a conditioned area of 1000 square meters and a power demand of 500-KW or 600-KVA. The energy performance index is set at 90-KWh/sqm/year to 200-KWh/sqm/year and a building that falls under the index is an ECBC Compliant Building. The BEE has a 5-star rating system for office buildings operated in the day time in 3 climatic zones, composite, hot and dry, warm and humid. The Reserve Bank of India (RBI) buildings in Delhi and Bubaneshwar in Orissa have received 4 and 5 star ratings. The Standards and Industrial Research Institute of Malaysia (SIRIM) promotes green building techniques. The Green Building Index (GBI) was developed by Pertubuhan Akitek Malaysia (PAM) and the Association of Consulting Engineers Malaysia (ACEM) in 2009. It will be the only rating tool for the tropical zones other than the Singapore Government’s GREENMARK. In Malaysia priority is given to energy and water efficiency. The New Zealand Green Building Council was formed in 2005 and in 2006/2007 became a member of the World GBC while launching the Green Star NZ Office Design Tool. The Green Building Council of South Africa was launched in 2007. It has developed Green Star SA rating tools, based on the Green Building Council of Australia tools to provide an objective measurement for green buildings. Each Green Star SA rating tool reflects a different market sector such as office, retail or residential.

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The definition of green building is often debated. Some individuals argue that a building is not a green building unless it obtains certification either by the USGBC, Green Globes or NAHB. While certification does provide a label and verification of a company or individual’s achievement it comes with a cost. Federal projects are now required to be build to LEED silver standards. ISO 21931 Sustainability in Building Construction provides methods of assessment for the environmental performance of construction. Part 1, Buildings, describes issues for the assessment of new or existing buildings in the design, construction, operation, refurbishment and deconstruction stages. It is intended to be used in conjunction with, and following the principles set out in, the ISO 14000 series of standards. Some contractors involved in green buildings attempt to achieve high levels of water and energy efficiency but they do not pursue certification because the system is too complex. In order to overcome the resistance of individuals to build green, the system must be clarified to remove the inconsistency between credits and reduce any fear of certification that a building might fall short by missing a credit. In its current form LEED certification is valued but it still has its skeptics. There is the potential for a building to lose its status as LEED certified if it fails to perform properly. LEED v.3.0 and the potential for a LEED certified building to be decertified suggests that landlords and building owners of LEED certified buildings begin using green leases. The green lease would include a clause to reward the landlord for operating a high-performance building, along with procedures and building control/management systems for charging tenants for after hours/excess energy usage. It would also include a hazardous materials clause, green cleaning specifications for cleaning the building in a sustainable manner, building rules and regulations that stipulate a building-wide recycling program along with a tenant construction agreement that defines sustainable product requirements and construction practices and a tenant guide that explains the building’s sustainable features and benefits, procedures and operating parameters. Some reports indicate that LEED buildings use more energy than non-certified buildings. This energy use is likely due to improper use of the building by the occupants rather than faulty design. Green building should continue to grow in spite of the global credit crisis and the economic recession in most countries. More people are going green each year, and there is no indication that this trend will cease.

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Local governments will increasingly mandate green buildings for public and private sectors. Concerns over the economics of green buildings mandates will be debated but more government agencies will order green buildings. Zero net energy designs for new buildings will gain more traction in both public and private buildings. As building energy drops down to low levels with better designs, it becomes more cost-effective to use green power for energy. Green homes will dictate many new home developments in more sections of the U.S., as builders increasingly use green as a selling point with European green building technologies being widely adopted in the U.S. and Canada as more firms open offices in the U.S. Green building is expected to grow more than a 60 percent in rate on a cumulative basis. The cumulative growth in new LEED projects has been over 60 percent per year since 2006 and it hit 80 percent in 2008. Green building results in more green jobs in energy efficiency, new green technologies and renewable energy. The focus of green building will begin to switch from new buildings to greening existing buildings. The fastest growing LEED rating system in 2008 was LEED for Existing Buildings. LEED Platinum-rated projects will become more common as building owners and designers strive to design higher levels of LEED achievement at lower costs. Concern of the growing global problems in the fresh water supply will push building designers and managers to reduce water consumption in buildings with more conserving fixtures, rainwater recovery systems and new innovative water systems. Solar power in buildings will advance due to the extension of solar energy tax credits for buildings through 2016 along with increasing utility concentration on renewable power goals for 2015 to 2020. Third-party financing will continue to grow and provide funding for large rooftop systems. References

Baden, S., et al., “Hurdling Financial Barriers to Lower Energy Buildings: Experiences from the USA and Europe on Financial Incentives and Monetizing Building Energy Savings in Private Investment Decisions,” Proceedings of 2006 ACEEE Summer Study on Energy Efficiency in Buildings, American Council for an Energy Efficient Economy, Washington, D.C., August 2006. Energy Roundup, Wall Street Journal Energy Roundup, 2007-05-03.

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Environmental Protection Agency Green Building Workgroup, Building and the Environment: A Statistical Summary, December 2004. Frej, Anne B., editor. Green Office Buildings: A Practical Guide to Development, Washington, D.C.: ULI—The Urban Land Institute, 2005. “Green Building Initiative,” http://www.thegbi.org/2007-05-24. The Power of Small Communities to LEED Change: Charlottesville, VA, Energy Spin, 200705-03. U.S. Department of Energy, Annual Energy Review 2006, June 26, 2007. Energy Information Administration. U.S. Department of Energy, “Energy Consumption by Sector.” 2007. World Business Council for Sustainable Development, August 2007, Energy Efficiency in Buildings: Business Realities and Opportunities. http://www.arcspace.com/books/ecodesign/ecodesign.html http://www.epa.gov/greenbuilding/pubs/components http://www.dcgreenworks.org

Chapter 4

Fuel Sources Keywords: Alcohol Fuels Methanol Ethanol Energy from Biomass Bioconversion Renewable Fuel Standard Cellulosic Fuel

Fuel from Algae Natural Gas Hydrogen Hydrogen Production and Growth Trends Research Trends Practical Aspects Biohydrogen

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hen oil prices are high, there is a demand for alternatives. Although we will eventually run out of oil, coal, and other non-renewable energy sources, in the short term rising oil prices produce more of the hard to get oil with improved technology as well as other more expensive forms of energy. There are large amounts of reserves that are too expensive to profitably develop when oil is below a certain price, as soon as the price rises above this threshold, a given oil field can be developed at a profit. Many older domestic fields with heavy crude are being developed using steam injection and recovery. Most of the initial interest in alternative fuels started after the oil crisis in the 1970s. It has been grown more recently by concerns about supply interruptions, high prices, air quality and greenhouse gases. Energy producers take advantage of higher prices to make use of their existing infrastructure to extract, refine, and distribute as much oil as possible. Current non-renewable energy supplies are still cheap but more expensive than they have been. The U.S. Environmental Protection Agency (EPA) has established the Renewable Fuel Standard (RFS) which was mandated by the Energy Policy Act of 2005. It required that by 2012, at least 7.5 billion gallons of renewable fuel be blended into motor vehicle fuel sold in the U.S. The 121

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EPA will no longer require facilities that use carbohydrate feedstocks in producing ethanol to count fugitive emissions of regulated pollutants. These are emissions that do not come from process stacks or vents. This may allow some plants to expand production. It will also allow new ethanol facilities to emit up to 250 tons of regulated pollutants per year in areas that are not exceeding EPA’s air quality standards and not in an Ozone Transport Region, where ground-level ozone is a concern. The program is based on a credit trading system that provides a flexible way to comply with the annual standard by allowing renewable fuels to be used where they are most economical. The program could cut petroleum use by almost 4 billion gallons and reduce annual greenhouse gas emissions by 13 million metric tons. ALCOHOL FUELS Fuel alcohol programs have been appearing in more and more countries. Energy independence, low market prices for sugar and other food crops, and large agricultural surpluses have been the main reasons for these programs. Countries with fuel alcohol programs are in Africa and Latin America, along with the United States and a few other countries. When fuels are produced from biomass, there is job creation in agriculture and related industries. Expanded production can also increase exports of byproducts such as corn gluten meal from ethanol. Brazil has been the major producer of ethanol in the world and began to make ethanol from sugar cane in 1975. By the 1990s, more than 4 million cars were using ethanol. The ethanol used in Brazil is a mixture of 95% ethanol and 5% water. A small amount (up to 3%) of gasoline is also used. Almost 90% of new cars in Brazil run on this mixture. The rest operate on a 20% ethanol/80% gasoline mix. The production of this ethanol requires about 1% of Brazil’s total farmable land. Sugar cane can be grown nearly yearround in Brazil, but the program has required government assistance. Methanol and ethanol are alcohol fuels that can be produced from various renewable sources. Alcohol fuels are converted from biomass or other feedstocks using one or several conversion techniques. Both government and private research programs are finding more effective, less costly methods of converting biomass to alcohol fuels. Methanol was

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originally a byproduct of charcoal production, but today it is primarily produced from natural gas and can also be made from biomass and coal. When methanol is made from natural gas, the gas reacts with steam to produce synthesis gas, a mixture of hydrogen and carbon monoxide. This then reacts with a catalytic substance at high temperatures and pressures to produce methanol. The process is similar when methanol is produced by the gasification of biomass. The production of methanol from biomass or coal can cost almost twice as much as production from natural gas. Considering the full production cycle, methanol from biomass emits less carbon dioxide than ethanol from biomass. This is because short rotation forestry, the feedstocks of methanol, requires the use of less fertilizer and diesel tractor fuel than the agricultural starch and sugar crops which are the feedstocks of ethanol. METHANOL AS FUEL Methanol, CH3 OH, is a clear liquid and also the simplest of the alcohols, with one carbon atom per molecule. Methanol is extensively used today, the U.S. demand in 2002 was over a billion gallons. Methanol is mainly synthesized from natural gas, it can also be produced from a number of CO2-free sources including municipal solid waste and plant matter. Methanol is already used as an auto fuel. It has been the fuel of choice at the Indianapolis 500 for more than three decades, partly because it improves the performance of the cars but it is also considered much safer. It is less flammable than gasoline and when it does ignite, it causes less severe fires. Methanol is also toxic and very corrosive, so it requires a special fuel-handling system. Methanol also seems to biodegrade quickly when spilled and it dissolves and dilutes rapidly in water. It has been recommended as an alternative fuel by the EPA and the DOE, partly because of reduced urban air pollutant emissions compared to gasoline. Most methanol-fueled vehicles use a blend of 85% methanol and 15% gasoline called M85. Biomass-generated methanol might be economical in the long term, but there is a significant amount of so-called stranded natural gas in areas around the globe that could be converted to methanol and shipped by tanker at relatively low cost. There would also need to be

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enough natural gas for a growing demand for gas-fired power plants and fuel cells. Methanol from natural gas would have little or no net greenhouse gas benefits. But, the price of methanol may not remain competitive with gasoline if methanol demand increases. Health and safety concerns would need to be solved and direct methanol fuel cells would need to be affordable. Methanol or wood alcohol is also a potential source or carrier of hydrogen. Building a methanol infrastructure would not be as difficult as converting to hydrogen. Fuel cell vehicles with onboard methanol reformers would have very low emissions of urban air pollutants. Daimler-Chrysler has built demonstration fuel cell vehicles that convert methanol to hydrogen. While methanol can be produced from natural gas, it can also be distilled from coal or even biomass. In the 1980s, methanol was popular for a brief time as an internal-combustion fuel. If fuel cell cars run on gasoline, there is minimum disruption, but many predict that methanol will serve as a bridge to direct hydrogen. Early fuel cell cars may run on methanol, but rapid advances in directhydrogen storage and production could bypass any liquid fuel phase. When gasoline or methane is used as a source of hydrogen, the hydrogen is separated from the hydrocarbon molecules using partial oxidation and autothermal reformers. Cost is an issue for onboard gasoline reformers and another is that the high temperature at which they operate does not allow for rapid starting. The reforming process also involves a loss of about 20% of the energy in the gasoline. Methanol reformers operate at lower temperatures of 250°C-350°C. Direct methanol fuel cells (DMFCs) can run on methanol without a reformer. In the 1920s the catalytic synthesis of methanol was commercialized in Germany. Even before that, methane was distilled from wood, but this pyrolysis of wood was relatively inefficient. The more widespread use of ethanol could have some safety benefits since Ethanol is water soluble, biodegradable, and evaporates easily. Ethanol spills tend to be much less severe with an easier clean up than petroleum spills. When agricultural surplus was used for the production of ethanol in the United States, it provided economic benefits to farmers and to the farming economy. In 1990, almost 360 million bushels of surplus grain were used to produce ethanol. In that year, it is estimated that ethanol

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production increased farm income by $750 million while federal farm program costs dropped by $600 million and crude oil imports fell by over forty million barrels. A major drawback of ethanol compared to methanol is its price which can be almost twice as much as methanol. But, both methanol and ethanol, as liquids, can use established storage and distribution facilities. Although most ethanol is now produced from corn, research has been done on producing this type of alcohol fuel from cellulosic biomass products including energy crops, forest and agricultural residues, and MSW, which would provide much cheaper feedstocks. The process of chemically converting these cellulosic biomass feedstocks is more involved and until this process can be simplified the price of ethanol will remain high. BIOMASS ENERGY Biomass energy comes from organic plants or animal matter. Biomass energy or bioenergy is a general term for the energy stored in organic wastes. The energy conversion process includes harvesting crops and burning them or distilling their sugars into liquid fuels. Biomass energy production can replace a variety of traditional energy sources such as fossil fuels in solid or liquid forms. One of the most common sources of biomass energy is wood and wood wastes. Other sources include agricultural residues, animal wastes, municipal solid waste (MSW), microalgae and other aquatic plants. Medium-Btu gas is already being collected at more than 120 landfills in the U.S. Crops that may be grown for harvesting their energy content include grains, grasses, and oil-bearing plants. Although obtaining and transporting feedstocks can be an obstacle, the USDA and DOE believe that as plants are built around the country, this will create local demand and farmers will respond. Plants create energy through photosynthesis using solar radiation and converting carbon dioxide and water into energy crops. Biomass technology allows the use of that energy by transforming it through a variety of processes. The three basic types of bioenergy conversion are direct combustion, thermochemical conversion, and biochemical conversion.

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The direct combustion of wood and other plant matter has been a primary energy source in the past. Any type of biomass can be burned to produce heat or steam to turn a generator or perform mechanical work. Direct combustion is used in large power plants that produce up to 400 megawatts. Most direct combustion systems can use any type of biomass as long as the moisture content is less than 60%. Wood and wood residues are commonly used along with a number of other agricultural residues. A characteristic of biofuels is that three fourths or more of their energy is in the volatile matter or vapors, unlike coal, where the fraction is usually less than half. It is important that the furnace or boiler ensure that these vapors burn and are not lost. For complete combustion, air must reach all the char, which is achieved by burning the fuel in small particles. This finely-divided fuel means finely-divided ash particulates which must be removed from the flue gases. The air flow should be controlled since too little oxygen means incomplete combustion and leads to the production of carbon monoxide. Too much air is wasteful since it carries away heat in the flue gases. Modern systems for burning biofuels include large boilers with megawatt outputs of heat. Direct combustion is also used to extract the energy contained in household refuse, but its moisture content may be 20% or more and its energy density is low. A cubic meter contains less than 1/30th of the energy of the same volume of coal. Refuse-derived fuel (RDF) refers to a range of products resulting from the separation of unwanted components, shredding, drying and treating of raw material to improve its combustion properties. Relatively simple processing can involve separation of large items, magnetic extraction of ferrous metals and rough shredding. The most fully processed product is known as densified refuse-derived fuel (d-RDF). It is the result of separating out the combustible part which is then pulverized, compressed and dried to produce solid fuel pellets with about 60% of the energy density of coal. Biomass technology allows the carbon in the organic matter to be recycled. Unlike the burning of fossil fuels, the combustion of biomass recycles the carbon set by photosynthesis during the growth of the plant. In biomass energy production, the combustion of plant matter releases no more carbon dioxide than is absorbed by its growth and the net contribution to greenhouse gases is zero.

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When biomass is transformed into energy by burning, it releases CO2 that was previously sequestered or held in the atmosphere, for some time, so the net CO2 emitted is zero. Biomass provides the potential of a sustainable way of providing energy. Wood and wood waste includes residues from the forest and the mill. Bark, sawdust and other mill wastes are all suitable fuels. Agricultural residues include corncobs, sugar cane bagasse (the stalks after processing), leaves, and rice hulls. MSW materials include paper products, cloth, yard wastes, construction debris, and packaging materials. Biomass materials depend on local conditions. In tropical areas, sugar cane is widely grown and bagasse is available as an energy feedstock. Rice growing areas have rice husks available. The Midwestern area of the U.S. can use corn husks and forested areas have timber residues. One source of ethanol is sugar cane or the molasses remaining after the juice has been extracted. Other plants such as potatoes, corn and other grains require processing to convert the starch to sugar. This is done by enzymes. Biodiesel fuel is derived from vegetable oils or waste animal fats. It is a renewable, clean burning fuel that can be used for diesel engines or oil heating. Thermochemical conversion processes use heat in an oxygen controlled environment that produce chemical changes in the biomass. The process may produce electricity, gas, methanol and other products. Gasification, Pyrolysis, and Liquefaction Gasification, pyrolysis, and liquefaction are thermochemical methods for converting biomass into energy. Gasification involves partial combustion to turn biomass into a mixture of gases. Gasification processes may be direct or indirect. The direct processes uses air or heat to produce partial combustion in a reactor. Indirect processes transfer the heat to a reactor and its walls using heat exchangers or hot sand. This process produces low or medium BTU gases from wood and wood wastes, agricultural residues and MSW. This synthesis gas (syngas) contains carbon monoxide, carbon dioxide and hydrogen. Processing these synthetic gases with water can also produce ammonia or methanol. Commercial gasification systems exist, but their widespread use has been limited by hauling distances for the feedstock. Pyrolysis is a type of gasification that breaks down the biomass in oxygen deficient environments, at temperatures of up to 400°F. This

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process is used to produce charcoal. Since the temperature is lower than other gasification methods, the end products are different. The slow heating produces almost equal proportions of gas, liquid and charcoal, but the output mix can be adjusted by changing the input, the temperature, and the time in the reactor. The main gases produced are hydrogen and carbon monoxide and dioxide. Smaller amounts of methane, ethane, and other hydrocarbons are also produced. The solids left are carbon and ash. The liquids are similar to crude oil and must be refined before they can be used as fuels. Liquefaction systems use wood and wood wastes as the most common fuel stocks. They are reacted with steam or hydrogen and carbon monoxide to produce liquids and chemicals. The chemical reactions that take place are similar to gasification but lower temperatures and higher pressures are used. Liquefaction processes may be direct or indirect. The product from liquefaction is pyrolytic oil which has a high oxygen content and can be converted to diesel fuel, gasoline or methanol. BIOCONVERSION Biochemical conversion, or bioconversion is a chemical reaction caused by treating moist biomass with microorganisms such as enzymes or fungi. The end products may be liquid or gaseous fuels. Fermenting grains with yeast produces a grain alcohol. The process also works with other biomass feedstocks. In fermentation, the yeast decomposes carbohydrates which are starches in grains, or sugar from sugar cane juice into ethyl alcohol (ethanol) and carbon dioxide. The process breaks down complex substances into simpler ones. Anaerobic digestion involves limiting the air to moist biomass such as sewage sludge, MSW, animal waste, kelp, algae, or agricultural waste. The feed stock is placed in a reaction vessel with bacteria. As the bacteria break down the biomass, they create a gas that is 50 to 60% methane. Small-scale digesters are used on Asian and European farms and sewage treatment plants use this process to generate methane. Digesters are also used to compost municipal organic waste. The larger systems can handle 400,000 cubic feet of material and produce 1.5 million cubic feet of biogas per day while small systems may handle 400 cubic feet of material and produce 6,000 cubic feet of biogas a day.

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Methane made from anaerobically digested manure was used to light streets in England as early as 1895. Anaerobic digestion is also used to produce fertilizers. Gasification technology has been in a period of intensive development in the past few decades. Large-scale demonstration facilities have been tested and some commercial units are in operation. The application of gasification has been impeded by economic and not technical considerations. In the past, the product from gasification has been electricity or heat, but the value of these products has not been enough to justify the capital and operating costs. However, if gasification is combined with the production of higher value liquid fuels, it can become a more viable alternative energy technology. After gasification, anaerobic bacteria can be used to convert the syngas into ethanol. This is done by Bioengineering Resources, Inc. (BRI) which uses syngas fermentation technology to produce ethanol from cellulosic wastes with high yields and rates. Combined gasification/fermentation as used by BRI allows the yields to be high since most of the raw material, except for the ash and metal, is converted to ethanol. BRI’s bioreactor systems for fermentation have retention times of only a few minutes at atmospheric pressure and less than a minute at elevated pressures. These retention times lower equipment costs. Biomass is not a renewable resource unless creation of the source equals or exceeds its use. This is true in energy farms and standard crops, particularly forests. In the Canada of 1867, biomass supplied 90% of the energy. As coal and then oil became more widespread, the use of biomass dropped, reaching a low point by 1960. Since then, the trend is upward with biomass gaining popularity as an energy source. In the forest products industry, wood waste supplies a large percentage of the energy needed. This ranges between 65 and 100%, depending on the country. Biomass supplies almost 15% of the world’s energy. In developing countries this amount can be as high as 50%. Nepal, Ethiopia, and Haiti derive most of their energy from biomass. Kenya, Maldives, India, Indonesia, Sri Lanka, and Mauritius derive over half. The most common power plant sizes range from 2-MW to 10-MW although some plants are over 30-MW. Rice husks and other biomass waste is mixed in with wood in some plants. Just a few years ago, many industries did not believe they could

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produce biogas from their waste but today biogas production is common is Asia. The most common systems are up-flow anaerobic sludge blanket (UASB), anaerobic fixed film reactor (AFFR), continuous stirred tank reactor (CSTR), covered in-ground anaerobic reactor (CIGAR) along with covered lagoons. In the U.S. about 8% of the energy is provided by biomass and almost 90% of this comes from the combustion of wood and wood residues. The use of biomass for electric power increased from an installed capacity of 200-MW in 1980 to over 7,700-MW in 1990. The search for cleaner fuels and landfill restraints are major reasons for increased biomass interest. The cost of waste disposal has soared as landfill sites closed and few new ones opened up. By the 1990s several states had developed notable biomass energy. Florida’s power plants generated more than 700 megawatts of energy from biomass and almost one fourth of Maine’s baseload requirements were met with biomass generation. Hawaii generated about one half of its energy from renewable sources and one half of this came from biomass. States with large populations used biomass to help dispose of their waste. Florida, California and New York were large users of MSW for energy. In Canada, biomass energy equaled the energy produced by nuclear plants and represented about one half of that produced from coal. Biomass made up 12% of the energy in the Atlantic area and almost 25% in British Columbia. In Canada, biomass energy was used for greenhouse heating, health-care facilities, educational institutions, office and apartment buildings, and large industrial plants including automobile manufacturing and food processing. Developed nations that generated higher proportions of their energy from biomass include Ireland with 17% and Sweden with 13%. Biomass feedstocks can be used to create gaseous and liquid fuels. These can be used on-site, to improve the efficiency of the process or they can be used in other applications. Sugar, starch or lignocellulosic biomass such as wood, energy crops, or MSW can provide alcohols such as methanol, ethanol, and butanol. These fuels may be used as a substitute, or additive, to gasoline. In the biofuel process plant grains and fiber are converted into sugar and fermented into ethyl alcohol or ethanol. Typically used as a blending agent with gasoline, higher concentrations can reduce greenhouse gasses by 80% compared to straight gasoline.

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ETHANOL FUEL Most ethanol has been made from corn. This ethanol provides about 25% more energy than that required to grow the corn and distill the ethanol. Ethanol from other sources includes dedicated energy crops such as switchgrass, which may be grown and harvested with less energy consumption. Methanol can also be produced from biomass by chemical processes. Fermentation is an anaerobic biological process where sugars are converted to alcohol by micro-organisms, usually yeast. The resulting alcohol is ethanol which can be used in internal combustion engines, either directly in modified engines or as a gasoline extender in gasohol. This is gasoline containing up to 20% ethanol. Ethanol saw several spikes of popularity during the last century, notably during the world wars when petroleum demand soared. In more recent decades, the use of alcohol fuels has seen rapid development. Ethanol comes from distilleries using corn, sorghum, sugar beets and other organic products. The ethyl alcohol, or ethanol fuel produced is generally mixed in a ratio of 1 to 10 with gasoline to produce gasohol. The mash, or debris, that is left behind contains all the original protein and is used as a livestock feed supplement. A bushel of corn provides two and a half gallons of alcohol plus byproducts that can almost double the corn’s value. Most of the ethanol in the United States has been made from fermenting corn. Dry-milling or wet-milling can be used. In dry-milling, the grain is milled without any separation of its components. The grain is mashed and the starch in the mash is converted to sugar and then to alcohol with yeast. In wet-milling, the corn is first separated into its major components, the germ, oil, fiber, gluten and starch. The starch is then converted into ethanol. This process produces useful byproducts such as corn gluten feed and meal. The only other country with a significant production of ethanol is Brazil which makes its fuel from sugar cane. In 1979 only 20 million gallons of ethanol were being produced in the United States each year. By 1983, this had jumped to 375 million gallons annually and by 1988 to almost 840 million gallons annually. More than sixty ethanol production facilities were operating by 1993 in the United States in twenty-two states. Farm vehicles were being converted to ethanol fuel and demonstration programs were underway for testing

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light-duty vehicles. The nation’s first E85 (85% ethanol) fueling station opened in La Habra, CA, in 1990. The station was operated by the California Renewable Fuels Council. The bulkier biomass crops such as wood waste, switchgrass, miscanthus or other cellulosic feedstocks have less sugar than corn or sugar cane, so it requires more biomass volume to yield the same quantity of ethanol that corn or sugar cane produce. Ethanol is a renewable source of energy, but critics question turning food-producing land into energy production. Cellulose ethanol eliminates the diversion of food crops to fuel. It can be produced from agricultural residues which are often destroyed by burning. The energy bill passed by the U.S. Senate mandates oil companies to blend in 21 billion gallons of cellulosic ethanol with their gasoline by 2022. Farm lawmakers push for more biofuel with legislation for loans, grants and other incentives for the building and start up of biorefineries. There are also loans, loan guarantees and grants to farmers, ranchers and small businesses for renewable energy systems, such as wind turbines and biodigesters to harvest methane from animal waste. Incentives would be provided to farmers who grow dedicated energy feedstock crops. The Forest Biomass for Energy program will research the harvesting, transporting and processing of woody biomass for bioenergy production. There are also programs for the feasibility studies for ethanol pipelines, funds for USDA to buy up excess sugar stock for ethanol and grants for improving energy efficiency on farms. Green payments may also be included. These are USDA payments to farmers and ranchers who implement whole-farm comprehensive conservation plans. This funding goes along with encouraging production to meet the demand for biofuels by increasing soil and water conservation. Research at the DOE, Oak Ridge National Laboratory and the Regional Biomass Processing Center at Michigan State University have been involved in treating the plant material to make it denser and easier to ship. USDA researchers in biodiesel have been researching peanuts in Georgia. Varieties such as Georganic have been found to be high in oil content with low production costs, requiring only one herbicide application and no fungicides. The Georganic plants are not suitable for the growing of edible peanuts. Traditional peanuts can produce 120 to 130

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gallons of biodiesel per acre, compared with about 50 gallons of biofuel per acre from soybeans. A cost efficient way to utilize wheat in ethanol production has been developed by researchers from Greece and the U.K. This process splits the grain into separate components, separating out the nonfermentable solids, and then uses a group of enzymes to ferment the proteins and starches using a single liquefaction and saccharification step. There is the potential of 75 billion gallons a year of carbon-neutral ethanol using the Zymetis process on a Chesapeake Bay marsh grass bacterium. This bacterium has an enzyme that can be quickly broken down into sugar, which can then be converted to biofuel. Ethanol is a healthy industry in some parts of the United States and the rest of the world. Brazil has a large ethanol industry, producing about three billion gallons each year from sugar cane. In 2007 corn acreage was up almost 20% from 2006. This caused corn prices to drop 40 cents to 50 cents a bushel, but increasing demand for corn to produce ethanol and to feed livestock in Asia, Latin American and elsewhere kept world stocks low. China’s rapid growth in ethanol output dropped off due to a government rule in 2007 that restricts production to nonfood feedstocks. The country has four state licensed and subsidized fuel grade ethanol plants and another 6 to 10 new plants that will use cassava and sorghum, instead of corn. The Chinese government does not consider cassava and sorghum as food grains, but they are staples in some countries. China plans to lease several million acres in Laos and Indonesia for the production of cassava and palm oil. Distiller grains (DG) ethanol’s main coproduct and the potential to use these coproducts is great according to USDA’s National Agricultural Statistics Service (NASS). A NASS survey found that of more than 9,000 livestock operations, more than a fifth of dairy producers and a third of both hog and beef producers were considering adding DG to their livestock feed. Others predict that the ratio of corn to distillers grains being fed to livestock will go from 11/1 to 3/1 in 10 years. DG replaces corn pound for pound in feed rations, usually at a lower price, so it will be in demand. The main barrier to the use of DG has been availability. Distiller grain sales can drop the cost of corn by about a third. When corn is $3 a bushel, an ethanol producer gets $1 back from distiller grain sales.

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CELLULOSIC FUEL The commercial production of cellulosic ethanol is closer due to advances in technology along with federal and private funding for new plants and research centers. Volume production could push the cost of ethanol from cellulosic feedstocks to well below the cost of corn ethanol. The process of using concentrated acid hydrolysis was developed in the 1940s but new biological and gasification technologies are expected to cut costs by $1 a gallon, making the fuel competitive with both corn ethanol and gasoline. When the costs of building a new gasoline refinery are included, gasoline would cost about the same as making cellulosic ethanol using traditional acid hydrolysis. The biggest hurdle is the high capital cost of cellulosic biorefineries, which are two to three times more than corn ethanol plants. But these costs are expected to come down significantly. A cellusosic biorefinery requires a large amount of expensive equipment, but as process improvements occur less expensive equipment should be required. The Department of Energy (DOE) is helping six firms build cellulosic biorefineries with grants totaling about $385 million. The plants can produce more than 130 million gallons of cellulosic ethanol a year. DOE has also invested $375 million into three new Bioenergy Research Centers to speed up the development of cellulosic ethanol and other biofuels. POET LLC of Sioux Falls, S.D., has plans for a 125 million gallon a year biorefinery in Emmetsburg, Iowa. POET is one of several companies pursuing the production of cellulosic ethanol using enzymatic hydrolysis to break down the cellulose and produce sugars. This process will be aided with the development of genetically modified enzymes and other microorganisms from Verenium Corporation and Mascoma Corporation in Cambridge, MA. They have developed microorganisms that generate enzymes that both break down the biomass cell walls, exposing the sugars, and ferment the sugar into ethanol. This represents major cost savings since it typically costs 10-15 times as much for the enzymes used in the fermentation of cellulosic material that those used in corn-based ethanol production. A demonstration-scale cellulosic ethanol plant in Jennings, LA., is expected to have an output of 1.4 million gallons a year, using sugar cane bagasse and a special breed of energy cane as feedstocks. A commercialscale cellulosic ethanol plant operated by Mascoma will use wood chips and other nonfood agricultural crops in Michigan. Dynamotive Energy

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Systems will work with Mitsubishi on a series of projects, using Dynamotive’s technology for small plants. Based in Vancouver, Canada this cellulosic ethanol company has offices in the U.S., U.K. and Argentina. Other companies, such as Genencor and Novozymes are providing producers with enzymes that are genetically modified to extract the sugars from a variety of biomass feedstocks. Verenium, Mascoma, Cargill, DuPont and Archer Daniels Midland have received DOE grants totaling $23 million for improved microorganisms. Codon Devices and Agrivida are working on the development of corn varieties using genetically engineered enzymes that degrade the cornstalk, husks and other plant material into sugars. Other companies are working on thermochemical processes that do not use enzymes. Range Fuels of Broomfield, CO, is working on such a plant in Soperton, GA. Range Fuels has a grant of up to $76 million from DOE and will use a two-step process to convert biomass wood chips and forest residue first to synthesis gas and then to ethanol. Initially the plant will produce almost 20 million gallons of ethanol a year with the output to be increased by 100 million gallons per year. Eventually, the company plans to reach 1 billion gallons a year with all its plants. Alico will also use a thermochemical process to provide up to 14 million gallons of ethanol a year at a plant in LaBelle, Florida. Alico has a $33 million DOE grant and will gasify wood waste and agricultural residues into ethanol, ammonia and hydrogen. NewGen Technologies in Charlotte, NC, and its subsidiary, NewGen BioFuels, bought several biofuel producers to secure supplies of ethanol and biodiesel for its terminals owned by ReFuel America, NewGen’s U.S. fuel distribution subsidiary. In Houston, the GreenHunter BioFuels converted an existing waste oil/chemical refinery to produce biodiesel and methanol. The plant will use a variety of feedstocks, including soy, palm and jatropha oils and/ or animal and poultry fats. The BlueFire Ethanol Fuels cellulose-toethanol plant near Lancaster, in northern Los Angeles County will use agricultural and wood waste streams as feedstock. It is designed to use recycled water and will supply almost 70% of its energy with lignin, an ethanol coproduct. BlueFire plans to use this plant as the model for factory-made system modules that can be quickly erected at other sites. Eventually different technologies will be used for different feedstocks. The three approaches are concentrated acid hydrolysis, thermochemical and biological. A hybrid may also emerge.

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FUEL FROM ALGAE Algae requires only sunlight, water and carbon dioxide to grow and can quadruple in a day. It can remove pollutants from the air and water and has the potential to replace gasoline in the U.S. Algae as a feedstock for biofuels has many advantages over other biomass sources and it may eventually eclipse all others. Algae are highly efficient as converters of solar energy into chemical fuel. Some strains are over 50% oil and their yield per acre is very high. The average per-year, per-acre oil yield for algae grown for use in the food and pharmaceutical industries today is enough to make about 5,000 gallons of biodiesel. While an acre of soybeans can provide about 70 gallons of biodiesel and an acre of corn about 420 gallons of ethanol. The potential yield of algae according to the Department of Energy’s National RenewableEnergy Laboratory, is up to 15,000 gallons of biodiesel a year from a saltwater pond. GreenFuel Technology Corporation of Cambridge, MA has been working with power plants in Arizona, Louisiana and Germany to build algae producing photobioreactors. GreenFuel’s system captures about 80% of the carbon dioxide emitted during the daytime sun. GreenFuel is also building a 1000-m square algae facility in Jarez, Spain, which will produce about 25,000 tons of algae biomass. Solix Biofuels plans to begin large-scale production on a 10-acre site on the Southern Ute Indian Reservation in Southwest Colorado. There are estimates that Arizona could supply 40 to 60 billion gallons of road fuels, biodiesel and ethanol from algae utilizing its open space. Algae may play a major role since it uses wastewater and carbon dioxide and releases oxygen and clean water. Along with carbon dioxide algae also absorbs nitrates and phosphates. Algae can produce 15 times more biofuel per acre than jatropha, grapeseed, and palm, and 20 times more than corn or soy. Investments in algae in the U.S. are estimated to be one half to one billion dollars. The European Union is investing 2.7 billion Euros in algae over seven years and is including algae in its Seventh Framework Programme. However, there have been some setbacks, the Japanese Research for Innovative Technology of the Earth program spent $100 million on closed algae systems before ending the program. In 1996 the U.S. Aquatic Species program was ending after three decades of research at two 1,000 square meter open ponds as too expensive for large-scale

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production. Algae need a steady steam of carbon dioxide, and Seambiotic Ltd of Israel is using flue gas from a coal-fired power plant. Other users of algae are the Fischer-Tropsch fuel production facilities for coal to liquids and gas to liquids and natural gas power plants in the U.S. The Maryland based Alganol has licensed its technology to Biofields of Mexico which is building a massive algae farm in Northwest Mexico. Biofuels could start producing about 400 liters of ethanol a year and increase this to one billion by 2012 using a process that avoids dewatering, crushing or processing the algae. Ocean Technology & Environmental Consulting (OTEC) has been developing photobioreactors that produce algae in layers or shallow ponds. These organisms also thrive on harmful emissions such as nitrogen from wastewater and carbon dioxide from power plants. The Mohave Generating Station in Laughlin, Nevada, will use photobioreactors to capture carbon emissions from the plant. The CO2 will then be used to increase production at a nearby site. In 2007, about 4% of all the fuel sold or dispensed to U.S. motorists came from renewable sources, which is almost 5 billion gallons of renewable fuels. New and expanded plants now under construction are expected to push the annual production of ethanol well above this level. NATURAL GAS Natural gas (NG) is found in underground reservoirs and consists mainly of methane, with smaller amounts of other hydrocarbons such as ethane, propane, and butane along with inert gases such as carbon dioxide, nitrogen, and helium. The composition depends on the region of the source. When it is used as an engine fuel, natural gas is in compressed form as compressed natural gas (CNG) or in liquid form as liquefied natural gas (LNG). Natural gas is gaseous rather than liquid in its natural state. The United States has been a major producer and user of natural gas. But, only a few percent of production is used for vehicles, construction and other equipment including power generation. Worldwide, about a million vehicles in thirty-five countries operate on natu-

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ral gas. Some of the countries where natural gas is widely used include New Zealand, Italy and countries of the former Soviet Union. Liquid natural gas has also been used for taxis in Korea and Japan. There are about 300 NG filling locations in the United States, most are used by private fleets, but about one-third are open to the public. This fuel is more appropriate for fleet vehicles that operate in limited geographical regions and that return to a central location every night for refueling. In 1991 the California Air Resources Board certified a compressed natural gas (CNG) powered engine as the first alternative fueled engine certified for use in California. The board also sponsored a program to fuel school buses with CNG. While CNG has been used for fleet and delivery vehicles, most tanks hold enough fuel for a little over 100 miles. While natural gas has been plentiful, supplies are limited and increased demand has caused the cost to increase. Besides the range limitation, natural gas vehicles can cost more due to the need to keep the fuel under pressure. The weight and size of the pressure tank also reduces storage space and affects fuel economy. Most gasoline-powered engines can be converted to dual-fuel engines with natural gas. The conversion does not require the removal of any of the original equipment. A natural gas pressure tank is added along with a fuel line to the engine through special mixing equipment. A switch selects either gasoline or natural gas/propane operation. Diesel vehicles can also be converted to dual-fuel operation. Natural gas engines may use lean-burn or stoichiometric combustion. Lean-burn combustion is similar to that which occurs in diesel engines, while stoichiometric combustion is more similar to the combustion in a gasoline engine. Compressed natural gas has a high octane rating of 120 and produces 40 to 90% lower hydrocarbon emissions than gasoline. There are also 40 to 90% lower carbon monoxide emissions and 10% lower carbon dioxide emissions than gasoline. Natural gas can also be less expensive than gasoline on a per gallon-equivalent. Maintenance costs can also be lower compared to gasoline engines since natural gas causes less corrosion and engine wear, however, refilling takes two to three times longer than refilling from a gasoline pump. Some slow fill stations can take several hours.

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HYDROGEN Hydrogen and electricity are complementary and one can be converted into the other. Hydrogen can be viewed as a type of energy currency that does not vary in quality depending on origin or location. A molecule of hydrogen made by the electrolysis of water is the same as hydrogen manufactured from green plant biomass, paper, coal gasification or natural gas. Hydrogen is the lightest and most abundant element in the universe. It can exist as a gas or a liquid and can also be stored at room temperature in a solid form (hydride) as a compound. Hydrogen is a primary chemical feedstock in the production of gasoline, fuel oils, lubricants, fertilizers, plastics, paints, detergents, electronics and pharmaceutical products. It is also an excellent metallurgical refining agent and an important food preservative. Hydrogen can be extracted from a range of sources since it is in almost everything, from biological tissue and DNA, to petroleum, gasoline, paper, human waste and water. It can be generated from nuclear plants, solar plants, wind plants, ocean thermal power plants or green plants. Since hydrogen burns cleanly and reacts completely with oxygen to produce water vapor, this makes it more desirable than fossil fuels for essentially all industrial processes. For example, the direct reduction of iron or copper ores could be done with hydrogen rather than smelting by coal or oil in a blast furnace. Hydrogen can be used with conventional vented burners as well as unvented burners. This would allow utilization of almost all of the 30 to 40% of the combustion energy of conventional burners that is lost as vented heat and combustion byproducts. If hydrogen is burned in a combustion chamber instead of a conventional boiler, high-pressure superheated steam can be generated and fed directly into a turbine. This could cut the capital cost of a power plant by one half. When hydrogen is burned, there is essentially no pollution. Expensive pollution control systems, which can be almost one third of the capital costs of conventional fossil fuel power plants, are not required. This should also allow plants to be located closer to residential and commercial loads, reducing power transmission costs and line losses. Hydrogen is known as a secondary energy carrier, instead of a primary energy source. Energy is needed to extract the hydrogen from wa-

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ter, natural gas, or other compound that holds the hydrogen. This representation is not exact since it assumes that solar, coal, oil or nuclear are primary energy sources, but energy is still expended to acquire them. Finding, extracting and delivering the so-called primary energy sources requires energy and major investments before they can be utilized. Coal and natural gas are closer to true primary energy sources since they can be burned directly with little or no refining, but energy is still needed to extract these resources and deliver them to where the energy is needed. Even when extensive drilling for oil is not required from shallow wells or pools, energy is still needed for pumping, refining and delivery. If hydrogen could become the prime provider of energy, that would solve the problems of atmospheric pollution and oil depletion. Hydrogen has an energy content three to four times higher than oil, and it can be produced from all known energy sources, besides being a byproduct of many industrial processes. Hydrogen-powered fuel cells have wide applications and could replace batteries in many portable application, power vehicles and provide home and commercial electrical needs. Making hydrogen from water through electrolysis was initially promoted by nuclear engineers who thought that nuclear generated power would be inexpensive enough to make hydrogen. In Britain, an early hydrogen-fueled home was financed by the Swedish steel industry and SAAB along with other firms. Power at the home was provided by a computer-controlled windmill which was used to electrolyse filtered water into hydrogen and oxygen. The hydrogen gas was used for cooking and heating the house and as fuel for a SAAB car. The National Academy of Sciences has stated that the transition to a hydrogen economy could take decades. Challenges exist in producing, storing and distributing hydrogen in ample quantities at reasonable costs without producing greenhouse gases that may affect the atmosphere. The extraction of hydrogen from methane generates carbon dioxide. If electrolysis is used for splitting water into hydrogen and oxygen, the electricity may be produced by burning fossil fuels which generates carbon dioxide. Hydrogen is also a leak-prone gas that could escape into the atmosphere and set off chemical reactions. Production and Storage Most of the hydrogen that is manufactured now is made by reacting natural gas with high temperature steam, to separate the hydrogen

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from the carbon. Natural gas has a hydrocarbon molecule of four hydrogen atoms bonded to one carbon atom. The high temperature steam separated the hydrogen from the carbon. Using fossil fuels to make hydrogen can take more energy than that contained in the hydrogen. Even high-temperature electrolysis where an electric current is sent through water that is heated to about 1,000°C produces about half the energy compared to the energy required for the process. Hydrogen can also be manufactured from coal-gasification facilities. But making hydrogen from nonrenewable fossil fuels does not solve the problem of diminishing resources or the environmental problems. Since most of the easy-to-get oil has already been found, exploration efforts have to drill in areas that are more difficult and many areas have been closed to drilling in the U.S. At some point, in the future, it may take more energy to extract the remaining fossil fuels than the energy they contain. Hydrogen production for commercial use goes back more than a hundred years. Hydrogen is used to synthesize ammonia (NH3), for fertilizer production, by combining hydrogen with nitrogen. Another major use is hydro-formulation, or high-pressure hydro-treating, of petroleum in refineries. This process converts heavy crude oils into engine fuel or reformulated gasoline. It is also used as an industrial chemical, a coolant and an aerospace fuel. The annual world production is about 45 billion kgs or 500 billion Normal cubic meters (Nm3). A Normal cubic meter is a cubic meter at one atmosphere of pressure and 0°C. About one half of this is produced from natural gas and almost 30% comes from oil. Coal accounts for about 15% and the other 4-5% is produced by electrolysis. Hydrogen production in the U.S. is about 8 billion kg (approximately 90 billion Nm3). This is the energy equivalent of 8 billion gallons of gasoline. Hydrogen demand increased by more than 20% per year during the 1990s and has been growing at more than 10% per year since then. Most of this growth has been due to seasonal gasoline formulation requirements. Liquid hydrogen fuel systems would require changes in the energy infrastructure and end use systems, such as stoves, engines and fueling systems. While disadvantages of liquid hydrogen are substantial, they can be minimized. Although cryogenic fuels are difficult to handle, an early selfservice liquid hydrogen pumping station was built decades ago at Los

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Alamos National Laboratory. It was shown to be feasible for refueling vehicles over an extended period of time without any major problems. Today, there are a number of hydrogen refueling stations in various parts of the world. Cryogenic storage is used by the National Aeronautics and Space Administration (NASA) for hydrogen, which along with liquid oxygen is used for rocket fuel since World War II. As a fuel for the space shuttle, almost 100 tons (400,000 gallons) are stored in the shuttle’s external tank. A shuttle launch refueling requires fifty tanker trucks to travel from New Orleans to the Kennedy Space Center in Florida. This represents a great deal of experience in shipping liquid hydrogen. Since 1965, NASA has moved over 100,000 tons of liquid hydrogen to Kennedy and Cape Canaveral by tanker truck. Liquid hydrogen can be stored in newer vessels that are relatively compact and lightweight. General Motors has designed a 90-kg cryogenic tank that holds 4.6-kg (34 gallons) of liquid hydrogen. Liquefying hydrogen requires special equipment and is very energy-intensive. The refrigeration requires multiple stages of compression and cooling and about 40% of the energy of the hydrogen is required to liquefy it for storage. Smaller liquefaction plants tend to be more energy-intensive which presents a problem for local fueling stations. Even in large, centralized liquefaction units, the electric power requirement is high with 12 to 15 kilowatt-hours (kWh) needed per kilogram of hydrogen liquefied. A problem with liquefied hydrogen is evaporation since hydrogen in its liquid form can easily boil off and escape from the tank. NASA loses almost 100,000 pounds of hydrogen when fueling the shuttle requiring 44% more to fill the main tank. Liquid hydrogen requires extreme precautions in handling because of the low temperature. Fueling is usually done mechanically with a robot arm. Compressed hydrogen has been used in prototype vehicles for many years. Hydrogen compression is a mature technology and low in cost compared with liquefaction. The hydrogen is compressed to 3,600 to 10,000 pounds per square inch (psi), but even at these high pressures, hydrogen has a much lower energy per unit volume than gasoline. The higher compression allows more fuel to be contained in a given volume and increases the energy density but it also requires a greater energy input. Compression to 5,000 or 10,000 psi takes several stages and requires an energy input equal to 10 to 15% of the fuel’s

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energy. Compressing 1-kg of hydrogen into 10,000 psi tanks can take 5-kWh or more of energy. Compressed hydrogen can be fueled relatively fast, and the tanks can be reused many times. The primary technical issues are the weight of the storage tank and the volume needed. Tank weight is being improved with the use of stronger and lightweight materials and tank volume is reduced with the use of higher pressures. Once 5,000 psi tanks were considered to be the maximum allowable, but now 20,000 psi tanks are being built. GM has developed a 20,000 PSI (700 bar) hydrogen storage system which extended the range of the HydroGen3 fuel cell vehicle by 60-70 percent compared to an equivalent-sized 5,000 PSI system. But, the higher pressures also increases costs and complexity requiring special materials, seals and valves. Pressure tanks are usually cylindrical in order to provide integrity under the pressure with some flexibility in design. Liquid fuel tanks can be shaped according to their needs. Storage in metals involves metal hydrides where the hydrogen is chemically bonded to one or more metals and released with a catalyzed reaction or heating. Metal hydrides can hold a large amount of hydrogen in a small volume. A metal hydride tank may be one third the volume of a 5,000 psi liquid hydrogen tank. The hydrides can be used for storage in a solid form or in a waterbased solution. When a hydride has released its hydrogen, a byproduct remains in the fuel tank to be either replenished or disposed of. Hydrides may be reversible or irreversible. Reversible hydrides act like sponges, soaking up the hydrogen. They are usually solid alloys or intermetallic compounds that release hydrogen at specific pressures and temperatures and may be replenished by adding pure hydrogen. Irreversible hydrides are compounds that go through reactions with other reagents, including water, and produce a byproduct that may have to be processed at a chemical plant. Some hydrides are heavy and their storage capacity may be less than 2% by weight, so each 1-kg of hydrogen can require 50-kg or more of tank. A tank with 5-kg of hydrogen could weigh more than 250-kg. Hydrogen may be used to generate power by combustion or by using direct conversion with fuel cells. Both methods are efficient and environmentally clean. Hydrogen produced from electrolyzing water or from reforming fossil fuels is currently used in more than one hundred different industries ranging from petrochemical and glass manufacturing to food processing and electronics. The use of hydrogen is growing

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rapidly worldwide but the Hydrogen Economy will be realized when hydrogen becomes competitively priced as an energy commodity rather than as a chemical substance. Hydrogen energy for commercial power is primarily the result of the initial investments the U.S. made in defense and aerospace technology. NASA is one of the largest users of hydrogen as a fuel. The Department of Defense and the Department of Transportation are expanding the use of hydrogen both as a fuel and in the uses of fuel cells. GROWTH TRENDS The potentially large economic and security advantages of using locally produced hydrogen as a widespread energy carrier for both stationary and transportation applications has been recognized by the Hydrogen Future Act, which enjoyed widespread bipartisan support. A Vice Presidential task force on energy also gave formal recognition to hydrogen as a key element in the National Energy Policy Report. Government participation in these activities helps in the absorption of the high risks in the development and deployment of these enabling technologies. The Government recognizes the promise of hydrogen energy and can assist industry to promote commercialization of the technologies, the growth of industry and the development of a compatible infrastructure. The DOE provides support to American companies, but the level of support has been less than the federal support in Germany and Japan. In 1993, Japan started a major 28 year, $11 billion hydrogen research program called New Sunshine. It surpassed Germany’s hydrogen program to become the biggest program at that time. The basic hydrogen research included work on the metal-hydride storage systems that are used in Toyota’s fuel cells. German government support has declined since reunification. About $12 million was budgeted in 1995. A growing number of states are also taking initiatives in implementing hydrogen energy projects. The California Fuel Cell Partnership has been placing fuel cell passenger cars and fuel cell buses on the road. In addition to testing fuel cell vehicles, the Partnership will also identify fuel infrastructure issues and prepare the California market for this new technology. Texas is taking action with stationary and portable applications through the Texas Fuel Cell Alliance. Florida has a hydrogen

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business council to increase awareness and initiate hydrogen projects, building on NASA’s longstanding commitment to hydrogen. Hydrogen has been a proven, effective carrier of energy that has been used regularly by NASA and the petrochemical community. Today our cars are fueled with hydrogen enriched gasoline and the automobile industry is developing fuel cell powered cars operating on hydrogen while the capacity to produce and distribute hydrogen in the United States is growing. RESEARCH TRENDS The U.S. has over a half century of innovation in hydrogen energy technology. More than fifty years of direct investment by NASA and the Department of Defense has created a national ability in using hydrogen energy. The Department of Energy’s National Laboratory system has also supported the implementation of hydrogen energy. These National Laboratories are significant in addressing complex and risky technical questions. Few industries can afford to conduct the type of R&D that is conducted at these labs. Solar hydrogen production from photocatalytic water splitting is one of these areas. One hydrogen research project, which was part of the Strategic National R&D Program, investigated thermochemical, photocatalytic and photobiological water splitting for generating hydrogen with sunlight as the main energy source. Solar hydrogen production with photocatalytic water splitting involves the cleavage of water to form hydrogen and oxygen and would be an ideal source of hydrogen for energy needs. The feedstock is water and the resulting fuel, hydrogen, burns with little or non-polluting products. The main reaction product is water vapor. The water splitting reaction is endothermic and the energy required for a significant hydrogen production rate is high. The photocatalytic process uses semiconducting catalysts or electrodes in a photoreactor to convert the optical energy into chemical energy. A semiconductor surface absorbs the solar energy and to act as an electrode for splitting water. The technology is still at an early stage of development and the most stable photoelectrode is TiO2 which has a conversion efficiency of less than 1%. Other materials, which require no external electricity need to be found. Hydrogen production can also use a water-splitting thermochem-

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ical cycle with metal oxides. The simplest thermochemical process for splitting water involves heating at a high temperature and separating the hydrogen from the equilibrium mixture. The decomposition of water requires a temperature of about 4700 degrees K. Problems with materials and separations at these high temperatures makes direct decomposition not feasible at this time. A two-step water-splitting cycle used on metal oxides redox pairs bypasses the separation hurdle. Multi-step thermochemical cycles can use more moderate operating temperatures, but their overall efficiency is subject to an irreversibility connected to heat transfer and product separation. A lower-valence metal oxide can split water with a partial reduction of the metal oxide without the use of a reducing agent. Hydrogen and oxygen are derived in different steps, without a high temperature gas separation. Potential redox pairs include: Fe3O4/FeO, ZnO/Zn, TiO2/TiOx (with X < 2), Mn3O4/MnO and Co3O4/CoO. Renewable Hydrogen Hydrogen can also be produced from renewable resources, such as the direct and indirect sources of solar energy, which includes agricultural wastes, sewage, paper and other biomass materials that have been going into landfills. Generating hydrogen from waste materials may be one of the least expensive methods of producing hydrogen. In the U.S., almost 14 quads of the annual 64 quad total energy requirement could be met from renewable biomass sources, which is over 20% of total energy needs. Sewage in quantities of billions of gallons per day is available to produce hydrogen by utilizing the non-photosynthetic bacteria found in the digestive tracts and wastes of humans and other animals, or by pyrolysis-gasification methods. Advanced sewage treatment systems could convert the billions of gallons of raw sewage that is being dumped into rivers and oceans into relatively low-cost hydrogen. High-temperature nuclear-fusion reactors may also be practical as renewable sources of energy for hydrogen production in the future. Over 100 million°F temperatures are required for nuclear fusion. The technology is in development and may be commercially viable if there are breakthroughs in the near future.

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PRACTICAL ASPECTS The options for producing hydrogen include electrolysis and reforming methane at small local filling stations or at large centralized plants. Decomposing water into hydrogen and oxygen using electricity is a mature technology widely used around the world to generate very pure hydrogen. But, it is an energy intensive process and the faster you make the process, the more power that is needed per kilogram produced. Commercial electrolysis units need almost 50-kWh per kilogram, which represents an energy efficiency of 70%. This means that more than 1.4 units of energy must be provided to generate 1 energy unit in the hydrogen. Since most of the electricity comes from fossil fuel plants, and the average fossil fuel plant is about 30% efficient, then the overall system efficiency is close to 20% (70% times 30%). Almost five units of energy are needed for every unit of hydrogen energy produced. Larger electrolysis plants cost less to build per unit output and they would provide a lower price for electricity generation than smaller ones at local filling stations. These smaller plants are sometimes called forecourt plants since they are based where the hydrogen is needed. Hydrogen may be generated at off-peak rates, but that is easier to do at a centralized product facility than at a local filling station, which must be responsive to customers who typically do most of their fueling during the day and early evening, the peak power demand times. To circumvent peak power rates, the National Renewable Energy Laboratory (NREL) suggests that forecourt plants use large oversized units operated at low utilization rates with large amounts of storage. Estimates for the cost of producing and delivering hydrogen from a central electrolysis plant range from $7 to $9/kg while the cost of production at a forecourt plant could be as high as $12/kg. High cost is probably the major reason why only a small percentage of the world’s current hydrogen production comes from electrolysis. To replace all the gasoline sold in the United States today with hydrogen from electrolysis would require a doubling of the electrical power that is sold in the United States at the present time which is about 4 trillion kW. Hydrogen can be a complement to other renewable energy technologies such as wind or solar because of its unique ability to store energy and release it efficiently, and should be embraced by all clean energy advocates.

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Foreign governments have invested heavily in hydrogen energy. Japan’s WE-NET program and the Canadian/German direct sponsorship of Ballard, the pioneer in fuel cell development, are major examples. Iceland is implementing hydrogen energy with government help in concert with Norsk Hydro Electrolysers, DaimlerChrysler, and British Dutch Shell. In the U.S. the champions for hydrogen on Capitol Hill see the promise of hydrogen as it evolves into an American energy commodity changing the economics of energy around the world. This support has been bipartisan. The U.S. Congress has a responsibility to assure there will not be improper regulatory barriers or trade restrictions that prevent this industry from competing. The increased use of renewable hydrogen energy can reduce the vulnerability to physical attack, economic attack by OPEC sanctions or embargo, terrorist attacks (since hydrogen dissipates faster than gas or jet fuel), and many cumulative environmental problems. Hydrogen energy is an important long-range solution to our dependence on oil. A sudden rise in gasoline prices occurs when even one refinery shuts down since we have not built a new refinery in over 30 years and we are becoming more dependent than ever on foreign oil. The price of oil itself is not clearly accounted for until the subsidies for exploration and the actual cost of Middle East defense is added. Only recently have the true costs of fossil fuel energy been studied, from defense commitments to long-term health care for nationwide respiratory illnesses. Steam reforming may remain the most cost-effective means for producing hydrogen in volume. Hydrocarbon feed gas is mixed with steam and passed through catalyst-filled tubes producing hydrogen and carbon oxides. Hydrocarbon feedstocks for steam reformers include natural gas, refinery gas, propane, LPG and butane. Naphtha feedstocks with boiling points up to about 430 degrees F can also be used. The ideal fuels for steam reformers are light hydrocarbons such as natural gas and refinery gas, although distillate fuels are also used. Residual fuels are not used since they contain metals that can damage reformer tubes. From the perspective of green house gases, both electrolysis and central-station power generation are relatively inefficient processes since most U.S. electricity is generated by the burning of fossil fuels. Nuclear and renewables make up only about 1/3 of total generation. Producing hydrogen from electrolysis could produce more greenhouse

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gases if fossil fuels are used. This could make it difficult to pursue the generation of significant quantities of hydrogen from the present U.S. electric grid. Hydrogen could be generated from renewable electricity, but the renewable system most suitable for local generation, solar photovoltaics, is expensive because of the cost of photovoltaic panels. The least expensive form of renewable energy, wind power, is a small fraction of all U.S. generation, although that figure is rising. Generating hydrogen from electrolysis powered by renewables is viewed by some as a good use of that power for economic and environmental reasons. But, the United States would need abundant low-cost renewable generation before it could divert a substantial fraction to the production of hydrogen. If forecourt hydrogen generation from solar photovoltaics becomes practical in the first half of the century, it could supply enough hydrogen to fuel the growing amount of fuel cell cars and generating systems while hydrogen generated from the vast wind resources of the Midwest would need large infrastructure costs for delivering it to other parts of the country. A large steam reformer plant could supply 1 million cars with hydrogen. By 2005 at the International Conference and Trade Fair on Hydrogen and Fuel Cell Technologies, there were more than 600 fuel cell vehicles. In Europe the potential market for hydrogen and fuel cell systems is projected to reach several trillion Euros by 2020. A hydrogen infrastructure for fueling could cost hundreds of billions, since there is such a limited hydrogen-generating and distribution system now. Decentralizing production, by having reformers in commercial buildings and even in home garages in combination with local power generation would reduce some of the cost. Larger reformers in neighborhood facilities could be the service stations of tomorrow. Methanol would allow a transitional phase where some fuel cells use methanol, which is relatively simple to reform and would not present too big a change from our current system. However, methanol is toxic and very corrosive. Hydrogen is considered a good replacement for diesel in locomotives. Recent testing indicates that it could be economical for railroads. Dow Chemical and General Motors are installing 400 fuel cells at Dow plants. Hydrogen is a natural byproduct at Dow and will provide 35 megawatts at its facilities. Iceland plans to build up a small fleet of fuel cell buses in the capi-

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tal, Reykjavik, and then slowly convert every vehicle on the island including fishing boats to create the world’s first hydrogen economy. Some London taxis have an alkaline fuel cell which charges a battery array used to power an electric motor. The fuel cell runs on hydrogen gas stored under the cab’s floor. DaimlerChrysler is delivering fuel cell vehicles to customers in California. A truly zero-emissions hydrogen generating system using solar or natural sources is popular where the fuel is produced from an aggregate of photovoltaic collectors, wind generators, and biomass. For transportation, fuel cells have important advantages. Three main automotive goals are efficiency, range, and emissions. Gasoline and diesel fuels have the efficiency and range, but there are emissions problems. Batteries meet the emissions and the efficiency goals, but not the range. The fuel cell promises to have extremely low emissions, with excellent range and efficiency, providing the storage problems are solved. Burning hydrogen is less desirable than using it in a fuel cell. The direct combustion of hydrogen releases carbon monoxide, hydrocarbons and some particulates, although these are only about 0.1 of that from the burning of fossil fuels. Over the years of development, fuel cells have shrunk to one- tenth their original size. Energy output has risen by a factor of five in this time period. One factor in the shift to fuel cells is concern over climate changes. Global warming is a factor of concern with the world population continuing to grow rapidly and developing economies starting to demand private cars. This creates more fuel demands and more urgency on environmental fronts and alternative fuels. Natural gas can be used far more efficiently to generate electricity or to cogenerate electricity and steam than it can be to generate hydrogen for use in cars. Using natural gas to generate significant quantities of hydrogen for transportation would, for the foreseeable future, damage efforts to battle CO2 emissions. NATURAL GAS AND ELECTROLYSIS Natural gas is the least expensive source of hydrogen today, but, there may not be enough natural gas to meet the demand for natural gas power plants and to supply a hydrogen fueled economy. The prices of natural gas, hydrogen and electricity could see dramatic increases as

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the demand for natural gas to make hydrogen increases. The delivered cost of hydrogen from natural gas would need to become competitive with the delivered cost of gasoline. Infrastructure costs would need to be managed over time with total estimates reaching a trillion dollars or more. In the U.S. natural gas is a non-renewable resource, and hydrogen production from reforming natural gas would result in substantial carbon dioxide emissions. Great supplies of natural gas are found in sensitive locations and unstable parts of the world, along with petroleum. To power 40% of the U.S. auto fleet with hydrogen from natural gas in 2025, using high efficiency fuel cells, would require a 1/3 more natural gas using projected 2025 levels. Natural gas is already in heavy demand as a clean fossil fuel for power plants, so alternative sources of hydrogen production are needed. Unless global warming emissions are stored underground, natural gas use will continue to contribute to global warming. But, natural gas could act as a transition fuel. Electrolysis using renewable electricity, wind, water or photovoltaics, could produce a domestic, non-polluting hydrogen transportation fuel. But, hydrogen produced today by this method can be more than 3 times the cost of an equivalent gallon of gasoline. If the electricity is supplied from the present electrical grid, which is more than 50% coalfueled, it would generate even larger amounts of carbon emissions than the natural gas process. Dedicated sustainable energy crops could also serve as a part of a hydrogen economy since they can be a carbon-free source of hydrogen through biomass gasification, or be converted to cellulosic-based ethanol and then to hydrogen. This option is attractive since ethanol is a room temperature liquid fuel and substantially easier to transport. Energy crops could also diversify agricultural markets, help stabilize the agricultural economy, aid rural economic development and reduce the adverse impacts of agricultural subsidies on developing countries. More research and development of the production processes of biomass to hydrogen and ethanol-to-hydrogen is needed to make this source of energy a cost-effective and viable option. Eventually, hydrogen could also be produced directly from renewable sources through photoelectrochemical or photobiological processes, but these are still at an early stage of research and development. Coal has the advantage of being a domestic resource, but it has major emissions of carbon dioxide and pollutants. These problems can be

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addressed using coal gasification with carbon capture and storage. Then hydrogen from coal could become viable. The Department of Energy has been working on projects to gasify coal producing both hydrogen and electricity while storing the waste carbon dioxide in geologic formations. Clean options include nuclear power to produce hydrogen with no emissions. But expanding nuclear power means overcoming safety, waste disposal and security concerns. Hydrogen Safety When hydrogen is used in fuel cells, a simple chemical reaction takes place involving the transfer of electrons to produce an electric current. A hydrogen bomb requires a high temperature nuclear fusion reaction similar to that which occurs in our sun and other stars. In 1937 the German airship the Hindenburg contained hydrogen when it burst into fire in a well publicized incident. While 35 people lost their lives another 62 survived, the Hindenburg did not explode, it caught fire when venting some of its hydrogen, to get closer to the ground, during an electrical thunderstorm. The airship was also moored to the ground by a steel cable, which acts as an antenna for electrical discharges. There were 161 rigid airships that flew between 1897 and 1940. Almost all of these used hydrogen and 20 were destroyed by fires, but 17 of these were lost in military action. Hydrogen explosions can be powerful when they occur, but they are rare. Hydrogen must be in a confined space for an explosion to occur. In the open it is difficult to cause a hydrogen explosion without using heavy blasting caps. In 1974, NASA examined 96 accidents or incidents involving hydrogen. At this time, NASA tanker trailers had moved more than 16 million gallons of liquid hydrogen for the Apollo-Saturn program. There were five highway accidents that involved extensive damage to the liquid hydrogen transport vehicles. If gasoline or aviation fuel had been used, a spectacular fire would have resulted, but none of these accidents caused a hydrogen explosion or fire. A well publicized event where explosive mixtures of hydrogen and oxygen were present in a confined space occurred in 1979 at the Three Mile Island (TMI) nuclear facility in Pennsylvania. During the process of nuclear fission, the center of the uranium fuel pellets in the fuel rods can

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reach 5,000°F. The cooling water keeps the surface temperature of the pellets down to about 600°F. If the circulating water is not present, in 30 seconds the temperatures in the reactor vessel can be over 5,000°F. This temperature is high enough to melt steel and thermochemically split any water present into an explosive mixture of hydrogen and oxygen. This is what happened at TMI. If a spark had ignited the hydrogen gas bubble that drifted to the top of the containment building, the resulting explosion could have fractured the walls. This would have resulted in the release of large amounts of radiation at ground level. The hydrogen gas bubble was vented, since as long as it remained in the confined space of the containment building, the potential for detonation existed. A hydrogen gas bubble developing from a nuclear reactor accident is a highly unusual event and is an example of the particular environment that is required for hydrogen to explode. At Wright-Patterson Air Force Base, armor-piercing incendiary and fragment simulator bullets have been fired into aluminum storage tanks containing both kerosene and liquid hydrogen. The test results indicated that the liquid hydrogen was safer than conventional aviation kerosene. Other tests have involved simulated lightning strikes, with a 6-million volt generator that fired electrical arcs into the liquid hydrogen containers. None of these tests caused the liquid hydrogen to explode. Fires did occur from the simulated lightning strikes, but the fires were less severe even though the total heat content of the hydrogen was twice that of kerosene. These tests indicated that liquid hydrogen would be safer than fossil fuels in combat where a fuel tank could be penetrated. Hydrogen does have a wider range of flammability when compared to gasoline. A mixture as low as 4% hydrogen in air, or as high as 74% will burn, while the fuel to air ratios for gasoline range from 1 to 7.6%. It also takes very little energy to ignite a hydrogen flame, about 20 micro-joules, compared to gasoline which requires 240 micro-joules. However, these characteristics are reduced by the fact that as the lightest of all elements, hydrogen has a very small specific gravity. The diffusion rate of a gas is inversely proportional to the square root of its specific gravity so the period of time in which hydrogen and oxygen are in a combustible mixture is much shorter than other hydrocarbon fuels. The lighter the element is, the more rapidly it disperses when it is released in the atmosphere. In a crash or accident where hydrogen is released, it rapidly dis-

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perses up and away from the ground and any combustible material within the area. Gasoline and other hydrocarbon fuels are heavier since the hydrogen is bonded to carbon which is a much heavier element. When hydrocarbon fuels vaporize, their gases tend to sink rather than rise into the atmosphere. This allows burning gasoline to cover objects and burn them. In most accidents, hydrogen would be a more desirable fuel. The 1977 accident of two fully-loaded Boeing 747 commercial aircraft on a foggy runway in the Canary Islands took 583 lives. An inquiry concluded most of the deaths in the Canary Islands accident resulted from the aviation fuel fire that lasted for more than 10 hours. A hydrogen fire would have been confined to a relatively small area as the liquid hydrogen vaporized and dispersed into the air, burning upward, instead of spreading like the aviation fuel. The heat radiated from the hydrogen fire would be far less than a hydrocarbon fire and only objects close to the flames would be affected. Hydrogen fires produce no smoke or toxic fumes, which is often the cause of death in fires. In a liquid hydrogen fuel storage tank the gaseous hydrogen vaporizes and fills the empty volume inside the tanks. This hydrogen is not combustible since there is no oxygen present. In gasoline or other hydrocarbon fuel tanks, air fills the empty volume of the tanks and combines with vapors from the fuel to produce a combustible mixture. In the September 11, 2001 disaster where over 3,000 were lost, if hydrogen was used as the fuel the damage would have been limited to the immediate crash sites, the buildings would probably be still standing and many lives would have been spared. The hydrogen studies by Lockheed found that along with the fuel’s safety characteristics, liquid hydrogen fueled aircraft would be lighter, quieter, with smaller wing areas and could use shorter runways. Pollution would be much less and the range of an aircraft could be almost doubled, even though the takeoff weight remains about the same. Since liquid hydrogen has the greatest energy content per unit weight of any fuel, NASA used liquid hydrogen as the primary fuel for the Saturn 5 moon rockets and the Space Shuttle. NASA has used large quantities of gaseous and liquid hydrogen for many years, which required developing the necessary pipelines, storage tanks, barges and transport vehicles. As a result of this experience, NASA has concluded that hydrogen can be as safe or in some ways safer, than gasoline or conventional aviation fuels. NASA original-

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ly wanted to develop a reusable manned liquid hydrogen-fueled launch vehicle for the space shuttle program, but Congress would not vote for the additional funds that would be needed. Less expensive solid rocket boosters were used, which turned into a tragedy when one of the seals of the solid rocket boosters failed during a cold weather launch. This caused the explosion of the Challenger shuttle in 1986 and the loss of its entire crew, including the first teacher on a spaceflight. BIOHYDROGEN Biomass could be a source of hydrogen using any material that is part of the agricultural growing cycle. This includes agricultural food, wood and waste products as well as trees and grasses grown as energy crops. Biomass can be gasified and converted into hydrogen and electric power. The process is similar to coal gasification, but biomass gasification processes are still in the demonstration phase. Biomass can be gasified together with coal as Royal Dutch/Shell has commercially demonstrated with a 25/75 biomass/coal gasifier. The CO2 can be extracted from biomass gasification since it is similar to coal gasification. The cost of delivered hydrogen from biomass gasification is estimated to range from $5 to $6/kg, depending on the type of delivery used. Studies by NREL suggest a lower cost, especially for pyrolysis, if the technology is improved. Waste biomass, such as peanut shells or bagasse which is the residue from sugar cane is the most cost-effective source, but the supply is limited. Pyrolysis uses of heat to decompose biomass into its components. Bio-refineries could convert biomass into many useful products. As the biomass is dried and heated, the coproducts are removed and hydrogen is produced using steam reforming. A good fraction of arable land in the United States (and the world) would be needed for biomass-to-hydrogen production sufficient to displace a significant fraction of gasoline which may not be a practical or politically feasible approach. Anaerobic digestion, like pyrolysis, occurs in the absence of air. But, the decomposition is caused by bacterial action rather than high temperatures. This process takes place in most biological materials, but it is accelerated by warm, wet and airless conditions. It occurs naturally in decaying vegetation in ponds, producing the type of marsh gas that

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can catch fire. Anaerobic digestion also occurs in the biogas that is generated in sewage or manure as well as the landfill gas produced by refuse. This gas consists mainly of methane and carbon dioxide. Bacteria breaks down the organic material into sugars and then into acids which are decomposed to produce the gas, leaving an inert residue. The world’s largest anaerobic membrane bioreactor (MBR) system supplies 200,000 to 300,000 cubic feet of biogas a day from the waste water at Ken’s Foods of Marlborough, MA, a large food manufacturer of salad dressings and marinades. A number of smaller MBR projects have been built in Japan. The manure or sewage feedstock for biogas is fed into a digester in the form of a slurry with up to 95% water. Digesters range in size from small units of about 200 gallons to 2000 gallons for a typical farm plant and to as much as 2000 cubic meters for large commercial installations. The input may be continuous or batch. Digestion may run for 10 to 14 days. The bacterial action generates heat but in cold climates additional heat is usually needed to maintain a process temperature of about 35°C. A digester can produce 400 cubic meters of biogas with a methane content of 50% to 75% for each dry ton of input. This is about two thirds of the fuel energy of the original fuelstock. The effluent which remains when digestion is complete also has value as fertilizer. A large part of municipal solid wastes (MSW), is biological material that under anaerobic digestion in landfill sites produces methane. This was first viewed as a possible hazard and was sometimes burnt off. In the 1970s some use began to be made of this product. The waste matter is a conglomerate in landfills and conditions not as warm or wet as a digester, so the process is much slower, taking years instead of weeks. The landfill gas (LFG) consists mainly of CH4 and CO2. A landfill site may produce up to 300 cubic meters of gas per ton of wastes with about 55% by volume of methane. In a developed site, the area is covered with a layer of clay or similar material after it is filled, producing an environment to encourage anaerobic digestion. The gas is collected by pipes buried at depths up to 20 meters in the refuse. In a large landfill there can be several miles of pipes with as much as 1000 cubic meters an hour of gas being pumped out. The gas from landfill sites can be used for power generation. Some plants use large internal combustion engines, standard marine engines, driving 500-kW generators but gas turbines could provide improved efficiencies. A gas-turbine

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power station is similar to a steam plant except that instead of using heat from the burning fuel to produce steam to drive the turbine, it is driven directly by the hot combustion gases. Increasing the temperature in this way improves the thermodynamic efficiency, but in order not to corrode or foul the turbine blades the gases must be very clean which is why most gas-turbine plants use natural gas. Biomass energy can provide economic, political, social and environmental advantages. The energy potential of biomass has been estimated at almost 42 quadrillion Btus which is about 1/2 of the total energy consumption in the United States. Biomass now provides the U.S. with about the same amount of energy as nuclear plants. Converting waste products to energy lowers disposal costs and provides cost savings in energy supplies. Biomass facilities often require less construction time, capital, and financing than many conventional plants. Biomass energy offers an increased supply with a positive environmental impact. If grown on a sustainable basis, it causes no net increase in carbon dioxide and the use of alcohol fuels reduces carbon monoxide emissions. Biomass is renewable as long as it is grown on a sustainable basis, but land use issues and concerns about pollution are major concerns. Areas with fragile ecosystems and rare species would need to be preserved. Agricultural lands would also compete with food production. The loss of soil fertility from overuse is a concern. Biomass production would need to be varied and sustainable while preserving local ecosystems. Pollution problems could result from the expanded use of fertilizers and bioengineered organisms on energy farms. The introduction of hazardous chemicals from MSW into the agricultural system could result in increased air and water pollution. References

Carless, Jennifer, Renewable Energy, Walker and Company: New York, 1993. Cothran, Helen, Book Editor, Global Resources: Opposing Viewpoints, Greenhaven Press: San Diego, CA, 2003. Hordeski, Michael F., Alternative Fuels—The Future of Hydrogen, The Fairmont Press: Liburn, GA, 2007. Kemp, William H., The Renewable Energy Handbook, Aztext Press: Ontario, Canada, 2005. Romm, Joseph J., The Hype About Hydrogen, Island Press: Washington, Covelo, London, 2004.

Chapter 5

Conser vation and Automation Trends Keywords: Utility Programs Efficiency Trends Lighting Trends Energy Saving in Buildings Insulation Trends Natural Ecosystem Model Plant Upgrade Trends

Integrated Heating and Cooling Trends Power Management Trends Heating System Trends Community HVAC Trends Solar District Heating Trends Hybrid Cooling Trends Exhaust Air Trends

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nergy conservation can help reduce the impact of several current problems. Increasing energy efficiency could reduce or delay atmosphere pollution on many fronts while improving national security through increased energy independence. The environmental effects of carbon dioxide and acid rain could be reduced along with the risk of possible climatic changes. Energy efficiency also makes renewable energy that much more effective. The shift in the U.S. economy from energy-intensive activities such as steel manufacturing to information-intensive activities such as computer and software design will continue to improve our gross national product while reducing our dependence on oil and coal. The United States uses twice as much energy in manufacturing than Japan, Germany, or Italy and the cost of this energy keeps the cost of products in the U.S. higher. UTILITY PROGRAMS Most utility programs for energy conservation have involved demand-side management (DSM). These programs try to impact how 159

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customers will use electricity. One technique is to even out the demand for electricity so that existing power generating stations are operating at efficient capacities throughout any 24 hour day rather than peaking up during business hours and late afternoon and then dropping down later in the evening. The other part of DSM is to constrain the need for new electricity capacities. DSM may involve peak clipping, strategic conservation, valley filling, load shifting, strategic load growth and flexible load shaping. It may include interruptible services or curtailment of services for specified time periods for commercial customers. Peak clipping refers to reducing the customer demand during peak electricity use periods. This is done by using some form of energy management system. Valley filling increases the electricity demand during off-peak periods, which allows the utility to use its power generating equipment more effectively. Load shifting is like valley filling, since it uses power during off-peak periods. Both valley filling and load shifting programs can involve power or thermal storage systems. Load growth planning is a DSM program that encourages demand during certain seasons or times of the day. Flexible load shaping modifies the load according to operating needs and can result in interruptible or curtailment rates for customers. These DSM energy and load-shaping activities are implemented as utility-administered programs. In the late 1980s, utilities began offering commercial rebate programs for DSM. Some utilities paid 30 to 50% of the installed cost, while others based their rebate programs on the peak-kilowatt-demand savings achieved by new equipment. DSM programs are designed to encourage consumers to modify their level and pattern of electricity usage. Energy conservation is often rewarded by the utility rebate programs. It includes energy audits, weatherization, high-efficiency motors, Energy Management, DDC systems and HVAC systems and equipment. Consolidated Edison has a program for organizations that can reduce their summer electricity bills without buying new equipment. During the summer months, these customers agree to reduce electric demand by at least 200 kilowatts on demand. More than 100 organizations were involved in this program. Duquesne Light Company in Pittsburgh and Georgia Power have interruptible economic development rates that operate in a similar way. Con Edison also offered programs with energy audits and rebates for steam air conditioning,

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gas air conditioning, high-efficiency electric air conditioning, cool storage and high-efficiency motors. The Georgia Power Good Cents building program offered commercial customers HVAC rebates, along with energy audits. The Houston Lighting & Power (HL&P) program encouraged the use of cool storage technology and provided building owners with a $300 cash incentive for each kilowatt reduction in peak demand. There was also a cool storage billing rate, which defined the on-peak demand as noon to 7 p.m. Monday to Friday throughout the year. Many buildings have increased in value and marketability as a result of these cool storage programs. Besides rebates there are low- or no-interest equipment loans, financing, leasing and installation assistance and assured payback programs. Wisconsin Electric Power Company offered rebates of up to 50% of the project cost and loans with multiple rates and terms for 3 to 7 years. These programs are available for HVAC systems, window glazing, high-efficiency motors or building automation systems. Pacific Gas and Electric (PG & E) has its SmartAC program where a device installed on a central air conditioner can receive a signal during summer peak periods that will allow the unit to use less power. Over 100,000 customers have used this program in 2008 with a 95% satisfaction ratio. Utilities are also supporting the adoption and implementation of stricter building codes and equipment efficiency standards The increasing acceptance of energy management systems for building management applications has been pushed by federal mandates. Appliance and equipment efficiency standards have had a notable impact on electricity demand in the United States. Standards have lowered national electricity use by 3%. A few energy efficiency measures, such as power-managed personal computers, have been widely adopted without financial incentives or much utility involvement. EFFICIENCY TRENDS Many studies infer improvements in the gas mileage of cars and efficiency in the production of energy in power plants, in industrial applications and in home heating, lighting and other sectors. U.S. manufacturers could improve the average energy efficiency of cars and trucks. But, as America’s fleet of older vehicles is replaced with

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newer cars with less pollution, CO2 emissions may change very little or even increase since additional miles may be driven. One highefficiency case assumes new cars could average 52 miles per gallon and could penetrate 50% of the U.S. market. This would be possible if small hybrids take over a major part of the market. Other studies predict that new car efficiencies could be even greater than that, with a fuel economy for the average vehicle of 75 miles per gallon. One NEPP report assumes that the U.S. economy could reduce its dependence on energy at the rate of about 1.7% per year, while others hold that more active efforts to make our economy less dependent on energy could result in a rate of about 4% per year. They also predicate very highefficiency lighting and the rapid deployment of electric-power-generating stations that are 50% or more efficient than present facilities. Improvements in efficiency along with major efforts to redirect energy use towards improved environmental quality would not only reduce emissions but there would be many other benefits. In 1960 many homes had 60 amp services that were adequate. Today’s kitchens with the best energy star appliances and multiple ceiling lamps would tax this system and there are the loads from computers and other electronics. From 1975 to 1985 startling gains in energy efficiency in the U.S. lowered fossil fuel emissions while the gross national product increased. These gains in energy efficiency were driven by the OPEC oil price jumps. The 1975-1985 time period was one in which economic growth and energy growth remained relatively unlinked. Most historic periods show the reverse trend. The DOE viewed this period as a deviation. The U.S. Environmental Protection Agency (EPA) launched the Green Lights program in 1991. Green Lights was a voluntary, nonregulatory program aimed at reducing the air pollution that results from electric power generation. Participants committed to upgrade a total of 4 billion square feet of facility space, this is more than 3 times the total office space of New York, Los Angeles, and Chicago combined. Green Lights Partners are public and private organizations that agreed to upgrade their lighting systems wherever profitable. The test of profitability for upgrades was a return on investment of the prime rate plus 6%. Most Green Lights Partners cut their lighting bills in half, while improving their work environment. Green Light Partners agree to survey the lighting system in all of their facilities and upgrade the


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lighting system in 90% of qualifying building space. The upgrades must be completed in 5 years. Firms that have signed onto the EPA program, include the Fortune 500 as well as federal, state and local governments along with schools and universities. LIGHTING TRENDS The Illuminating Engineer Society (IES) is the largest group of lighting professionals in the United States. Since 1915, IES has specified light levels for various tasks. The light levels recommended by the IES usually increased until the 1970s. More recently, effort has been placed on occupant comfort which decreases when a space has too much light. Several experiments have shown that some of IES’s light levels were exorbitant and worker productivity was affected due to visual discomfort. As a result of these findings, IES revised many of their light levels downward. But, the tradition of excessive illumination continues in many office areas. In the past, lighting designers would identify the task that required the most light and design the lighting system to provide that level of illumination for the entire space. In a modern office, many tasks include reading information on computer screens. Too much light tends to reduce screen readability. In an office with computers, there should be less than 30 foot-candles for ambient lighting. Small task lights on desks can provide the additional foot-candles needed for a total illuminance of 50 to 75 footcandles for reading and writing. The oldest electric light technology are incandescent lamps which also have the lowest lumens per watt and the shortest life. Light is produced by passing a current through a tungsten filament, causing it to become hot and glow. As the tungsten emits light, it progressively evaporates, eventually causing the filament to weaken and break open. Incandescent lighting consists of common light bulbs, certain types of floodlights, (quartz or tungsten-halogen) and most high-intensity reading lights. Incandescent lighting is the least expensive bulb to purchase and produces a soft light. Incandescent lighting gives far less light per energy dollar than other types of lighting. Incandescent bulbs do not last as long as other types of lighting. A tungsten alloy is used as the filament and the glass bulb maintains

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a vacuum for the glowing filament. Without the vacuum, the tungsten filament would quickly burn up. Halogen lamps are a type of high-efficiency incandescent lamp. The lamp uses halogens to reduce evaporation of the tungsten filament. Halogen lamps provide a 40 to 60% increase in efficiency with a whiter, brighter light than standard incandescents. Special types of incandescent lamps for flood lighting include quartz and tungsten-halogen units that operate on the same principle as regular incandescent bulbs but are constructed of slightly different materials to give longer service and to provide more light. One product that is used with incandescent light bulbs is a small disk which is inserted into the socket before the light bulb is screwed into place. These devices are variable electrical resistors which limit the initial rush of current to the light bulb. By limiting the initial rush of current, the temperature of the bulb’s filament rises relatively slowly compared to the temperature rise without the resistor. This reduces the amount of shock which the filament must endure and extends the life of the bulb. With this shock reduced, the bulbs provide service for a longer time. The light bulb uses the same amount of electricity except for the initial inrush. Another device used for extending lamp (bulb) life is a diode, which cuts off half of the power to the bulb. The bulb will last longer but emit half the light. This device is useful in locations that are difficult to reach. No energy is saved for the amount of lumens emitted, but there will be fewer light bulbs to purchase. Another technique is to use bulbs which are rated at 130 volts, rather than the normal 120 volts. The 130 volt bulbs have a stronger filament, which will last longer and the price differential is not too large. Incandescent lamps are sold in large quantities because of several factors. Many fixtures are designed for incandescent bulbs and lamp manufacturers continue to market incandescent bulbs since they are easily produced. Consumers purchase incandescent bulbs because they have low initial costs, but if life-cycle costs are considered, incandescent lamps are usually more expensive than other lighting systems with higher efficacies. Sulfur light bulbs contain a small amount of sulfur and inert argon gas. A golf-ball sized bulb is rated at 1425 watts or 135,000 lumens with a color rendering index of 79. Since there are no filaments or other metal components, the bulb may never need replacement. The sulfur lamp may be used with reflectors for high bay fixtures or with a hol-


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low light guide commonly called a light pipe for illuminating large areas. The light emitted can be filtered, tinted, dimmed and reflected to meet precise lighting needs. Sulfur lamps are used in the U.S. and Europe for airport tarmacs, aquariums, automobile assembly plants, cold storage facilities, gas stations, gymnasiums/sports facilities, highway signs, museums, postal sorting facilities and subway stations. Sulfur lamps are in the Smithsonian National Air and Space Museum and on the outside of DOE’s Forrestall Building in Washington, D.C. Hill AFB became the world’s largest installation of sulfur lighting when it used them in aircraft hangars for F16 fighter and C130 cargo aircraft maintenance and overhaul. Light guides using 10-inch diameter tubes fabricated of multiple layers of plastic materials are installed, each is 105-feet-long with a Fusion lamp module coupled to each pipe end. Compared to the high-intensity discharge systems they replaced, the sulfur lamps produced lighting levels that were almost 50% higher in the low bay area and up to 160% higher in the high bay area. Comparable lighting levels with metal halide lamps would consume almost 20% more energy in the low bay area and about 40% more energy in the high bay area. Indirect lighting is a growing segment of lighting where fixtures are suspended from the ceiling to distribute the light mainly upward. Indirect lighting is often combined with direct lighting or task lighting. Indirect lighting minimizes the glare on computer screens and creates a softer environment for more concentrated work. This tends to provide increases in productivity and occupant satisfaction. Indirect lighting has the potential to reduce energy use. Indirect lighting can lead to ceilings with too much light and a relatively gloomy area underneath. This led to the introduction of indirect/direct fixtures. Combining direct lighting with an indirect fixture provides lighting with the low-glare benefits of indirect lighting. Workers at a desk or computer benefit most from the low glare of the indirect portion and those in the area appreciate the depth and contrast that the direct component adds. Indirect and indirect/direct fixtures normally use T8 or T5 lamps with electronic ballasts. T5 lamps are thinner and more efficient. They provide a higher intensity of light output than the T8 bulbs. The high intensity of T5 lamps allows rows of indirect fixtures to be placed from 12-15 feet apart on ceilings as low as 8 feet 6 inches with uniform ceil-

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ing illumination levels. With T8 lamps, the standard spacing is 10 to 12 feet, and ceilings have to be at least 9 feet 6 inches high. This is higher than many conventional office ceilings. The wider spacing allows fewer fixtures to be used in a given space and the overall cost is reduced. T5 lamps are available in two types: standard output and high output (HO). The HO versions put out almost twice as much light as a T8 lamp with the same length. This allows the number of single-lamp T5 fixtures required in a given space to be cut almost in half compared with single-lamp T8 units. The indirect lighting systems that use T5 HO lamps are less expensive than a T8 indirect system, even though the T5 lamps themselves are more expensive than T8s. The cost advantage should grow as T5s become more popular. The lamp price should eventually drop below that for T8s, since their small size means that they require less material to manufacture. Single-lamp fixtures have an advantage over two-lamp fixtures since the light distribution is easier to control with one lamp than two. At the end of lamp life, a single T5 lamp is easier to replace and dispose of than a pair of T8s. The high intensity of the T5 lamp can produce glare problems in an indirect/direct fixture, but one means of reducing that glare is a waveguide, which provides a downward component to indirect lighting. The optical waveguide has an acrylic plastic panel with a semirefractive film on the bottom of the panel. A microscopic array of prisms on the film directs light in a uniform downward pattern, resulting in low levels of glare. ENERGY SAVING IN BUILDINGS The increasing acceptance of energy management systems for building management applications has been pushed by federal mandates. Energy saving systems integrate the operation and management of heating, ventilation, air conditioning, security, light and fire safety systems to reduce energy costs and minimize carbon dioxide emission of commercial buildings. The future vision is a building that almost runs itself, from adjusting HVAC loads to dimming the lights. Energy efficiency involves practical, computerized energy management systems that are largely self-managing, correcting changes within the building automatically and alerting building personnel when problems occur.


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Most workers prefer to adjust light levels down from typical office levels. Intelligent lighting control systems are available that allow workstation computers to control light fixtures. An on-screen control panel with click-and-drag dimming slider controls will lower workstation illuminance. This results in less complaints and better working conditions for maximum productivity. The use of local area networks (LANs) for lighting control allows centralized lighting control from network computers. The primary modes of central lighting control are load shedding and scheduling. Load shedding allows customers to take advantage of low rate structures. The technique is to turn off nonessential electric loads during high-cost electricity use periods, but lighting is rarely considered nonessential. By gradually dimming the lighting system, typically 20-30% over 15-20 minutes, the on-peak lighting power costs can be reduced by up to 30% without distracting workers. The human eye adapts to changes in brightness much faster than the load-shedding dimming rate and the change in brightness will not be evident. Reduced light levels should only be a temporary measure for minimizing the peak electricity demand. Full illumination levels should be restored at the same gradual rate after the peak demand period has passed. This type of load shedding takes advantage of time-of-use or real-time pricing rates. Light scheduling is used to ensure that manually controlled lighting systems are off at the end of the day. Occupancy sensors can be used to control the downlighting and a scheduling control used to turn off the uplighting at the end of the day and turn it back on for the next workday. There must be some way to temporarily override the schedule for special events. An occupant may need to work beyond the scheduled lights out time. The occupant should be able to override the lights out command in their area. Light scheduling controls can also be used for scheduled dimming. The light may need to be scheduled to stay on during cleaning times. This can be done at a reduced light level. Load shedding may also need to be scheduled at specific times. INSULATION TRENDS Insulation is one of the most important factors in achieving energy efficiency in a building. Its primary function is to slow the flow of heat through a building envelope, but it also acts to seal the building en-

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velope, preventing drafts and air leakage from unconditioned spaces. By maintaining indoor air quality insulation saves money by reducing heating and cooling loads and is a key factor in achieving comfortable living and working spaces. Insulation ratings are based on the resistance to heat flow. This is measured in R-value units in the United States and RSI in Canada (RSI = R x 0.1761). The inverse of thermal resistance is conductance, referred to as the U-value (U = 1/R or USI = 1/RSI). In the United States, U is measured in units of Btu/square foot-°Fahrenheithour. In Canada, U is measured in watts/square meter-Celsius. The higher the R-value, the better the insulating properties. The U-value is more useful for calculations, since it describes the actual amount of heat that can move through the material for each degree Fahrenheit difference in temperature from one side of the material to the other. Values of different components can be added (for the different layers of a wall, but U-values cannot be directly added. Most forms of insulation use pockets or bubbles of air or a gas to decrease the material’s conductivity, because a gas conducts heat more slowly than a solid. In fiberglass insulation, thin fibers create pockets and restrict the air circulation. In theory, an inch of air can achieve an insulation value of R-5.5. However, the best air-filled insulations only achieve R-4.5 to R-4.7 per inch. Two inches of insulation provide a value of R-9 to R-9.4. The primary types of insulation are fiber, foam, and reflective. Fiber insulation is available in either loose-fill form or in batts. Loose-fill insulation uses fiberglass, cellulose, rock wool, or other types of fibers that are blown into wall cavities or attic joist spaces. When properly installed, loose-fill insulation provides a more complete cavity coverage than batts as the fibers fill in around wires, piping, and corners. Loose-fill is usually installed by specialized contractors, while batts can be installed by anyone who wants to insulate an area. R-values for loose-fill insulation are 2.2/inch for fiberglass and about 3.2/inch for rock wool or cellulose. Batts are available with fiberglass, cotton, or rock wool that have an R-value of about 3.2/inch. Loose-fill insulation can settle over time. When loose-fill insulation is used in a wall, the settling produces a void above the settled insulation that acts to conduct heat through this area. In an attic, settling products a nonuniform layer of insulation, which reduces its effectiveness. Some types of insulation use an acrylic-based binder to reduce settling. Loose-fill cellulose can also be mixed with water and blown in wet, usually without any added binders. This viscous mixture tends


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to mold itself into pockets, which helps to eliminate air leakage and infiltration. It has an R-value of about 3.5/inch. Loose-fill cellulose may also be installed dry using a machine with a reduced application nozzle that packs the insulation creating a packed, high-density cellulose. This method does not seal as well as wet-spray cellulose. Since it is packed tightly, little settling occurs and, unlike wet-spray cellulose, it can be used on wall insulation retrofits. It also has an R-value of about 3.5. Foam insulation is available in either rigid sheets or spray. Rigid foam insulation has a higher R-value per inch than fiber insulation. It uses HCFCs instead of air to create pockets or bubbles in the foam sheet. R values range from 3.6 for expanded polystyrene to 7.7 for isocyanurate. Rigid foam insulation is easy to install with nails or glue. Its cost per unit R is much higher than that of fiber. Sprayed-in foam can be used in open or closed cavities as well as around ducts or pipes that pass through the building envelope. Low-density urethane spray foams can achieve up to R-11/inch, most foams are rated lower, with values around R-4 to R-6. Like wet cellulose, spray foams are effective at sealing out drafts. Some rigid foam insulation has been associated with insect problems. Carpenter ants and termites can tunnel through polystyrene and polyisocyanurate foams to create nesting cavities or protected passages to wood inside a building. To attack this problem, some manufacturers add boric acid to the foam. Reflective insulation differs from other types of insulation. Instead of reducing the conductive heat flow, it reduces radiant heat flow. It also does not use a gas to insulate. In its most basic form, it consists of a single sheet of a reflective material, which reflects heat emitted from a warm surface back to that surface. It must be positioned adjacent to an air gap to be effective, or the heat will be conducted through to the next solid layer that it touches. The R-values of reflective insulation can change depending on where the insulation is used. In areas like floor joist spaces above an unheated basement, convective heat losses are minimal, since the warm air will stay near the floor. Here, radiant transfer is the primary method of heat loss and a single reflective barrier can have an equivalent R-value of 8. In a ceiling joist application, the warm air will rise away from the conditioned space, instead of into it, and so convection will be the primary method of heat loss. In this application reflective insulation will have little effect in stopping the heat loss and fiber or foam insulation should be

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used instead. A single layer of reflective insulation next to an air space in a wall can have an equivalent R-value of about 3. For wall retrofits, spray foam insulation is used to seal around pipes or other items that break through the wall or to seal the connection to the attic, and usually not to fill the wall cavity. The available space for the insulation affects the choice of insulation. An R-14 barrier of isocyanurate rigid foam with its R-value of 7/inch requires only two inches of space in which to fit the insulation. This level of insulation using fiberglass would be much cheaper, but it would require about four and a half inches of space to accommodate it, which may not always be available. The R-value of the building envelope will depend on the local climate. It is also affected by diminishing R layer efficacy. Each additional unit of R-value contributes less energy savings than the previous one. Adding R-10 insulation to a wall that already has R-40 insulation will save very little additional energy. Most local communities mandate minimum R-value or RSI-value levels for new construction. Environmental and health factors are also a consideration. Fiberglass is a suspected carcinogen and is potentially more hazardous in loose-fill form, since airborne fibers are more easily produced by handling it than when handling batts. Phenol formaldehyde is used as a binder which is a pollutant in buildings since it will continue to offgas from the insulation into the surrounding spaces for several years. There is a potentially safer type of fiberglass that does not use a binder. These fibers are stronger and less likely to break and form airborne respirable fibers than the fiberglass containing formaldehyde. Cellulose insulation is made from recycled newspaper. There is some concern about the health risks of the ink residue, but the boric acid that is added as a fire retardant and vermicide is considered safe. Chlorofluorocarbon (CFC) blown rigid foams have been replaced with foams that use HCFCs because of the danger that CFCs may do to the ozone layer. Though HCFCs are not as damaging as CFCs, they still have some effect and may be replaced by hydrofluorocarbons or hydrocarbons. The best available insulation has a maximum R-value of about 11/inch. Some newer insulation technologies have an R-value above 20, but they are not being sold as building insulation. These include gas-filled panels, vacuum insulation panels, and aerogels. Gas-filled panels use pockets of sealed polymer film filled with low-conductiv-


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ity argon, krypton, or xenon gas. These panel have R-values per inch of 7.2, 12.4, and 20. Vacuum insulation panels use a vacuum between two gas sealed layers of metal to create R-values of 25 to 40 per inch. Aerogels are low-density solids that are made from silica and provide R-values of 15 to 35 per inch. These technologies are used in ovens and refrigerators, but are generally too expensive to compete with traditional building insulations. There is also a granulated transparent aerogel that may be used for skylights and windows with R-values of 8 to 20. THE NATURAL ECOSYSTEM MODEL In the 1990s, the Environmental Protection Agency began to focus on pollution prevention using natural ecosystems as a model for industrial systems. The idea was that these systems should not be open-ended, dumping endless byproducts, but closed, as nature is, continuously cycling and recyling. This concept grew to include Life Cycle Assessment (LCA) which considers: the source of raw materials, the dependency on nonrenewable resources, energy and water use, transportation costs, the release and use of carbon dioxide and the recovery of materials for recycling or reuse. LCA requires three stages: taking inventory, assessing impact, and assessing improvements. Taking inventory involves using a database to quantify energy and rawmaterial requirements (inputs) and environmental outputs, such as air emissions, water effluents and solid and hazardous waste for the life cycle of the product. Energy inputs should take into account transformation costs (raw materials into products), transportation costs and any reduction cost when using recycled materials. Recycling has made some strides since 1980 but much more could be done. Impact assessment requires knowing which materials, processes, or components may be toxic and their impact on the environment and health which varies according to the amounts involved. For example, disposable or rechargeable batteries require weighing performance (battery-charge life) against toxicity. LCA emerged to analyze the manufacturing of toxic chemicals, but now it even affects electronic and other manufacturing sectors. Standby or idle power for some electronic products exceeds the power consumed during operation.

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LCA encloses the entire life cycle of a product from raw-material extraction to end-of-life management alternatives including landfilling, incineration, and recycling. Customer use of a product is a major contributor to smog, nitrogen oxides, acid rain, and carbon-dioxide release all stemming from a product’s energy consumption. In one study of the energy consumption of a portable telephone, the energy spent in production was found to be greater than lifetime use. The energy expended in production included that required for not only material transformation but also the energy needed to keep workers comfortable such as heating and air conditioning. Many companies are incorporating life-cycle costs and life-cycle assessment into their operations. The U.S. Air Force uses computeraided software for defining the complex sets of interacting activities in the life cycle of an aircraft. Xerox reprocesses copiers which provide reusable components (51% by weight) and recycles 46% of parts by weight into reusable materials. This leaves only 3% of the parts for disposal. PLANT UPGRADE TRENDS Upgrading older inefficient electricity-generating plants could save large amounts of energy. Older plants can lose two-thirds of the heat energy as waste heat at the site. Upgrading these plants with more efficient boilers, controls and turbines could reduce the lost of heat energy to about half. Most electric power plants produce electricity from steam that is used to rotate a power-generating turbine. The heat contained in the steam after it condenses is lost to the environment. In many industrial processes steam or heat is produced during production, but the mechanical energy in the steam or heat is not utilized. Cogeneration combines the production of heat and the generation of electricity to provide a higher total efficiency than that of either process occurring separately. As the costs of fossil fuels and electricity continues to increase, cogeneration becomes more attractive. A gas turbine power plant requires hot, high-pressure gases produced by burning oil or natural gas. The hot exhaust gases can be used to create steam in a boiler system. The efficiency can approach 90% if the system is properly designed. A steam turbine power plant uses high-pressure steam produced


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in a boiler from burning fossil fuels or product waste to generate electricity. The low-pressure steam output can be for heating. The efficiency for this process can approach 85%. In a diesel engine generator, waste heat can be recovered from the water-filled cooling jacket around the engine or from the exhaust gases. This heat can be used to heat water or to produce steam. Diesels often have lower efficiencies than either gas or steam turbines, but with cogeneration the total conversion efficiencies reach 90%. They are also capable of generating more electricity than comparable gas or steam turbines and are more appropriate for small-scale applications. One potential problem with diesel cogeneration is air pollution, but the newer diesel engines are cleaner than those produced in the past. Cogeneration systems can also use renewable fuel sources such as wood, waste products, wood gas or methane from sewage and garbage. The Sun-Diamond plant in Stockton, California, used waste walnut shells into electricity for the plant and nearby homes. The walnut shells were used as fuel to produce steam to drive a turbine generator. The low-pressure steam output was then used for heat as well as to refrigerate the plant. The Sun-Diamond cogeneration system produced about 32 million kWh of electricity per year. It only used 12 million and sold the surplus power to Pacific Gas and Electric Company. In small-scale cogeneration units in the 5- to 20-kilowatt range, more heat is supplied than can be used, so these systems may also include heat storage components. If multiple, smaller units are used, at least one of the units can be operating continuously, providing electricity at all times. The Fiat Motor Company developed its Total Energy Module (TOTEM) using a four-cylinder automobile engine that burns natural gas and can be adapted to other fuels, including liquid petroleum gas (LPG) and alcohol. It has a heat recovery efficiency of about 70% and an electrical generating efficiency of about 25%. The heating efficiency is similar to a conventional heating system, but since the unit also generates electricity its total efficiency is over 90%. The 380 volt, 200 amp asynchronous generator unit can produce 15 kilowatts of electrical power and heat a 4- to 10-unit apartment building. Units that produce 50 to 100 kilowatts can heat multi-dwelling apartment buildings. They are fueled by natural gas or diesel fuel. Units of 200 to 2,000 kilowatts that operate on fuel oil or diesel fuel are suitable for large apartment buildings or small district heating sys-

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tems. The heat from a cogeneration unit can be used as a heat pump source, with electricity from the unit powering the heat pumps. If some of the electricity generated is used for space heating, the system can be downsized by about 1/3. If the electricity is used to power water source heat pumps, an even smaller system is required. Fluidized bed combustion is a newer technology that burns coal in an efficient manner and can produce both electricity and heat. A mixture of finely crushed coal and limestone rides on a stream of air, which allows the coal to be burned at temperatures lower than conventional coal burners. This reduces the nitrogen oxide produced. The limestone absorbs sulfur from the coal, which reduces the sulfur dioxide. Cogeneration systems may use different fuels including natural gas, residual fuel oil, heating oil, diesel fuel and gasoline. Alternate fuel sources also include coal liquids or wood gas. Cogeneration with fuel cells is growing as stationary fuel cells reduce their costs with continuing development. They provide medium-sized power generation sources for on-site generation, particularly for factories and commercial buildings. Many studies indicate a large potential. A 2000 study for the DOE’s Energy Information Administration found that the total power needs for combined heat and power (CHP) at commercial and institutional facilities was 75,000-MW. Almost two thirds of these required systems of less than 1-MW which are a good match for fuel cell generation. Ceres Power has an integrated, wall-mountable combined heat and power unit (CHP). The integrated CHP Unit is capable of generating electricity and all of the central heating and hot water requirements of a typical home, avoiding the need for a separate boiler. The CHP Unit uses the same natural gas, water and electricity connections as a boiler and is thus easy to install. A typical fuel cell system in the U.S. is the 200 kilowatt (kW) PAFC unit produced by UTC Fuel Cells. This type of unit provides electricity and heat to the U.S. Postal Service’s Anchorage Mail Handling Facility. The system consists of five natural gas powered 200-kW PC25 fuel cells developed by UTC Fuel Cells. The fuel cell station provides primary power for the facility as well as half of the hot water needed for heating. Excess electricity from the system flows back to the grid for use by other customers. In South Windsor, Connecticut, a natural gas powered 200-kW PC25 fuel cell system, from UTC Fuel Cells, is used at the high school to provide heat and electricity. Stationary fuel cells are installed at 30 facilities and locations in the Armed Services. The


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fuel cells are used for primary and back-up power as well as heat. On-site combined heat and power (CHP) includes turbines, reciprocating engines and steam turbines. Gas turbines in the 500-kW to 250-MW produce electricity and heat using a thermodynamic cycle known as the Brayton cycle. They produce about 40,000-MW of the total CHP in the United States. The electric efficiency for units of less than 10-MW, is above 30%, with overall efficiencies reaching 80% when the cogenerated heat is used. There are some very low NOx units. The high temperature exhaust can be used to make process steam and operate steam-driven chillers. A 1-MW unit can cost $1,800/kw installed while a 5-MW unit may cost $1,000/kw installed. In these systems, the turbine generator is about 1/3 of the total cost with the other costs including the heat recovery steam generator, electrical equipment, interconnection to the grid, labor, project management and financing. Reciprocating engines are another mature product used for CHP. These stationary engines may be spark ignition gasoline engines or compression ignition diesel engines. Capacities range from a few kilowatts to over 5-MW. Natural gas or alcohol fuels may also be used in the spark ignition engines. Electrical efficiency ranges from 30% for the smaller units to more than 40% for the larger ones. Reuse of the waste heat can provide overall efficiencies to 80%. The high-temperature exhaust of 700°F-1,000°F can be used for industrial processes or an absorption chiller. About 800-MW of stationary reciprocating engine generation is installed in the U.S. Development has been closely tied to automobiles and in the last few decades increases in electric efficiency and power density have been dramatic as well as emission reduction. Some units can even meet California air quality standards when running on natural gas. A 100-kW reciprocating engine generating system may cost $1,500/ kw installed, while an 800-kw unit can cost $1,000/kw. The engine is about one fourth of the total price with the rest going to the heat recovery system, electrical system, labor, materials, project management, construction and engineering. The steam turbine generator depends on a separate heat source for steam, often some type of boiler, which may run on a variety of fuels, such as coal, natural gas, petroleum, uranium, wood and waste products including wood chips or agricultural byproducts. Steam turbine generators range from 50-kW to hundreds of megawatts. By 2000, almost 20,000-MW of boiler and steam turbines were used to

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provide CHP in the United States. For distributed generation, a boiler and steam turbine system can be expensive. But, a process that already uses a boiler to provide high pressure steam can install a back pressure steam turbine generator for low cost, high efficiency power generation. The pressure drops in the steam distribution systems are used to generate power. This takes advantage of the energy that is already in the steam. A back-pressure turbine is able to convert natural gas or other fuels into electric power with an efficiency of more than 80%, which makes it one of the more efficient distributed generation systems. The CO2 emissions are low as well as pollution emissions. The installed capital cost for these systems is about $500/kW. High efficiency, low cost and low maintenance allow these back-pressure installations to have payback times of two or three years. Electric utilities have tended to view small power producers as competitors. The Public Utilities Regulatory Policy Act (PURPA) requires utilities to buy surplus power from and to supply back-up power to small power producers and cogenerators at nondiscriminatory fair rates. A report by the National Renewable Energy Laboratory, studied sixty-five distributed energy projects and found that various technical, business practice, and regulatory barriers can block distributed generation projects from being developed. These barriers include lengthy approval processes, project-specific equipment requirements and high standard fees. There is no national agreement on technical standards for grid interconnection, insurance requirements or reasonable charges for the interconnection of distributed generation. Vendors of distributed generation equipment need to work to remove or reduce these barriers. Distributed projects are not always given the proper credit for their contributions in meeting power demand, reducing transmission losses and improving environmental quality. The New York Power Authority (NYPA) and MTA New York City Transit (NYC Transit) are powering an expanded subway and bus maintenance facility with a clean energy 200-kW fuel cell. The stationary fuel cell produces electricity through a virtually emission-free chemical reaction since the electrical power is produced when oxygen and hydrogen are combined and the byproducts are essentially heat and hot water. The unit will displace some 2,800 barrels of oil per year. In 2005, the New York State Public Service Commission approved


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a Renewable Portfolio Standard providing for increased use of renewable energy sources, including fuel cells. This project in Queens helps to implement the vision that 25 percent of the state’s energy come from renewable sources by 2013. The facility is the first major maintenance facility with sustainable Green design. Integrated into the design are photovoltaic roof cells, natural light and ventilation, motion detector light switches and a storm water retention system to wash the subway car fleet. Fueled by natural gas, the 200-kW fuel cell will be a continuous source of power. The residual heat of almost 700,000 Btu per hour will be used for the shop’s domestic hot water system. In case of a power disruption, the fuel cell will automatically supply electricity to the building’s non-emergency lights. Combined with other sustainable green design elements, NYC Transit expects to use 36% less energy over the life of the new facility. NYC Transit’s use of clean energy power sources includes a 300kW roof-mounted solar power array at the Gun Hill bus depot in the Bronx. During warm weather, the solar array supplies 15 percent of this bus depots’ electrical needs. NYC Transit has been using solar energy to provide power to the Maspeth Warehouse Facility in Queens and the Jackie Gleason Bus Depot in Brooklyn since the late 1990s. NYC Transit also has a 100-kW solar canopy at the reconstructed Stillwell Avenue Terminal in Coney Island. NYC Transit became a full signatory of the International Association of Public Transportation’s (UITP) charter on Sustainable Development in Mobility in 2004 and was the first public transit agency in the world to attain international certification for environmental management (ISO 14001). The New York Power Authority is a major proponent of clean distributed energy technologies with 2.4 megawatts of installed capacity. It has 11 fuel cells in the New York City metropolitan region including eight at wastewater treatment plants, operated by NYC, where the units generate power using as fuel the gases produced through the wastewater cleansing process. INTEGRATED HEATING AND COOLING TRENDS In building control the controlled parameters include basic functions such as discharge air temperature, space temperature, humidity and fan control. The benefits of such a control system in an intelligent,

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integrated heating and cooling network include repeatable and individual parameter or area (zone) control. Proportional zone control is a type of temperature control. First, the zone temperature is sensed and compared to a setpoint. When the temperature is not at the setpoint, a control action is taken to add heat or cooling to the zone. Then, the temperature is sensed again for a new control cycle. The control may go beyond basic proportional temperature control and to integral or derivative control. In this case, the integral or derivative is used to calculate the amount that the temperature is from the setpoint. The control action is now limited to avoid overshooting these point and the oscillations that cause delays in control response. These delays can often occur with proportional control. Derivative control is often used in dynamic applications such as pressure control. Derivative control will measure the change of speed in the controlled condition and adjust the action of the control algorithm to respond to this change. The use of a combined Proportional, Integral and Derivative (PID) control loop allows the control variable to be accurately maintained at the desired levels with very little deviation. A combined sequence like PID can be used to integrate the control of several pieces of heating and cooling equipment to provide a more efficient and seamless operation. Combining this type of more accurate control with networking has been an important advance in building control. Networking takes building automation beyond traditional heating and cooling functions. Intelligent devices can be tied into the network, allowing data to be collected and energy usage to be measured. A networked system may also manage lighting, fire and access control. If these systems are fully integrated, then the expanded integrated control functions can also address environmental issues such as indoor air quality. A high level of integrated control allows coordinated control sequences with the entire building monitored and its various functions optimized. All of this can take place transparently, behind the scenes, automatically. Data from hundreds or thousands of I/O points in a building or building complex can be accessed quickly and used to assist in decision-making. The appropriate communications architecture allows easy access to system information to take place at different locations throughout the facility. This access may take place at local or remote personal computer workstations. Information management


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can provide both environmental compliance and energy management. A large part of the building’s set of plans can be loaded into the computer. For new buildings this involves access to the CAD (computer aided design) system that designed the building. For older buildings the drawings can be scanned into the CAD system and then utilized by the energy management system. Most DDC systems on the market today have open protocols. Many vendors offer interoperability with systems related to the building HVAC industry. Standard protocols for building controls include the BACnet protocol for building automation and control networks and the European Profibus developed for building automation systems in the European market. In the mid-1980s when there was no shortage of oil, the absence of a national energy policy resulted in a drop in the demand for energy management systems. The slower but continuous growth of these systems led to an awareness of the benefits of computerized control. Real energy cost reductions were noted as well as the other benefits of improved control. These benefits include longer equipment life, more effective comfort levels and expanded building information. The use of heating and cooling controls are driven by higher energy costs and potential energy crises. These also force a return to growth in the use of Demand Side Management. The growing requirements of indoor air quality and related environmental requirements force more applications for intelligent buildings and the control integration that they utilize. A distributed control system might control heating and cooling equipment and other loads such as lighting. Distributed control is applied at each piece of equipment to provide application specific control. A number of products have been introduced that use a type of communication network known as sensor or field buses. This technology has been growing quickly. Remote support can take place through a modem interface over telephone lines or through the Internet. Building systems may also do alarm dial outs to pagers and telephones with voice synthesis. Using building wide controllers that support plugand-play and objects, the system stores all critical system information at the controller level. Intelligent controllers of this type make it possible to dial into a system from a remote location, upload from the controllers and have full access to the system.

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Another related building wide control trend is integration at the functional level. This trend also includes a movement toward integrated control between systems with different functions such as security and building control systems. The speed of information transfer can be increased by switching from twisted pair cables to coaxial or fiber optics, however, these types of cables add to the installation costs. In the future, communications between sensors and multiplex boxes and the rest of the system may use a combination of technologies including traditional means such as twisted wire and coaxial and non-traditional methods such as infrared or radio wave. Peer controllers can be used for continuously interrogating the network for sequences such as morning warm-up. This feature would have been centralized in older systems. A single condition such as outside air temperature might have been monitored, and the building wide device would make a decision on start time based on this data and a stored sequence. When start up was required, that controller would signal the start of the sequence. With integrated control of this type, each controller can make independent decisions based on building wide data as well as local controller data. This results in a more reliable and effective building control system. Equipment level applications that are energy intensive include air handlers, chillers and boilers. Control sequences include such expanded applications as start/stop of non-HVAC loads and the on/off control of lighting and other electrical equipment. In the future, virtual reality may allow the operator to experience the environment. Special headsets and gloves may be used. After a complaint of a hot or cold temperature or a draft, an operator may zoom in to the space to feel and measure the temperature. Zooming inside the VAV box, the operator could check the damper position and view readouts of air volume and temperature. The thermostat or damper control could be adjusted while observing the system’s operation. The operator could also check the operation of fans, boilers and chillers using this zoom control. Adding a sensor to a room could be a simple operation. The sensor may have a self-adhesive backing and stick to the wall. Power could be supplied to the unit by a built-in solar cell with battery backup. The sensor would broadcast using infrared, radio wave, or microwave. The computer will recognize the sensor and assign a point number. The system would map the location of the


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sensor using triangulation of the signal and its internal map of the building. A self-optimization routine would be used to search for the optimum control strategy to utilize the new sensor. POWER MANAGEMENT TRENDS Power management may involve devices that regulate the on and off times of selected loads, such as fans, heaters, and motors. These devices reduce the electrical demand (kilowatts) and regulate energy consumption (kilowatt hours). In the past most of the energy savings has mainly been in heating. Power management devices can be electromechanical, electronic, or computer based. The operation of one or more loads is interrupted by the power management system based on control algorithms and building-operating parameters, such as temperatures, air flow, or occupancy. The savings in electrical energy use and cost range from 0 to 50% or more. Demand limit control raises the cooling setpoint in order to reduce some stages of cooling. This building wide sequence uses equipment turn-off and avoids demand peaks. Load-shaping involves the prediction of demand excursions for shedding loads or starting power generators to avoid setting new peaks. Power-monitoring software can be used to analyze energy use and power quality. It can identify load profiles to help with rate negotiation. If companies know their energy profiles, how and when they consume power, they can negotiate better rates for the type and amount of power they need. Electrical demand is defined as the average load connected by a user to an electrical generating system. It is measured over a short, fixed period of time, usually 15 to 30 minutes. The electrical demand is measured in kilowatts and recorded by the generating company meter for each measurement period during the billing month. The highest recorded electrical demand during the month is used to determine the cost of each kilowatt hour (kWh) of power consumed. Linking power management systems to control systems allows the power information to flow from both systems. Load profiles can be developed to find any energy inefficiencies. Energy scheduling can be used to find the optimum energy schedule for new product lines or processes.

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Real-time utility pricing means that production schedule energy requirements need to be compared with energy rate schedules for optimum energy benefits. The new energy supply market requires more companies to give back energy capacity during peak energy use times by scheduling lower-energy production. This can result in significant savings. Intelligent metering and monitoring systems offer a low-cost method for quickly implementing energy saving practices. A CutlerHammer plant in Asheville, NC, installed a power management system when energy bills were running close to $45,000 a month. After 6 months of installation, the plant energy saving was $40,000. The power management system allowed plant engineers to identify wasteful procedures, shift loads to level the demand and perform preventive maintenance. Better control of area lights during off hours was possible. Large electric oven loads were timed during the late shifts when the total energy demand was lighter. Maintenance technicians were able to locate abnormal conditions with monitoring screens and then service the equipment before it broke down. The total return on investment was predicted to be less than two years. Some power management devices function as load shedders. They reduce the demand or average load in critical demand periods by interrupting the electrical service to motors, heaters, and other loads for short periods. Since the load which has been turned off would normally have been operating continuously, the overall effect is to reduce the average load or demand for that period of time. The instantaneous load when the load is operating remains the same. When the period involved has the highest monthly demand, significant savings are possible in rate reductions. In periods other than the highest demand period, energy is still saved. Prior to the era of high energy costs, load shedding was used mainly to avoid demand cost penalties. Now, it is used to limit energy consumption, by cycling loads on and off for brief periods, as well as to reduce demand. Other techniques used to limit energy use include the computer optimization of start times, setpoints, and other operating parameters based on the weather, temperatures, or occupancy. Electronic demand limiting includes devices that monitor and measure the actual demand and provide control actions to limit the operation of attached devices when the measured demand reaches a specified value. These devices require two signals, the kilowatt hour


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(kWh) or demand pulse, which indicates the units of electrical energy consumed and a timing pulse, which indicates the end of one demand pulse and the start of the next one. Some load shedders use a demand target that is not fixed but increases at a steady rate. Other devices allow the off-on setpoints to be adjusted independently for individual loads. Loads can be cycled based on the maximum demand target, time of day and day or week, rate of demand increase, heating and cooling temperatures, pressures, fuel flow and rates, occupancy schedules, inside and outside temperatures, humidity, wind direction and velocity and combinations of the above factors. Durations can be variable and changed automatically according to these parameters. In air conditioning systems, intake and exhaust dampers can be controlled on the basis of air temperatures, so that the mix of air requiring the least energy is obtained at all times. The start-up and shut-down of air conditioning, heating, and lighting systems can be regulated according to inside and outside temperatures as well as occupancy to produce the conditions which consume the least energy. HEATING SYSTEM TRENDS Some newer heating system technologies involve modifications to conventional heat exchangers or the burn design. These changes provide steady-state efficiencies approaching 90%, with seasonal efficiencies to 85%. This is about 10% better than the steady-state efficiencies of 78 to 80% for the most efficient conventional designs. One technique uses spark ignition in the combustion chamber to hold exhaust gases at 120°F instead of 400°F or more. In this process almost all the useful heat is removed and the gases are cool enough to be exhausted through a plastic pipe. This type of system allows seasonal and steadystate efficiencies to reach 90%. Air and natural gas are mixed in a small combustion chamber and ignited by a spark plug. The resulting pressure forces the hot exhaust gas through a heat exchanger, where water vapor condenses, releasing the latent heat of vaporization. In subsequent cycles, the fuel mixture is ignited by the residual heat. One system manufactured by Hydrotherm, of Northvale, New Jersey, has efficiencies of 90 to 94%. The cost of the system is between 50 and 100% higher than a conventional one, but the improved efficiency can pay

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back the difference in 5 years. Conventional flame retention burners create a yellow flame, while modified flame retention burners create a blue flame in the combustion chamber. This is done by recirculating unburned gases back through the flame zone. This produces more complete burning of the fuel and results in lower soot formation. These flame systems are available as a burner for retrofit to furnaces, or as a complete burner and boiler system for hot water distribution systems. Variable fuel flow is used in burners to throttle or cut back the fuel flow rate, which reduces the flame size, as the system heating load varies. These burners have conventional steady-state efficiencies and higher seasonal efficiencies. They are available for large apartment boilers and furnaces. Tankless boilers offer some advantages in seasonal efficiencies, compared to conventional units, since there is less water to heat up and cool off. The savings are similar to that of using an automatic flue damper. Flue economizers include small auxiliary air-to-water heat exchangers that are installed in the flue pipe. The unit captures and recycles the usable heat that is usually lost up the flue. The recaptured heat is used to prewarm water as it returns from the distribution system. Depending upon the age and design of the boiler and burner, a flue economizer can provide annual fuel savings of 10 to 20% and a payback of 2 to 5 years. Air-to-air flue economizers are also available for about 1/5 the cost but these save much less energy and are usually not tied into the central heating system. GROUP HEATING TRENDS The technologies that are well suited to groups of buildings include cogeneration, district heating and seasonal energy storage systems. Cogeneration involves the simultaneous production of both space heat and electricity from an electrical generating system. A district heating system supplies heat and hot water from a central production facility to a number of residential, commercial and office buildings. A seasonal energy storage system is designed to store heat or cold energy during one season, when it is not needed, for use during another season.


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To be cost-effective, these types of technologies are usually applied to groups of buildings, but cogeneration and seasonal energy storage systems may be sized for small-scale applications. District heating may include cogeneration or summer storage of solar energy for winter space heating. District heating usually involves supplying hot water for space heating and hot water use from a central production facility to a group of residential or commercial buildings. District heating networks in Europe serve large portions of the populations of some countries. In Sweden, 25% of the population is served by district heating, in Denmark the number is over 30%, in Russia and Iceland it is over 50%. In the United States, district heating serves only about 1% of the population through older steam supply systems. In Europe, many of the district heating systems were installed during the rebuilding that followed World War II. District heat replaces relatively inefficient home heating systems with a more efficient, centralized boiler or cogeneration system. These offer the potential of major energy savings, although some heat is lost during the distribution of hot water. A centralized boiler or cogeneration system can be used to produce heat. Large, centralized oil-fired boilers can remove as much as 90% of the energy contained in the fuel. Cogeneration systems can also have a total heat and electricity efficiency approaching this. District heating systems can use the waste heat from electric generation and industrial plants that would be released to the air or to nearby water supplies. Some estimates suggest that district heating could save as much as one billion barrels of oil per year in the United States. In some European cities, waste heat from fossil fuel electric power plants is used for district heating with an overall energy efficiency of 85%. These plants were not originally constructed as cogenerating units. Waste heat from industrial process plants can also be used. Geothermal sources are used to provide heat for district heating systems in Iceland and Boise, Idaho. Hot water can be transported over longer distances with little heat loss while steam heat distribution systems can only serve highdensity regions. The largest steam system in the United States is a part of New York’s Consolidated Edison Company and serves a small part of Manhattan Island. The larger pipes or mains carry 200 to 250°F wa-

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ter under pressure. Return mains carry the cooler, used water at 120°F back to the central facility. Costs can be lowered with the use of newer types of pipes, insulating materials and excavation techniques. Plastic piping in long rolls is laid in plastic insulation and placed in narrow trenches. Using these techniques, hundreds of feet of pipe can be laid quickly. Metal radiators can also be replaced by plastic units. District heating systems are often financed by municipal bonds at low interest rates, to be repaid over a 30 to 40 year period. This makes the annual cost per home competitive with or less than that of conventional heating systems. A seasonal energy storage system is designed to store heat or cold during one season, when it is not needed, for use during another season. These systems have a large energy storage component. They collect essentially free heat or cold when they are plentiful and save them until required. The only energy consumed is that needed to run the various parts of the system. Three types of systems exist: annual cycle energy systems, integrated community energy systems and annual storage solar district heating. The first two can provide both heating and cooling while the third is used for heating only. The annual cycle energy system (ACES) has two basic components: a very large insulated storage tank of water and a heating-only heat pump. The tank contains coils of pipe filled with brine (salt water) warmed by the water in the tank. The brine circulates through a heat exchanger and transfers its heat to the heat pump refrigerant. During the heating season, heat is removed from the water tank by the brine and transferred to the building at a temperature of 100 to 130°F. The system may also be used to provide domestic hot water. As heat is removed from the tank, the temperature of the water drops below the freezing point and ice begins to form on the brine circulation coils. By the end of the heating season, ice fills the entire tank. This ice is then used during the summer to provide chilled water for air conditioning. While the ice remains in the tank, the only power required for cooling is for the operation of a circulator pump and a fan. In actual installations these systems have been shown to use about 45 to 50% of the electricity consumed in a similar house with conventional electric resistance heating. It is more efficient than a conventional air-to-air heat pump system, since the heat source is maintained at a constant, known temperature. In moderately cold climates


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with 6,000 degree-days, an ACES uses about 25% less electricity than a conventional heat pump with a coefficient of performance of 1.5. The initial cost of an ACES is much higher than that for conventional home heating and cooling systems, mainly because of the cost of the storage tank. Energy savings in a house with electric resistance backup can be over $1,000 per year, which gives about a 10 to 15 year payback. The system is usually sized to meet the summer cooling requirements, rather than the winter heating load, of a building. In order to meet the total heating requirements of a building, an ACES is best suited for climates where the heat provided to the building from the tank during the winter is nearly equal to the heat removed from the building for cooling and transferred back into the tank during the summer. This is possible in areas where the winter and summer climates are not too extreme, such as Maryland and Virginia. COMMUNITY HVAC TRENDS An integrated community energy system (ICES) is a type of district heating and cooling system that uses heat pumps to collect and concentrate energy. The use of heat pumps allows free heat that would otherwise be lost to be removed from fuel cells, boiler waste heat, groundwater, lakes, solar and geothermal sources. An ICES has three major components: heat pumps, a heat source which may also act as heat storage and a distribution system. The heat pump section of an ICES may be centralized, distributed or cascaded. In a centralized system, one or more large heat pumps are used in a manner similar to the centralized boiler of a district heating system. The heat pumps are located in a central facility, and they remove heat directly from a heat source. This heat is then used to warm distribution water, which is then pumped to individual buildings. In a distributed system, small heat pumps are located in each building. Water from the heat source is sent directly to an individual heat pump. Heat removed from the distribution water is then used to warm the building. Some heat pumps may be used to also provide cooling. A cascaded system uses both centralized and individual heat pumps. A central heat pump removes low temperature heat from the primary source and adds it to the distribution water, which is sent to

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individual buildings. Heat pumps in the buildings then use this distribution water as a secondary heat source. This system is used when the primary source water is too corrosive, such as salt water, or contaminated, such as waste water. The distribution system of an ICES is the same as that of a conventional district heating system. Each ICES has warm water supply and cool water return mains. Systems that supply both heating and cooling at the same time may have independent distribution systems for hot and cold water. Distributed systems using groundwater as a heat source may have only a distribution water supply line. Cascaded and distributed ICESs have separate heating distribution systems for each building. Depending on the winter climate, the heat source can be a lake, reservoir, underground storage tank, aquifer (underground river or lake), solar-heated water, sewage or waste water, geothermal energy or waste heat from industrial or commercial facilities. In an ICES that serves both small and large buildings, the surplus internal heat from the large buildings can be used to provide source heat to smaller ones. An ICES in areas with moderate winter temperatures may use air as a heat source. Systems that use lakes or reservoirs rely on the natural collection of heat by these water sources throughout the year. The operation of an ICES depends upon the nature of the heat source and if the system is centralized, distributed or cascaded. Solar energy can be used to warm heat pump source water. In this system solar collectors are mounted on a large, insulated water tank where the warmed water is stored. Most of the heat is collected in the summer for use during the winter. In the winter, the hot water can be used directly for space heating until it cools to about 85 to 90°F. The remaining heat can be removed and concentrated by a centralized heat pump. An ICES using a large fabricated tank of water can operate as a community-scale ACES. The water in the tank is slightly higher than 32°F. During the winter a centralized heat pump removes heat from the tank, causing the formation of ice. This ice is then used for summertime air conditioning or for winter cooling of large buildings. Sewage and wastewater heat sources are usually not much colder than the buildings from which they come. A cascaded ICES can remove heat from waste water and transfer it to the distribution system which then acts as a secondary heat source for heat pumps in indi-


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vidual buildings. Waste heat is often lost into the environment by industrial facilities in the form of hot water. This hot water can be used directly by the heat pumps in a centralized ICES. ICES have several advantages over conventional district heating systems or individual building heating systems. An ICES will often serve business, commercial and residential districts. Since the peak heating and cooling demands of these different sectors may not occur at the same time of the day, a single moderately sized system can meet the varying peaks of the different sectors. If the ICES contains a short-term heat storage component, such as a water tank, the system can operate continuously and at a steady level around the clock with peak heat demand requirements drawn from storage. Conventional heating systems burn fossil fuels at high temperatures to heat water to 120°F. Most district heating systems operate in the same way. In these cases, when the hot water cools to 90°F or less, it is no longer warm enough to supply heating. This remaining heat is eventually lost to the environment. An ICES can recover this low-temperature heat that would otherwise be wasted. This helps to increase system efficiency. An ICES is often found to be economically competitive with conventional heating systems such as furnaces and/or boilers in individual buildings or district heating systems using fossil fuels. Capital costs are a good deal higher than those of conventional systems, but ICESs have lower energy requirements. Free environmental energy is substituted for the burning of fossil fuels. In some ICESs, electricity consumption may be greater than in conventional systems lacking heat pumps, but the total consumption of all forms of energy is lower. SOLAR DISTRICT HEATING TRENDS ACESs and ICESs rely on heat pumps and storage systems, and need notable amounts of energy to operate. An annual storage solar district heating system could supply most of a community’s annual space heating requirements with a minimum of nonrenewable energy. An annual storage solar district heating system requires a heat store, a collecting area and a distribution system. The storage can be either an insulated earth pit or a below-ground concrete tank. Both have insulated concrete covers and are filled with water. Collectors

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are mounted on the cover of the storage tank and are rotated during the day so they always face the sun. During the summer, the collectors heat water for storage and for domestic hot water. During the winter, the collecting system heats water that is used directly for heating purposes. When additional heat is required, the hot water stored in the storage tank or pit is used. Water is removed from the top layers of the storage tank. The cooler used water is pumped back through the collectors or into the bottom of the storage tank. These systems cannot provide air conditioning so they are mostly suited to northern climates. This is because over the course of a year even northern locations such as Canada receive as much sunlight per square foot as Saudi Arabia. The problem is that most of the sunlight falls in the summer when it is not needed for heating. In annual solar storage the system collects heat in the summer for use during the winter. A large rock cavern in Sweden provides district heating for 550 dwellings. A housing project at Herley, near Copenhagen in Denmark, uses a central solar collector and a large insulated water tank buried in the ground. Solar heat provides most of the space heating requirements for 92 housing units. When the temperature of the heat store falls below 45°C, heat is transferred with a heat pump, powered by a gas engine, which boosts the temperature to 55°C. This process continues until the temperature of the heat store has fallen to 10°C, at the end of the heating season. Waste heat from the engine is also delivered to the heating system, and a gas boiler is used as a back-up. In summer, the main heating system is shut down and 90% of the domestic hot water requirements of the housing units are provided by additional solar collectors on each of the eight housing blocks. This type of system can also be implemented by a gas furnace. All of these systems operate in latitudes far to the north of American cities. An annual storage solar district heating system is capable of supplying 90% of the annual heating requirements for the homes in a community. Depending upon the climate zone, the required collector area per house can range from 70 to 300 square feet. This can be reduced if residential heat loads are lessened through increased weatherization and the addition of passive solar features. Solar district heating offers a number of advantages over conventional single-residence active systems. The collectors can be set aside in an open area and problems with access to the sun do not arise. The


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heat storage capacity is not constrained by space limitations in any one building and the storage tank can be as large as necessary. Since the system is equipped for annual storage, solar collection is not dependent on the day-to-day weather conditions. HYBRID COOLING TRENDS Hybrid cooling plants may use a number of different technologies to provide cooling. These technologies include electric chillers, absorption chillers, engine-drive and/or dual-drive chillers, thermal storage systems and the use of a water-side economizer cycle. Most of these seek to provide some or all of the cooling without using electricity during the high cost, peak period. The electric rate structure is a primary determinant in the choice of cooling medium. Hybrid plants are generally a better option because the cost of cooling with electricity during some periods can be less than the cost of cooling with natural gas. Absorption chillers, especially the double-effect type, are used for utility rate structures with high peak period demand. These include usage charges or rate schedules with ratchet clauses for the demand charges. There is a significant first cost premium for this equipment. Maintenance costs are generally comparable with electric chillers, but the absorption chiller requires more day-to-day maintenance. Enginedriven chillers provide an alternative to absorption chillers when natural gas cooling is desired. Engine-driven chillers utilize the same type of equipment as electric chillers for cooling, but replace the electric motor with a natural gas fueled engine. A major benefit of engine-driven chillers is the opportunity to capture waste heat from the engine as a mechanical cogeneration system. Another option is the use of dual-drive chillers with both an electric motor and a natural gas engine available to drive the chiller. Thermal storage systems can be used to shift the cooling load from high cost periods to low cost times of day. The major concern is allowing for sufficient storage and recharging capacity to allow for some load and temperature increase for overnight periods. There is a significant danger of poor operation and the inability to fully transfer loads if spare capacity is not available. Primary-secondary chilled water distribution systems were developed to allow a constant flow through chillers, required by the

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chiller manufacturers, with variable flow for the load side of the system to improve efficiency. The main applications are in multibuilding systems or systems with larger variations in load. The use of variable speed drives and DDC control systems made the operation of these systems much more effective. Newer chillers with digital control panels are able to operate effectively and safely with variable flow. Another significant advantage of the primary-secondary system is the system flexibility that it offers. This type of system makes it easier to incorporate hybrid systems, as well as thermal storage systems and water-side economizers. Depending on the piping and valving arrangement, the system can load chillers evenly or sequentially. They also allow for the preferential loading of particular chillers as required in a hybrid system to gain the maximum benefit. The complexity of these systems requires a well developed sequence of operations to ensure that the control system will provide the proper operation. Condenser water systems for electric chillers are usually designed with a 10°F temperature differential. Absorption chiller systems may operate with higher temperature differentials due to the greater amount of heat rejected from these units. There may be benefits for electric chiller systems in using a larger temperature differential for the condenser water system. The primary benefit is the reduction in the quantity of water to be pumped for the condenser water system to reject the same amount of heat. This allows the use of smaller piping and pumps. The higher temperature will improve the efficiency of the cooling tower, but will reduce the efficiency of the chiller. There is a reduction in costs due to the smaller pumps and piping. An oversized cooling tower provides additional capacity with an allowance for equipment problems. For operating costs, there is a reduction in pumping energy and a possible reduction in cooling tower energy, offset by an increase in chiller energy. The net effect will depend on the size of the system, amount of pumping, climate and hours of operation, but generally results in a net reduction in energy consumption. EXHAUST AIR TRENDS Exhausting air to outside is an effective way to provide a safe and comfortable working environment for industrial workers. Many


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exhaust systems are designed for peak demand and operate 24/7 with little or no controls. Normally, one fan controls several exhaust inlets. There are no dampers to close the inlets that are not in use. The fans are usually single speed and are not controlled by the building control system. They are manually turned on and run 24/7 in most cases. Most exhaust fans are in the range of 1/4-hp to 15-hp. Since exhaust fans do not consume a lot of energy compared to other HVAC equipment in the building, they are often overlooked for efficient operation. In manufacturing buildings, exhaust air needs to be made up by fresh outside air. Due to high air exhaust, some manufacturing buildings use almost 100% outside air during winter heating season. The supply system is used to create a comfortable environment in the plant and replace the air exhausted out by the exhaust system. The exhaust system removes contaminated air and reduces the heat concentration locally. The exhaust system can be divided into general exhaust and local exhaust. Local exhaust is more effective due to the fact it is close to the source of contamination. Temperature and humidity are controlled to ensure worker comfort and product quality. When excessive exhaust occurs, the supply system needs to supply more outside air than the minimum required for proper ventilation, resulting in more heating and cooling energy. An exhaust system retrofit was done by the Eldec Corporation, an aerospace electronic manufacturer. With the help of the local utility, Eldec implemented a control project to reduce exhaust air by up to 30% for the first shift and 60% for the rest of the time and achieved significant savings with a one year simple payback. The project closed the exhaust inlets with dampers and controlled the exhaust fan speeds with variable frequency drives (VFD). The exhaust fans are now monitored and controlled by the building direct digital controls (DDC) system to ensure proper operation and save energy. The facility had three buildings ranging from 70,000 to 80,000 square feet (SF). The HVAC systems are variable air volume (VAV) systems. Minimum 30% relative humidity is controlled in the production buildings. There were no dampers to close the inlets and no flow controls for the fans. Since these were local exhaust, heat recovery was not possible. The exhaust system ran constantly and due to exhaust, the HVAC systems had to operate the same way all the time. The building had operated this way by for many years. During 2000-2001, the power rate increased dramatically due to the energy crisis on the West

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Coast and it became a high priority to reduce the power usage. With no dampers in most of the exhaust inlets and no automatic controls on the fans, the exhaust air was very high and unnecessary. Modifications included easier operating dampers, using magnets to hold the dampers open and relocating the dampers so they would not obstruct normal operation. Visible warning lights were installed to indicate if the associated exhaust fans were on or off. The fans were controlled by variable frequency drives (VFD) and these were linked into the DDC system to schedule and monitor their operation. Workers were able to close dampers and turn off fans when they were not needed. The DDC system monitored the VFD operation and when the building was unoccupied, the VFDs were set to run at minimum. The building achieved a 30% energy reduction during occupied hours and 60% during the unoccupied hours. Environmental safety standards were used to check if the exhaust amounts were adequate. References

Hordeski, Michael F., Dictionary of Energy Efficiency Technologies, The Fairmont Press: Liburn, GA, 2004. Hordeski, Michael F., New Technologies for Energy Efficiency, The Fairmont Press: Liburn, GA, 2003. Hordeski, Michael F., Alternative Fuels—The Future of Hydrogen, The Fairmont Press: Liburn, GA, 2007.

Chapter 6

Environmental Mitigation Keywords: European Model Cap and Trade Theory Cap and Trade Problems Carbon and Renewables Renewable Energy Certificates Carbon Disclosure

Carbon Dioxide Abatement Sequestration Trends Agricultural Carbon Offsets Gasification Trends Nuclear Energy Trends Mitigation Trends

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arbon markets do not trade existing carbon, they trade the reduction of carbon emissions into the atmosphere. Like other emissions trading schemes, such as the sulfur dioxide market that helped to reduce the acid rain problem here in the U.S. over the past few decades, carbon markets would theoretically mitigate carbon emissions. Carbon markets are predominantly based on the idea of greenhouse gas (GHG) reduction and the growing concern about a warming planet. The idea may be sincere but quickly becomes complex in terms of actual measured emission reduction as well as unintended consequences. Carbon markets can be either voluntary or mandatory. In a voluntary market, an entity such as a company, individual, or another emitter volunteers to offset its carbon emissions by purchasing carbon allowances from a third party, who then uses this money in a project that will reduce carbon in the atmosphere. These projects include planting trees (natural carbon sequestration) or investments in renewable energy generation to reduces fossil fuel use from a carbon-emitting source. Compliance carbon markets function under a regulated limit to carbon emissions (a cap on emissions), where permits or allowances are given or auctioned to carbon emitters who then must conduct their business within this set limit. This provides a market for these allowances, where lower emitting entities can trade their extra allowances to those who need the additional capacity. These are called cap-and-trade carbon markets. 195

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THE EUROPEAN MODEL The EU Emissions Trading Scheme (EU ETS) was the first international attempt at a carbon market. It is a compliance market and functions as a cap-and-trade and a credit-and-trade system under rules set by the Kyoto Protocol. Article 17 of Kyoto sets up an ETS, where Annex I countries may exchange emission permits or trade emissions reductions from investment projects. These projects are called Clean Development Mechanisms (CDMs) if they take place in countries with no carbon limit and Joint Implementation (JIs) if they take place in countries with a carbon limit. The EU ETS represents about 2/3 of the total volume of carbon traded worldwide which reached $20 billion by 2006. In these growing carbon markets there have been several pitfalls. One has to do with the creation of the allowance market. The initial dispersal of allowances was over-allocated since the emissions cap did not equal the allowances that were allocated to emitters. The market was not based properly and it took some time for prices to conform to the actual market. Another area involves the CDM’s and responsibility. Emitters in the developed countries of the EU often used the lowest-cost method to satisfy their emissions reductions. This was often in the form of a CDM in a developing country. This led to projects that would have taken place anyway or projects where the emissions reductions could not be verified. Other projects created fewer carbon emissions, but produced other environmental or social problems. These concerns created increasing criticism of the EU ETS as it was currently run and led to having the U.N. critically approving the CDMs. This created additional investment risks in the market, since projects could be delayed or rejected. There were also issues on the enforcement and oversight mechanisms as well as the institutions for verifying emissions reductions and trading. These issues applied to the verification of emissions reductions claims and to the oversight for counting reductions. Multiple stakeholders could take credit for emission reductions that should be attributed to one emitter. CAP AND TRADE THEORY The basis of emissions trading or (cap and trade) is to provide economic incentives for achieving emissions reductions. A central authority, usually but not always a governmental body, sets a limit or cap on the

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amount of a pollutant that can be emitted. Emission permits are issued for allowances or credits which represent the right to emit a specific amount. The total amount of allowances and credits cannot exceed the cap, limiting total emissions to that level. Those that need to increase their emission allowance must buy credits from those who do not need them. This transfer of allowances is referred to as a trade. Thus, the buyer pays a charge for polluting, while the seller is rewarded for reduced emissions. The theory is that those who can reduce emissions most cheaply will do so, achieving emissions reduction at the lowest cost. An emission cap and permit trading system is a quantity instrument since it fixes the overall emission level, the quantity, and allows the price to vary. Any uncertainty in future supply and demand conditions, the market volatility, coupled with a fixed number of pollution credits creates an uncertainty in the future price of pollution credits, so industry bears the cost of adapting to these volatile market conditions and passes them on to the consumer. Since emissions trading uses markets to address pollution, it is often called an example of free market environmentalism, however, emissions trading requires a cap to reduce emissions. The cap is a government regulatory mechanism, so it is not correct to describe it as free market environmentalism since it is premised on government intervention. After the cap has been set by a political process, companies are free to choose how or if they will reduce their emissions. Failure to reduce emissions is often punishable by a fine that increases costs of production. If firms choose the least-costly way to comply with regulations, this should lead to reductions where the least expensive solutions exist, while allowing emissions that are more expensive to reduce to continue. The cap and trade approach was first studied in micro-economic computer simulations in 1967 for the National Air Pollution Control Administration. The studies used models of several cities and their emission sources to compare the cost and effectiveness of different techniques. The concept of cap-and-trade grew out of these studies as the least cost solution for a given level of abatement. CAP AND TRADE PROBLEMS Under volatile market conditions, the ability of the controlling agency to alter the caps translates into an ability to pick winners or losers and

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presents the opportunity for agency corruption. An emission tax is more of a price instrument since it fixes a price while the emission level is allowed to vary according to economic activity, but with an emission tax the outcome, the limit on emissions, is not certain. A tax removes capital from industry, suppressing investment. Carbon dioxide acts globally, so its impact will be similar wherever in the globe it is released. The location of the emissions does not matter. The policy should be different for regional pollutants since the impact of these pollutants is more local. The same amount of a regional pollutant can exert a large impact in some locations and a small impact in other locations. Most studies of the costs of reducing carbon emissions assume global participation, but since the Kyoto Protocol has limited country participation, this is likely to continue in any post-Kyoto agreement and carbon leakage will occur. Direct leakage results when production of a good is shifted to a country not bound to reduce its carbon emissions. Indirect leakage is the result of lower prices for oil and coal. Non-participating countries will import more oil and coal, both to fuel the production of energy-intensive exports and goods produced for domestic use. These effects may be substantial. Another concern about carbon mitigation is how to level the playing field with border adjustments. The American Clean Energy and Security Act puts carbon surcharges on goods imported from countries without cap and trade programs. Aside from issues of compliance with the General Agreement on Tariffs and Trade, such border adjustments assume that the producing countries bear responsibility for the carbon emissions. However, one fourth of China’s carbon emissions are generated in the production of exports, mostly for developed countries. RENEWABLE ENERGY CERTIFICATES These certificates are also called green tags. They are transferable rights for renewable energy within some American states. A renewable energy provider gets issued one green tag for each 1,000-kWh of energy it produces. The energy is sold into the electrical grid, and the certificates can be sold on the open market for profit. They are purchased by firms or individuals in order to identify a portion of their energy with renewable sources and are voluntary.


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They are typically used like an offsetting scheme or to show corporate responsibility, although their issuance is unregulated, with no national registry to check for double entries. It is a way for organizations to purchase energy from local providers who use fossil fuels, but back it with a certificate that supports a specific wind or hydro power project. Besides the European Union Emission Trading Scheme, in the U.S. there has been a national market to reduce acid rain as well as several regional markets in nitrogen oxides. There has been some movement on establishing a self regulatory organization like the Securities and Exchange Commission (SEC) to regulate a compliance carbon market. In the U.S. there is a movement for national carbon legislation and there are several regional initiatives already in place. A true carbon market would need to be able to act like existing financial markets that can operate internationally. Regional compliance markets include the Chicago Climate Exchange which is the largest voluntary carbon trading system in the U.S. It has been handling carbon offsets along with renewable energy investments. In California, AB 32 mandated greenhouse gas reductions of 25 percent by 2020 and 80 percent by 2050. The California Air Resources Board is responsible for enforcing this cap, and for making rules to implement the goal, probably a cap-and-trade system. The Regional Greenhouse Gas Initiative (RGGI) is a regional capand-trade system for Northeast states. Among its first trades was a forward trade for allowances at $7 a ton, placing an annual value for the RGGI market at $1.3 billion. CARBON AND RENEWABLES The question of how carbon market development relates to renewable energy development is not always direct. Now, any price associated with carbon may be good for renewables as long as carbon intensive energy generation becomes more expensive, which makes renewable energy generation more cost competitive. Least-cost carbon mitigation may continue the reliance on carbon intensive fuels by focusing on cleaner emissions and projects that do not necessarily displace carbon intensive fuel dependence. Or, the system may reward emissions reductions through efficiency measures and innovation that use both carbon mitigation and

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renewable energy development. If the focus is on carbon sequestration and other technologies that create cleaner carbon emissions, these applications could compete with renewables. If Renewable Energy Credits (RECs) are not bundled with Certified Emission Reductions (CERs), then there may be emissions reductions that are sourced exclusively from carbon mitigation and not renewable projects. Since emissions are reduced as renewables come online, the carbon quota should decrease to maintain price stability in the market and to assure that renewables are connected with emissions reductions. This can be done by linking RECs and CERs. Some argue against carbon and pollution credits stating that a company with sufficient profit margins may continue to generate profits while continuing to pollute by making payments to a cleaner company that has been more successful in making it’s processes less damaging to the environment. Among the critics of carbon trading as a control mechanism are environmental justice nongovernmental organizations, economists, labor organizations and those concerned about energy supply and excessive taxation. Some view carbon trading as a government takeover of the free market and argue that trading pollution allowances is dubious science and would have destructive impacts on projects for local peoples and their environments. They seek making reductions at the source of pollution and energy policies that are justice-based and community-driven. Many hold that emissions trading schemes based upon cap and tax will necessarily reduce jobs and incomes. They argue that emissions trading does little to solve pollution problems overall, since groups that do not pollute sell their conservation to the highest bidder. Overall reductions would need to come from a sufficient reduction of allowances available in the system. Agencies may issue too many emission credits, diluting the effectiveness of regulation and in effect removing the cap. Then instead of a net reduction in carbon dioxide emissions, there may be more. The European Union Emission Trading Scheme experienced this when it became apparent that actual emissions would be less than the governmentissued carbon allowances at the end of Phase I. There is also the practice of grandfathering, where free allowances are given by governments. Carbon Trade Watch argues that there is a disproportionate emphasis on individual lifestyles and carbon footprints, instead of the wider, systemic changes and collective political action that needs to be taken. Groups such as the Corner House argue that the market will choose the easiest means to save a given quantity of carbon in the short term,


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which may be different to the pathway required to obtain sustained and sizable reductions over a longer period, and so a market-led approach is likely to force technological lock-in. Small cuts may often be achieved cheaply through investment in making a technology more efficient, where larger cuts would require scrapping technology and using a different technique. They argue that emissions trading is undermining alternative approaches and limit technological change. An article in Financial Times argued that carbon markets create a gray area with room for unverifiable manipulations. Another criticism of emissions trading points out that old growth forests, which have slow carbon absorption rates, are being cleared and replaced with fast-growing vegetation. An alternative to cap-and-trade is cap and share, which was under consideration by the Irish Parliament and the Sky Trust. They argued that cap-and-trade or cap-and-tax inherently impact the poor and those in rural areas, who have less choices in energy consumption options. The International Air Transport Association with 230 member airlines and 93% of all international traffic take the position that trading should be based on benchmarking and setting emissions levels based on industry averages, instead of grandfathering which would use a company’s previous emissions levels to set their future permit allowances. They hold that grandfathering would penalize airlines that took early action to modernize their fleets, while a benchmarking approach would reward more efficient operations. Meaningful emission reductions with a trading system can only occur if they are measured at the operator or installation level and reported to a regulator. All trading countries must maintain an inventory of emissions at the national level. In addition, trading groups in North America may maintain inventories at the state level through The Climate Registry. For trading between regions these inventories must be consistent, with equivalent units and measurement techniques. In most industrial processes emissions can be physically measured by sensors and flowmeters in chimneys and stacks, but many types of activity must still rely on estimates or theoretical calculations. Local legislation may require additional checks and verification by government or third party auditors with prior or post submission to local regulators. Enforcement is another important, yet troublesome aspect. Without effective enforcement the value of the program is diminished. Enforce-

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ment may be done using several means, including fines or sanctioning those that have exceeded their allowances. Concerns include the cost and effectiveness of enforcement at the local, national and international level and the risk that these entities facilities may be tempted to mislead rather than make real reductions or make up their shortfall by purchasing allowances or offsets. The net effect of corrupt reporting or poorly managed or financed regulation can result in discounted emission costs and hidden increases in actual emissions. In the U.S., carbon reduction projects have started to take place. The AES Corporation and GE Energy Financial Services, a unit of General Electric announced a partnership to develop greenhouse gas emission reduction projects. The partnership would pursue an annual production volume of 10 million tonnes (metric tons) of greenhouse gas offsets, mainly through the reduction of emissions of methane, which is a greenhouse gas with potential effects 21 times greater than carbon dioxide. Projects to capture and destroy methane emissions will include agricultural waste, landfills, coal mines and wastewater treatment. The partnership may also pursue the development of offsets through energy efficiency projects and electricity generation from renewable sources. The partnership will sell offsets from these projects to commercial and industrial customers seeking to reduce the environmental impact of their operations or to provide green products or services to customers. The partnership will attempt to enhance the ability of the U.S. to expand energy resources while mitigating the negative environmental impacts of growth. The uniting of the two companies may give them a lead the development of the U.S. market for carbon offsets. The partnership will invest in projects using equipment from a variety of manufacturers, including GE products certified by its ecomagination program. GE Energy Financial Services and AES are moving ahead with the current focus on voluntary demands for greenhouse gas reductions with a future of possible mandatory emissions. This should help GE Energy Financial Services increase its $1.5 billion portfolio of investments in renewable energy projects. It is also part of GE’s ecomagination program, where GE is committed to help its customers meet their environmental challenges while reducing greenhouse gas emissions. GE will increase its investment in cleaner energy technologies, while reducing its greenhouse gas emissions. It also plans to improve the company’s energy efficiency by 30 percent by 2014. GE Energy Financial Services provides the capital, sales channels and risk management to AES’s


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ability in project development. AES has also formed an alternative energy group, making a $1 billion commitment to investments in wind, LNG, and climate change sectors. AES has adjusted its investments by as much as $10 billion over the next 5-10 years. It also set a target to produce up to 40 million tons of greenhouse gas emission offsets per year by 2012. This would be done with development projects under the Clean Development Mechanism of the Kyoto Protocol in Asia, Africa, Europe and Latin America. AES began investing in greenhouse gas reduction projects in the late 1980s and has a presence in almost every region of the world. The AES/GE partnership would establish strict standards for the creation, certification and registration of U.S. greenhouse gas emissions credits. It will have internationally accredited and independent environmental organizations assure that each carbon offset meets stringent scientific and technical standards. CARBON DISCLOSURE In South Africa the Eskom and Sasol companies starting reporting under the carbon disclosure project in 2007. South Africa was the first developing nation, along with Brazil, to participate. Eskom was the highest greenhouse gas producing company to report from any country, with 200 million tons of carbon dioxide per year, compared to Shell’s 105 million tons. Sasol reports about 70 million tons a year. Its Secunda coal-liquids plant is the largest single point source of greenhouse gas emissions in the world, according to a report to the South African Cabinet by the Department of Environmental Affairs and Tourism. The report called Re-thinking Investment highlighted South Africa’s disproportionate contribution to greenhouse gases and suggested remedies. The country’s consumption of oil and coal places it among the world’s top 20 greenhouse gas emitters. On a per capita basis, South Africans emit 20 times more carbon dioxide than the United States for each unit of GDP produced. South Africa and Russia are the most energy intensive of the BRICS (Brazil, Russia, India, China and South Africa). China has cut its carbon output in half during the last decade of the 20th century. South Africa’s emissions per capita, at 7.6 tons, are almost three times that of China’s 2.7 tons.

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The report stressed that present tax policies in South Africa encourage vehicles with larger engines, while an import duty of 15% is placed on sustainable products such as parts for solar water heaters. The large-scale implementation of solar heating has been estimated to create 50,000 to 120,000 new jobs. Eskom will be expanding its demand-side management program to provide financial incentives for installing one million solar water heaters. The report views the imposition of carbon taxes as a key reform to move the economy to a sustainable environmental basis. It noted that increasing an input cost requires a sacrifice, but increasing the price of environmentally detrimental resources, such as fossil fuels, through marketbased instruments should serve to make resource-efficient technologies such as renewable energy more competitive. But, these new taxes should not increase the overall tax rate. A carbon tax or other resource tax need not increase the overall level of taxation in an economy, but could simply be applied as a tax shift, with additional revenues generated by the tax being applied to reducing taxes on consumer goods, personal income or corporate profits. This process is also known as tax recycling. Research in South Africa indicated that a carbon tax with recycling to personal and corporate taxes could have a positive economic, social (redistributive) and environmental effect. It also indicated that it may be useful to provide a tax back option, where companies can claim tax relief by reducing their carbon footprints through energy efficiency or investing in renewable energy. The report stated that the country’s two heaviest users of coal were not against the idea of carbon taxes. In 2007 Eskom took the position that greenhouse gases must have a global price. Sasol also indicated the company had a cautious optimism regarding the use of a carbon tax. The Western Cape, which could be among the areas most affected by climate change in South Africa, has been the most progressive in developing sustainability. The Western Cape government has pushed to triple the national renewable energy target of 4% by 2015 and increase investments in new renewable energy generation capacity by 2015. The province is also requiring the installation of solar water heaters in new homes above a certain threshold value and will consider the implementation of a carbon tax in the province. They said that regulatory support for green energy and carbon trading markets should include reverse metering and a feed-in tariff, to allow


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renewable energy producers to sell energy back into the national grid at competitive prices. Climate changes may not be prevented, but it may be possible to minimize any damages from an altered climate. Certain preventive strategies could actively limit emissions of substances thought to be harmful. One strategy designed to avoid damage to the ozone layer was the reduction or banning of all uses of CFCs. The Montreal Protocol of 1987 proposed a 50% cut in CFCs by the year 2000, but not all nations signed the treaty. Most scientific studies push for at least a 90% ban if the ozone hole is to be reversed. This would not only help protect the ozone layer but would cut emissions of a trace greenhouse gas that could be responsible for up to 25% of global warming. The use of artificial fertilizers in agriculture also generates atmospheric nitrogen compounds that can reach the stratosphere and possibly destroy ozone. Present theories of the origin of acid rain indicate that we can limit acid rain by reducing sulfur dioxide emissions and moving to low-sulfur fuels. But, only about 20% of the world’s petroleum reserves are low in sulfur. Switching U.S. Midwestern power plants to low-sulfur coal could cause economic problems since much of the coal from the Midwest and Appalachia has a high sulfur content. Most of the electric power generated in the Midwest uses high-sulfur coal and it would cost tens of billions of dollars to scrub the sulfur out of coal. An energy cost would also be paid for the processes that remove the sulfur along with environmental problems from disposing of it. About 5% more coal would be needed to keep electricity production from these power plants at current levels if most of the sulfur is scrubbed out. It is also possible to keep sulfur dioxide from reaching the atmosphere by washing the coal or by removing the SO2 from the flue gas. Simple washing removes about 50% of the sulfur. Additional removal of up to 90% requires high temperatures and high pressures and may cost ten times as much as washing. Flue gas desulfurization (scrubbing) by reacting the effluent gas with lime or limestone in water can remove 8090% of the sulfur but creates large amounts of solid waste. Techniques for minimizing emission of SO2 from burning power plants has no effect on nitrogen oxide (NOx) emissions. Oxides of nitrogen result from the burning of nitrogen normally found in combustion air. The percentage of NOx generated by the burning of air is about 80% in conventional coal-fired boilers and depends mostly on the temperature of combustion.

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Improved furnace designs and combustion techniques could reduce NOx emissions from stationary sources by 40-70%. These methods are not in widespread use now. The processes for removing NOx from flue gases are still in an early stage of development. CARBON DIOXIDE ABATEMENT Reducing the amount of CO2 in the atmosphere could involve prescrubbing to take the carbon out of fuels before combustion, leaving only hydrogen to be burned. Another approach is postcombustion scrubbing which removes CO2 from the emissions stream after burning. Among the prescrubbing techniques is the hydrocarbon process, where hydrogen is extracted from coal and the carbon is then stored for possible future use or buried. Using this process, only about 15% of the energy in coal is converted to hydrogen for use as fuel in existing coal power plants. There is also much residual solid coal material to store. Removing 90% of the CO2 from the stack gases would cost about 0.5 to 1 trillion dollars or $2,000 to $4,000 per capita. Removing the CO2 at a power plant could use up about half the energy output of the power plant. Carbon could be filtered from power plant emissions, compressed into a liquid, and pumped into ocean depths of ten thousand feet. Here, the water pressure would compress liquid carbon dioxide to a high enough density to pool on the seafloor before dissolving. At shallower depths it would just disperse. However, injecting vast quantities of carbon dioxide could acidify the deep ocean and harm marine life. Protesters have forced scientists to cancel experiments to test this plan in Hawaii and Norway. A consortium of eight partners, including Canada, the United States, the European Union and BP (formerly British Petroleum) have a $25-million project to explore new technologies to capture and store carbon gas. The project has found techniques that reduce costs for geological carbon storage by up to 60%. Although more savings are needed before economical large-scale operations. Geological storage is one option that could play an important part in carbon dioxide control. Other researchers are working on projects that would allow the burning of fossil fuels. Researchers at Princeton are exploring a technology that would take the carbon out of coal. In this multistep process the


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coal reacts with oxygen and steam to make pure hydrogen that could be burned to produce electricity or used in hydrogen-powered cars. The byproducts are mostly carbon dioxide but there are also the contaminants that coal-burning plant now emit, such as sulfur and mercury. These would be buried. Other proposals for counteracting global warming from the greenhouse effect include releasing dust or other particles to reflect away part of the solar energy normally absorbed by earth. This could work on a global average basis, but the mechanisms of warming and cooling would vary and large regional climatic changes could still occur. The growing fossil fuel use in the 20th century changed the carbon record of the earth, but deforestation also had a major impact on carbon in the atmosphere. Forests serve as carbon sinks, producing oxygen while using carbon dioxide. The clearing of forests in the United States early in the century, combined with a large increase in postwar tropical deforestation, where much of the wood was burned, released carbon dioxide to the air and changed the atmospheric components. Researchers at the Monterey Bay Aquarium Research Institute, believe that rising carbon dioxide in the atmosphere will acidify the ocean’s surface waters in any case and pumping some of the carbon into the ocean depths could slow that process. Another plan is to pump the carbon into coal seams, old oil and gas fields and deep, porous rock formations. This high-pressure injection would also release the remaining oil or gas out of depleted fields. SEQUESTRATION TRENDS Mass sequestration involves storing CO2 in large underground formations. CO2 separation and capture are part of many industrial processes, but using these existing technologies is not cost-effective for largescale operations. Sequestration costs using most industrial techniques are quite high. The practicality and environmental consequences of mass sequestration techniques are still being proven from an engineering aspect. Geologic sequestration is being done in a North Sea field that produces gas which is heavily contaminated with natural carbon dioxide. Before shipping the gas, the Norwegian oil company Statoil filters out the carbon dioxide and injects it into a sandstone formation half a mile below the seafloor. The U.S. Department of Energy has a test project to

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drill a 10,000-foot well in West Virginia and pump carbon dioxide into the deep rock. Tapped-out oil and gas fields are full of drill holes that could leak the carbon dioxide. The stored gas might also seep into groundwater pools. But, the North Sea project seems to be going well. Seismic images under the ocean floor show that a thick layer of clay capping the sandstone is sealing in the millions of tons of carbon dioxide injected. Underground storage is being tested in Saskatchewan to determine if carbon dioxide can be safely buried. The Weyburn oil field which is 70 miles south of Regina may hold over 20 million tons of carbon dioxide over the project’s expected 25-year lifespan. Saskatchewan’s oil fields are expected to have enough capacity to store all the province’s carbon dioxide emissions for more than three decades. The Canadian government believes that carbon gas storage will help the country meet its emissions reduction targets under the 1997 Kyoto Protocol. It required industrialized nations to cut emissions of greenhouse gases by an average of 5% between 2008 and 2012. The Weyburn project has the backing of international energy companies as well as the U.S., European Union and Canada. Carbon storage provides a unique advantage, buried in an oil field, the gas boosts oil production by forcing residual deposits to the surface. At Weyburn, oil production is up 50% since carbon dioxide injection began four years ago. The Weyburn site was selected because, during 44 years of oil exploration, Saskatchewan required oil companies to keep extensive geological records. Core samples from 1,200 bore holes allowed an extensive look at subsurface conditions and a way to track the movement of oil and gases. Carbon dioxide is injected almost a mile underground under a thick rock layer. The buried carbon dioxide is tracked by checking vapors in wells and groundwater testing. Seismic tests provide a portrait of subsurface conditions. The site has hundreds of oil wells over a 70-square-mile area. Each well shaft can act as a conduit to bleed carbon dioxide to the surface. Some wells are being closed off while others are checked for traces of carbon dioxide. Computer models are being used to forecast how the site will perform over several millenniums. One computer model showed that carbon dioxide could migrate upward about 150 feet in 5,000 years although it would still be far below the surface. Deep-well injection of the gas may force briny water to the surface, potentially polluting streams and aquifers. Earthquakes have also been reported in places where


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deep-well injection has occurred and carbon dioxide can convert to an acid in groundwater. In 1986, 1,700 people in West African Cameroon, suffocated when a giant bubble of naturally occurring carbon dioxide erupted from Lake Nyos and displaced the available oxygen in the immediate area. Every day, almost 5,000 tons of liquefied carbon dioxide arrives from a plant near Beulah, N.D. This plant is operated by the Dakota Gasification Co., which converts coal to natural gas. The liquid carbon dioxide passes through a 220-mile-long pipeline before it is pumped underground in Canada. Separating the carbon dioxide is expensive since the scrubbing process uses almost one-third of the energy produced by the power plant. It costs about $30 a ton to separate carbon dioxide from industrial exhaust, although the technology exists to cut this almost in half. The Energy Department’s goal is to get this down to $8 a ton. At this price, the emissions could be captured and stored in the U.S. while increasing the cost to produce electric power by less than 10%. The Energy Department’s goal for power plants would have them capture 90% of their carbon emissions by 2012. California may have enough depleted oil fields and subsurface saline deposits to store all the carbon dioxide that the state’s power plants can produce for the next few centuries, according to the Lawrence Berkeley Laboratory. Pilot projects using carbon dioxide injection to enhance oil recovery have been conducted in Kern County. Creating carbon sinks includes planting new forests, which the Kyoto climate treaty encourages. In China, the government has planted tens of millions of acres of trees since the 1970s. This was done to control floods and erosion, but one result has been to soak up almost half a billion tons of carbon. Young trees are hungry for carbon before they mature so one technique is to keep a forest young, by regular thinning. U.S. forests have increased by more than 40% in the last 50 years from 600 billion to nearly 860 billion. Standing timber is increasing at a rate of almost 1% per year in the country. Reforestation can be used as a carbon bank to capture carbon from the atmosphere, but the decay or burning of harvested trees decades later would add some carbon. Vegetational carbon banks would compete with agriculture for land and nutrient resources. It is estimated that a land area about the size of Alaska would need to be planted with fast-growing trees over the next 50 years to use up about half the projected fossil-fuel-induced CO2 at a

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cost of about $250 billion or $50 per person for the global population. One problem is that once the trees are fully grown they no longer take up CO2 very rapidly and would need to be cleared so new trees could be planted to continue a quicker uptake. Old trees could be used for lumber, but not fuel, since this would release the CO2. If used as fuel, a delay of 50 years, (the typical growth time) would occur and move up the buildup rate of atmospheric CO2. In 2000, global warming talks in the Netherlands broke down overcarbon accounting. The United States wanted to use its forest areas to offset some carbon emissions. This type of trading of carbon rights was the kind of approach that most mainstream environmental groups in the United States had promoted in an attempt to give business an inducement to conserve. In Europe, environmentalists have taken a stronger stand against industry and viewed it as a plan for evading responsibility for cleaning up the global atmosphere. MITIGATION TRENDS Besides carbon sequestering there is biochar, low carbon nuclear energy sources and cement absorption. Storing carbon dioxide gas in the ground or in saline solutions is being done at several tens of millions of tons/year worldwide. The amount offset by solar power is about the same, but the worldwide total generated is more than 25 billion tons per year. Nuclear power offsets 2 billion tons per year. Fertile black soils may provide a cheaper technique for carbon storage. Dark, charcoal-rich soil known as terra preta (Portuguese for black earth) is being studied as a potential carbon sink. Burying biomass-derived charcoal (biochar) could boost soil fertility and transfer carbon dioxide from the atmosphere into storage in topsoil. Charcoal has been traditionally made by burning wood in pits or temporary structures, but modern pyrolysis equipment can greatly reduce the air pollution. Gases emitted from pyrolysis can be captured to generate valuable products instead of being released as smoke. Some of the byproducts may be condensed into bio-oil, a liquid that can be upgraded to fuels such as biodiesel and synthesis gas. A portion of the noncondensable fraction is burned to heat the pyrolysis chamber, and the rest may provide heat or fuel for power generation. Pyrolysis equipment now in development at several public and pri-


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vate sites typically operates at 350 - 700 °C. In Golden, Colorado, Biochar Engineering Corporation is building portable $50,000 pyrolyzers that will be used to produce tons of biochar per week. The company is planning larger units that could be trucked into position since biomass is expensive to transport. Pyrolysis units that are located near the source of the biomass are preferable to larger, centrally located facilities. Charcoal-mediated enhancement of soil have been found to cause a 280-400% increase in plant uptake of nitrogen and a greenhouse study showed that low-volatility biochar supplemented with fertilizer outperformed fertilizer alone by 60%. The heat and chemical energy released during pyrolysis could replace the energy derived from fossil fuels and some calculations indicate a total benefit equivalent to removing 1.2 billion metric tons of carbon from the atmosphere each year. This would offset 29% of today’s atmospheric carbon, which is estimated at 4.1 billion metric tons, according to the Energy Information Administration. CARBON SEQUESTERING The MIT Future of Coal 2007 report estimated that capturing all of the 1.5 billion tons per year of carbon dioxide generated by the coal-burning power plants in the U.S. would generate a gas flow of about one-third of the volume of the natural gas flowing in the U.S. gas pipeline system. This technology is expected to use between 10 and 40% of the energy produced by a power station. In 2007, the EPA estimated about 35 million tons of CO2 were sequestered in the U.S. The Japanese government is targeting an annual reduction of 100 million tons in carbon dioxide emissions by 2020. Industrial-scale storage projects include Sleipner in the North Sea where Norway’s StatoilHydro strips carbon dioxide from natural gas with amine solvents and disposes of this carbon dioxide in a deep saline aquifer. Since 1996, Sleipner has stored about one million tons per year. The Weyburn project, which started in 2000, has been the world’s largest carbon capture and storage project. It is used for enhanced oil recovery with an injection rate of about 1.5 million tons per year with plans to expand the technology to a larger scale. At a natural gas reservoir in Salah, Algeria, the CO2 will be separated from the natural gas and re-injected into the subsurface at a rate of

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about 1.2 million tons per year. An Australian project will store 3 million tons per year. The Gordon project is part of an off-shore Western Australian Natural Gas extraction operation project and will become the largest CO2 storage project in the world. It will capture and store 3 million tons per year for 40 years in a saline aquifer and will cost about $840 million. For CO2 capture from the air, the European Commission is spending 1.25B euros for carbon capture and storage (CCS) at 11 coal-fired plants in Europe, including four in Britain. The four British power stations include the controversial Kingsnorth plant in Kent, Longannet in Fife, Tilbury in Essex and Hatfield in Yorkshire. Japan and China have a project that will cost 20 to 30 billion yen and includes JGC and Toyota. The project will transfer more than one million tons of CO2 annually from the Harbin Thermal power plant in Heilungkiang Province to the Daqing Oilfield, about 100-km from the plant, to be injected and stored in the oilfield. The Novacem company is making cement from magnesium silicates that absorb more CO2 as it hardens. Normally cement adds about 0.4 tons of CO2 per ton of cement, but this cement can remove 0.6 tons of CO2 from the air. There is an about 10 trillion tons of magnesium silicate in the world which could store 6 trillion tons of CO2. This represents several hundred years of storage at present emission rates. Calera cement also has a process for carbon capture and storage. In every ton of Calera cement, they are sequestering half a ton of CO2. The Calera cement process uses flue gas from coal, steel or natural gas plants with seawater for calcium and magnesium. Calera has an operational pilot plant. Nuclear power worldwide offsets 2 billion tons of CO2 per year/ power, wind energy, solar power, geothermal and hydro-electric power can offset a lot of CO2 by displacing coal power, oil and natural gas. The technology for CO2 capture from the air is progressing. Carbon Sciences and others are trying to scale up the capture into fuel. Carbon Sciences estimates that by 2030, 25% of the CO2 produced by the coal industry can provide enough fuel to meet 30% of the global fuel demand. This carbonate technology combines CO2 with industrial waste minerals and transforms them into a chemical compound, calcium carbonate, which is used in applications such as paper production, pharmaceuticals and plastics.


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AGRICULTURAL CARBON OFFSETS American Electric Power has an agreement with an affiliate of Environmental Credit Corp.(ECC) to purchase approximately 4.6 million carbon credits between 2010 and 2017 generated from capturing methane on livestock farms. One carbon credit is equal to one ton of carbon dioxide reduction. The agreement is part of the first large-scale livestock methane offset program in the U.S. that will capture and destroy methane from approximately 400,000 head of livestock on almost 200 U.S. farms. ECC is investing more than $25 million in services and materials to bring the 200 farms online with emission reduction. Environmental Credit is a supplier of environmental credits to global financial markets. ECC creates carbon credits for sale into the growing emissions trading markets in the United States and Europe. ECC is a member of the Chicago Climate Exchange (CCX) as a credit aggregator and offset provider. ECC markets carbon credits through the CCX as well as directly to power companies, industrial greenhouse gas emitters, and to state and privately managed funds that specialize in carbon credits. Methane capture programs from livestock farms reduce the possible impact of a potent greenhouse gas while limiting odor and pest issues. They also provide a source of income for farmers who often have thin margins. A farm with 2,000 head of livestock could receive more than $100,000 during the 10-year contract. Methane from livestock manure accounts for almost 7 percent of total greenhouse gas emissions in the U.S. Methane is 21 times more potent than carbon dioxide in trapping heat in the atmosphere and is released into the air through manure-handling practices. In the methane-capture program, storage lagoons are used to capture and burn off the methane, converting it to carbon dioxide. AEP will buy up to 600,000 carbon credits per year between 2010 and 2017 at a fixed price from ECC. ECC will work with farmers to design and provide lagoon cover systems, including gas meters and flares, at no cost to the farmers. ECC also will provide data monitoring, reporting, verification, certification and registration of the carbon credits with the Chicago Climate Exchange (CCX), the world’s first and North America’s only voluntary, binding greenhouse gas emissions reduction and trading program. AEP is a founding member of CCX and the largest U.S. utility to join CCX. AEP views the methane offset program as part of a comprehensive program to address greenhouse gas emissions. Other components of their

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program include building the next generation of clean, coal-gasification plants, validating technology to capture and store carbon from existing coal plants and investing in new renewable generation with offsets. It is committed to reduce, avoid or offset its greenhouse gas emissions to 6 percent below the average from 1998 to 2001. AEP will reduce or offset about 46 million metric tons of greenhouse gas emissions. This includes power plant efficiency improvement, renewable generation such as wind and biomass co-firing, off-system greenhouse gas reduction projects, reforestation projects and the buying of emission credits from CCX. AEP is adding 1,000 megawatts of wind capacity while installing carbon capture on two coal-fired power plants and reducing carbon dioxide emissions from existing plants. AEP’s plans include post-combustion and pre-combustion solutions for coal-fired generation. The company also has continuing and new initiatives for demand-side and supply-side efficiency. American Electric Power is one of the largest electric utilities in the United States, delivering electricity to more than 5 million customers in 11 states. It is among the nation’s largest generators of electricity, with more than 38,000 megawatts of generating capacity in the U.S. AEP also owns the nation’s largest electricity transmission system, a 39,000-mile network with more 765 kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. AEP’s transmission system directly or indirectly serves about 10 percent of the electricity demand in the Eastern Interconnection, the interconnected transmission system that covers 38 eastern and central U.S. states and eastern Canada, and about 11 percent of the electricity demand in ERCOT, the transmission system that covers most of Texas. AEP’s utility units include AEP Ohio, AEP Texas, Appalachian Power (Virginia and West Virginia), AEP Appalachian Power (Tennessee), Indiana Michigan Power, Kentucky Power, Public Service Company of Oklahoma, and Southwestern Electric Power Company serving Arkansas, Louisiana and east Texas. EFFICIENCY AND EMISSIONS TRENDS Several research projects have focused on the use of solid oxide fuel cells (SOFCs) with coal-based power production systems. Plants that incorporate SOFCs have the potential for significantly higher efficiencies


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and lower emissions than conventional coal technologies. High-temperature electro-chemical systems can enhance energy storage in central coal power plants, reducing the impact felt during hours of peak demand and making the plants more cost effective. One program had six competing industry teams supported by a core technology program. The teams involved FuelCell Energy, Delphi, General Electric, Siemens Power Generation, Acumentrics, and Cummins Power Generation. The benefits and feasibility of hybrid systems have been established with conceptual studies and small-scale demonstrations fueled with natural gas. Large-scale, greater than 100-MW, fuel cell/turbine hybrid systems could become a reality with a reduction in fuel cell costs and the scalability to larger units. The program demonstrated 3 to 10-kW SOFC systems with costs of less than $800/kW in 2005. Fuel cell/gas turbine hybrids form the essential power block component of the FutureGen plant concept for high overall efficiency and exceptional environmental performance. The SECA Fuel Cell Coal-Based Systems program had a goal to develop and demonstrate fuel cell technology for central power station and produce environmentally-friendly electricity from coal using advances in solid oxide fuel cell (SOFC) technology. The near-zero emissions program for coal-fueled power stations aimed at a 50 percent or greater overall efficiency in converting the energy in coal to electrical power, the capture of 90 percent or more of the carbon in the coal fuel, a cost of $400 per kilowatt, excluding the coal gasification and carbon dioxide separation systems. The projects being conducted by research teams led by General Electric Hybrid Power Generations Systems (GE HPGS), Siemens Power Generation and FuelCell Energy concentrate on fuel cell technologies that can support power generation systems larger than 100 megawatts. GE HPGS is a partner with GE Energy, GE Global Research, Pacific Northwest National Laboratory (PNNL), and the University of South Carolina in developing an integrated gasification fuel cell (IGFC) system. It would combine GE’s SECA-based planar SOFCs and gas turbines with coal gasification technologies. The system design would use a SOFC/gas turbine hybrid as the main power generation unit. Siemens Power Generation in partnership with ConocoPhillips and Air Products and Chemicals, Inc. (APCI), are involved in the development of large-scale fuel cell systems based upon their gas turbine and SECA SOFC technologies. The design will use an ion transport membrane (ITM) oxygen air separation unit

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(ASU) from APCI with improved system efficiency. FuelCell Energy in partnership with Versa Power Systems, Nexant, and Gas Technology Institute are involved in research and development of more affordable fuel cell technology that uses synthesis gas from a coal gasifier. The project includes fabrication and manufacturing capabilities for solid oxide fuel cell stacks for multi-megawatt power plants. The High Temperature Electrochemistry Center (HiTEC) Advanced Research Program provides research for fuel cell coal-based systems and FutureGen. HiTEC is located at the Pacific Northwest National Laboratory with support groups at Montana State University and the University of Florida. HiTEC is investigating the development of high temperature electrochemical power generation and storage technologies and advanced fuel feedstocks. Coal-based power production systems that use SOFC systems could have higher efficiencies and lower emissions than conventional technologies. High-temperature electrochemical systems could improve energy storage in central coal power plants, reducing the peak capacity during high demand periods and greatly reducing costs. General Motors is applying cell technology to stationary power. Dow and GM are working on a significant fuel cell application at the Dow Chemical Company plant in Freeport, TX. The Freeport plant is Dow’s largest chemical manufacturing installation in the world and one of the world’s largest chemical plants. In 2004 Dow Chemical and GM began the installation of fuel cells to convert excess hydrogen into electricity. Hydrogen is a natural byproduct of chemical manufacturing at Dow Chemical. Dow uses its excess hydrogen as fuel for boilers and also sells hydrogen to industrial gas companies for resale to their customers. Using this hydrogen through a fuel cell to generate electricity is more efficient and economically desirable than either of these applications. By efficiently consuming byproduct hydrogen in a fuel cell, Dow will reduce emissions of greenhouse gases and create competitively priced electricity. Dow and GM plan to install up to 400 fuel cells to generate 35 megawatts of electricity. GASIFICATION TRENDS The Tampa Electric Company plant in Polk County, Florida, uses coal gasification to generate some of the nation’s cleanest electricity. Coal


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gasification could be the next generation of coal-based energy production. The first coal gasification power plants are now operating in the U.S. and other nations. Coal gasification is a way to generate extremely clean electricity and other high-value energy products. Instead of burning coal directly, coal gasification reacts coal with steam and carefully controlled amounts of air or oxygen under high temperatures and pressures. The heat and pressure breaks the chemical bonds in coal’s complex molecular structure with the steam and oxygen forming a gaseous mixture of hydrogen and carbon monoxide. Pollutants and greenhouse gases can be separated from the gaseous stream. As much as 99% of sulfur and other pollutants can be removed and processed into commercial products such as chemicals and fertilizers. The unreacted solids can be marketed as coproducts such as slag for road building. The primary product is a fuel-grade, coal-derived gas which is similar to natural gas. The basic gasification process can also be applied to other carbon-based feedstocks such as biomass or municipal waste. In a conventional coal-burning power plant, heat from the coal furnaces is used to boil water, creating steam for a steam-turbine generator. In a gasification-based power plant, the hot, high pressure coal gases from the gasifier turn a gas turbine. Hot exhaust from the gas turbine is then fed into a conventional steam turbine, producing a second source of power. This dual, or combined cycle arrangement of turbines is not possible with conventional coal combustion and offers major improvements in power plant efficiencies. Conventional combustion plants are about 35% efficient (fuel-to-electricity). Coal gasification could boost efficiencies to 50% in the near term and to 60% with technology improvements. Higher efficiencies mean better economics and reduced greenhouse gases. Compared to conventional combustion, carbon dioxide exits a coal gasifier in a concentrated stream instead of a diluted flue gas. This allows the carbon dioxide to be captured more easily and used for commercial purposes or sequestered. Historically, the use of gasification has been to produce fuels, chemicals and fertilizers in refineries and chemical plants but DOE’s Clean Coal Technology Program allowed utilities to build and operate coal gasification power plants in Tampa, Florida, and West Terre Haute, Indiana. A Clean Coal Technology gasification project is also operating at Kingsport, Tennessee, producing coal gas that is chemically recombined into industrial grade methanol and other chemicals. Gasification power plants cost about $1200 per kilowatt, compared to conventional coal plants at around

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$900 per kilowatt. The Vision 21 program focuses on new concepts for coal-based energy production where modular plants would be configured to produce a variety of fuels and chemicals depending on market needs with virtually no environmental impact outside the plant’s footprint. Membranes would be used to separate oxygen from air for the gasification process and to separate hydrogen and carbon dioxide from coal gas. Improved gasifier designs could be capable of handling a variety of carbon-based feedstocks. Advanced gas cleaning technologies would capture virtually all of the ash particles, sulfur, nitrogen, alkali, chlorine and hazardous air pollutants. The Clean Coal Power Initiative would investigate these high-potential, but high-risk, technologies. Many countries and companies have channeled R&D efforts into generating hydrogen and electricity from coal without releasing CO2. Gasification and cleaning that combines coal, oxygen or air and steam under high temperature and pressure generates a syngas (synthesis gas) of hydrogen and CO2. The syngas does not contain impurities such as sulfur or mercury. A water-gas shift reaction is then used to increase the hydrogen production and create a stream of CO2 that can be piped to a sequestration site. The hydrogen-rich gas is sent to a Polybed Pressure Swing system for purification and transport. The remaining gas that comes out of the system can be compressed and sent to a combined cycle power plant. These are similar to the natural gas combined cycle plants used today. The plant output can be adjusted to generate more power or more hydrogen as needed. The FutureGen project which was also known as the Integrated Sequestration and Hydrogen Research Initiative, is a 275-MW prototype plant that will cogenerate electricity and hydrogen and sequester 90% of the CO2. This advanced coal-based, near-zero emission plant is planned to produce electricity that is only 10% more costly than current coal-generated electricity while providing hydrogen that can compete with gasoline. The Department of Energy has issued a National Environmental Policy Act (NEPA) Record of Decision to move forward toward the first commercial scale, fully integrated, carbon capture and sequestration project in the country. The Department’s decision is based on consideration of the proposed project’s potential environmental impacts, as well as the program goals and objectives. The Department of Energy’s total anticipated financial contribution for the project is $1.073 billion, $1 billion of this will come from Recovery


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Act funds for carbon capture and sequestration research. The FutureGen Alliance’s total anticipated contribution is $400-$600 million. The total cost estimate of the project is $2.4 billion. When fully operational, the facility will use integrated gasification combined cycle technology with carbon capture and sequestration into a deep saline geologic formation. It will be designed to capture 90% of the carbon emissions by the third year of operations, but may be operated at 60% capture in the early years to validate plant integration and sequestration ability. This project should sequester one million tons of CO2 annually when it reaches full commercial operation. The country needs abundant, affordable energy to ensure sustained economic growth and development. Inexpensive energy has fueled development and enhanced the quality of life in the U.S. and the world. The world’s energy use will rise, and the cost of energy will rise. India and China, represent almost 40 percent of the world’s population and with higher economic growth rates will consume far more energy in the future. About 85 percent of the United States’ and the world’s energy needs are met by fossil fuels. America’s energy needs to be affordable, secure, abundant, and environmentally sound. A comprehensive transformation of America’s energy technologies is both needed and possible. We must deploy known technologies to improve the efficiency of systems, devices, buildings and vehicles to reduce energy use. This includes the use of coal as a major energy resource with less environmental adversity. FutureGen, a demonstration project for carbon capture and safe storage, is a key project that must move forward if we are to ensure that the technology will be viable on a large scale. Coal provides about 50 percent of U.S. electricity, 70 percent in China and is the source of about 85 percent of the electricity in Missouri. Coal is abundant and accessible. Ultimately, America’s energy future depends on the development of many energy supplies, including nuclear, solar photovoltaics, biofuels, wind, geothermal and hydro. Expanding any of these poses challenges, including cost, environmental concerns, appropriate use of land and, for nuclear, the radioactive waste and proliferation of nuclear weapons. It is essential that the United States embark upon a massive, sustained research and development effort to assure energy supply options and to establish the United States as the world leader in energy technology. The rest of the world, especially China, is aggressively pursuing the development of new energy technologies through ambitious energy research and

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development efforts. Building large commercial coal gasification combined cycle units could be difficult based on the history that traditional power generators have had with simpler chemical processes. Sequesting the CO2 can be another technological challenge. NUCLEAR ENERGY TRENDS Increases in energy production include nuclear power. Nuclear power has been promoted as a clean source of energy that, unlike fossil fuels, produces no greenhouse gases or air pollution. Nuclear power is more environmentally friendly because it does not contribute to global warming the way fossil fuels do. Unlike coal, natural gas and oil-fired power plants, nuclear plants are free not only of carbon emissions but also of other noxious gases like sulfur dioxide, mercury and nitrogen oxide that have made fossil-fuel burning plants the biggest source of air pollution in the United States. Nuclear energy does not produce as much CO2 or other greenhouse gases as fossil power, but it’s inaccurate to call nuclear technology CO2 free. A large amount of electric power is used to enrich the uranium fuel, and the plants that manufacture the fuel in the U.S. are powered with coal. When fuel mining, preparation, transportation and plant construction are included with power production, nuclear power can produce about 5 grams/kWh. Wind or biomass power can produce 15-20 grams/ kWh with hydro as much as 60 grams/kWh and solar 50-70 grams/kWh. Fossil fuels start at 120-180 grams/kWh for natural gas, 220 grams/kWh for oil and 270-360 grams/kWh for coal. Uranium production does have a notable impact on ozone depletion. The Environmental Protection Agency’s (EPA) Toxic Release Inventory showed that in 1999, the nation’s two commercial nuclear fuel-manufacturing plants released 88% of the ozone-depleting chemical CFC-11 by industrial sources in the U.S. and 14% of the discharges in the whole world. The family of nuclear reactors known as light water reactors (LWRs) are cooled and moderated using ordinary water. These tend to be simpler and less expensive than other types of nuclear reactors. They have excellent safety and stability features and make up the vast majority of civilian nuclear reactors as well as naval propulsion reactors throughout the


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world. LWRs include pressurized water reactors (PWRs), boiling water reactors (BWRs) and supercritical water reactors (SWRs). The SWR remains theoretical as a Generation IV design that is only partially moderated by light water and has some of the characteristics of a fast neutron reactor. PWRs include the passively-safe AP1000 Westinghouse unit as well as several smaller, modular units such as the Babcock and Wilcox MPower and the NuScale MASLWR. The Russian Federation offers the VVER1000 and the VVER-1200 for export while France has the AREVA EPR and Japan the Mitsubishi Advanced Pressurized Water Reactor. China and Korea are also constructing PWRs. The Chinese are engaged in a massive program of nuclear power expansion and the Koreans are designing and constructing their second generation of national designs. BWRs are offered by General Electric and Hitachi in the form of the ABWR and the ESBWR for construction and export. Toshiba also offers an ABWR unit for construction in Japan. Germany was once a major producer of BWRs but has moved towards a massive expansion of coal power plants. Other types of nuclear reactors for power generation are the heavy water moderated reactor, built by Canada (CANDU) and India (AHWR), the advanced gas cooled reactor (AGCR), built by the United Kingdom, the liquid metal cooled reactor (LMFBR), built by the Russian Federation, France and Japan, and the graphite-moderated, water-cooled reactor (RBMK), found in the Russian Federation and former Soviet states. Electricity generation capabilities are comparable between all of these reactors, but due to the extensive experience of the LWR, it has been favored in most new nuclear power plants followed by the CANDU/ AHWR for a smaller number of plants. Light water reactors make up the majority of reactors that power nuclear naval vessels. The Russian Federation’s Navy uses liquid-metal cooled reactors in its Alfa class submarine. These use lead-bismuth eutectic as a reactor moderator and coolant. The majority of Russian nuclear-powered boats and ships use light water reactors. A level of inherent safety is built in to these reactors, since light water is used as both a coolant and a neutron moderator. The light water moderator can act to stop the nuclear reaction and shut the reactor down. This is known as a negative void coefficient of reactivity. The International Atomic Energy Agency (IAEA) lists 359 reactors in operation with a total generating capacity of 328-GW. Another 27 reac-

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tors are under construction. The light water reactor produces heat by controlled nuclear fission in the reactor core. Pencil-thin nuclear fuel rods of about 12 feet (3.7 m) long, are grouped by the hundreds in bundles called fuel assemblies. Inside each fuel rod there are pellets of uranium, or more commonly uranium oxide, which are stacked end to end. The control rods are filled with pellets of substances like hafnium or cadmium that can easily capture neutrons. As the control rods are lowered into the core, they absorb neutrons, which impedes the chain reaction. As the control rods are lifted out, more neutrons strike the uranium-235 or plutonium-239 in the fuel rods, and the chain reaction increases. The reactor core is enclosed in a waterfilled steel pressure vessel (the reactor vessel). In a boiling water reactor, the heat generated turns the water into steam, which directly drives the turbine generators. In a pressurized water reactor, the heat generated is transferred to a secondary loop using a heat exchanger. Steam is produced in the secondary loop which drives the turbines. After flowing through the turbines, the steam changes back to water in the condenser. The number of control rods inserted and the distance they are inserted is used to control the reactivity of the reactor. In PWR reactors, a soluble neutron absorber, such as boric acid, is added to the reactor coolant to allow the complete extraction of the control rods during stationary power operation to ensure an even power and flux distribution over the entire core. In the BWR design, the coolant flow through the core is used to control reactivity by varying the speed of the reactor recirculation pumps. Many other reactors are also light water cooled, notably the RBMK and some military plutonium production reactors. These are not regarded as LWRs, since they are moderated by graphite, and their nuclear characteristics are very different. Although the coolant flow rate in commercial PWRs is constant, it is not in nuclear reactors used on U.S. Navy ships. The light water reactor uses uranium 235 as a fuel, enriched to approximately 3 percent. Although this is its major fuel, the uranium 238 atoms also contribute to the fission process by converting to plutonium 239 and about half of this is consumed in the reactor. Light-water reactors are generally refueled every 12 to 18 months, when about 25 percent of the fuel is replaced. The enriched uranium is converted into uranium dioxide powder in pellet form. The pellets are stacked in tubes of metal alloy called fuel rods. The tubes are assembled into bundles which are given a unique


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identification number, which allows them to be tracked from manufacture through use and into disposal. In a pressurized water reactor the tubes are about 1-cm in diameter. There are several hundred fuel rods per fuel bundle and 150 fuel bundles in a reactor core. The bundles are about 4 meters in length. In pressurized water reactors the coolant water is used as a moderator by letting the neutrons undergo multiple collisions with light hydrogen atoms in the water, losing speed in the process. The use of water as a moderator is an important safety feature of PWRs, since any increase in temperature causes the water to expand and become less dense, reducing the amount that neutrons are slowed down and reducing the reactivity in the reactor. As the reactivity increases, the reduced moderation of neutrons will cause the chain reaction to slow down, producing less heat. This is known as the negative temperature coefficient of reactivity, which makes PWR reactors very stable. If a loss of coolant occurs, the moderator is also lost and the reaction stops. Advances in nuclear technology may provide energy from thorium which is the most energy-dense substance on Earth and enough exists to power civilization for millennia. All current commercial nuclear power reactors depend primarily on uranium-235 or the resulting reprocessed plutonium as their fuel. Another nuclear fuel is uranium-233 derived from naturally occurring thorium. Thorium is a slightly radioactive metal in the Earth’s crust, four times as plentiful as uranium. In a nuclear reactor thorium- 232 is transformed by neutron capture and natural decay into uranium-233, which undergoes fission in the same reactor to provide heat and power. The machine to extract that energy is the liquid-fluoride thorium reactor (LFTR). In conventional reactors 3/4th of the associated CO2 emissions are from coal-fired power plants that supply power to uranium enrichment facilities. Thorium does not require enrichment so the thorium fuel cycle provides a 75% decrease in CO2 emissions from the uranium fuel cycle. Thorium is already mined at uranium mines, rare earth mines, and phosphate mines. LFTRs are stable with passive safety features that automatically dump the core into holding tanks in the event of an emergency. Advanced nuclear designs with the use of common low-cost materials provide a major route to CO2 mitigation during the next 40 years. What is required is a political and social commitment to advanced nuclear technology. India alone among nuclear capable nations has made that

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commitment. The U.S. has, in contrast, followed a nuclear policy shaped by nearsightedness and fear. MITIGATION TRENDS One scheme for climate change mitigation proposes that if transportation technology remains about the same, we could use 16 trillion mirrors to offset emissions. This assumes that the planet is experiencing global warming and that warming is being exacerbated by human activity. The mirrors represent one way that the world could react quickly enough to avert any cataclysm if the global economy cannot be moved away from oil, coal, and natural gas. Climate scientists are actively using computer simulations to examine other possible contingency plans. One is an artificial haze of sulfur particles, which would reflect solar radiation to cool the planet. Based on the aftermath of a 1991 volcanic eruption, some scientists believe that adding reflective particulates to the upper atmosphere might provide a sunshade. This could cost $400 million per year to maintain and its less expensive than the scheme which proposed cooling the Earth by orbiting 16 trillion tiny solar mirrors at a cost of trillions. If one of these geo-engineering schemes were used without reducing greenhouse gas emissions, there could be more acidic oceans (since the oceans would continue to absorb excess carbon dioxide), disrupted rainfall patterns, and a drier planet overall. Even if such a scheme could temporarily abate global warming, there may be many unexpected consequences. The models indicate that if the system failed, the climate could heat up 10- to-20 times faster (as much as 7 degrees Fahrenheit per decade.) Even if human activities have nothing to do with global warming, we need to become more resource-efficient. China’s growth has pushed them to open a new coal-fired power plant every week. Their growing energy demand has made them a net importer of coal in spite of their extensive domestic reserves. The environmental impact of those coal operations may exceed the energy of the fuel that’s consumed. The American Association for the Advancement of Science estimates that the unintentional burning of coal from underground coal mine fires contributes significantly to carbon dioxide emissions and points out that as much as 3% of total world output might be due to these fires in China.


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The U.S. has massive coal reserves, but one report stated that building a 100,000-barrel-a-day coal-to-liquids facility could cost more than $12 billion while increasing U.S. auto and truck fuel efficiency by 10% could offset the output of ten of these plants. Also, there are millions of square feet of industrial space that continue to use inefficient lighting, HVAC, and motors. Buildings continue to be operated manually because the plant never gets around to allocating money for energy management systems. Aggressive growth in areas like Brazil, Russia, India, and China means that energy prices will most certainly rise. Improving energy efficiency should be portfolio-wide with no exceptions. This practice is both cleaner and greener which today means more profitability. References

“Carbon Trading: Revving UP.” The Economist, Volume 376, pp, 64-65, July 9, 2005. Cap and Trade 101, Center for American Progress, January 16, 2008. “Chicago Climate Exchange Prices,” Chicagoclimatex.com. 2009-08-04. http://www. chicagoclimatex.com/http://www.fossil.energy.gov/programs/powersystems/futuregen/futuregen_rod_071409.pdf http://www.iea.org/textbase/papers/2006/certainty_ambition. pdf Garnaut, Ross, The Garnaut Climate Change Review, Cambridge University Press, 2008. Jacoby, D.H. & A.D. Ellerman, “ The Safety Valve and Climate Policy, Energy Policy 32 (2004) 481ΓÇô49." http://www.sciencedirect.com. Montgomery, W.D., "Markets in Licenses and Efficient Pollution Control Programs," Journal of Economic Theory, Dec 1972, 395-”USEPA’s Clean Air Markets web site.” Epa.gov. http://www.epa.gov/airmarkets/ Montgomery, W. David, Markets in Licenses and Efficient Pollution Control Programs, Journal of Economic Theory, 1972, Volume 5, Number 3, pp. 395-418. Nordhause, William (2008). A Question of Balance: Weighing the Options on Global Warming Policies, Yale University Press. Stern, Nicholas, The Stern Review: The Economics of Climate Change, Cambridge University Press, 2007. Stern, Nicholas, A Blueprint for a Safer Planet: How to Manage Climate Change and Create a New Era of Progress and Prosperity, Vintage Press: U.K., 2009. http://www.iaea.org/NuclearPower/WCR/LWR/ http://www.euronuclear.org/info/encyclopedia/l/lightwaterreactor http://hyperphysics.phy-astr.gsu.edu/Hbase/NucEne/ligwat.html.

Chapter 7

Grid Integration and Transm ission Keywords: Feed-in Tariffs PV and Power Distribution Grid and Wind Power Reactive Power Control Large-scale PV Power Reliability Grid Stability Fixing the Grid

Virtual Utilities DC Transmission Smart Grids Home Grids Phasor Measurement Trends Advanced Grid Trends Smart Grid Vehicles

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here has been a lack of agreement on technical standards for grid interconnection, insurance requirements or equitable charges for the interconnection of distributed generation. Vendors of distributed generation equipment need to work to remove or reduce these barriers. In New York City, the Starwood Hotel chain had to overcome utility efforts to block the installation of a 250-kW molten carbonate fuel cell. The system represented only 10% of the hotel’s total power. These barriers can be described as the clash between distributed generation and the local utility. From the 1900s until 1980, U.S. utilities had total control over power lines. During the 1970s the Supreme Court ruled this was a violation of the Sherman Antitrust Act and in 1978, the federal government passed PURPA, but it failed to work in many states because it allowed the utilities to block renewable energy and cogeneration by announcing they did not need any more capacity. Then in the early 1980s, California and a few other states made utilities offer a Standard Offer Contract with fixed prices to all small power producers. But California discontinued the program in the 1990s. 227

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Since the mid-1990s, other states have mandated that utilities generate their own renewable energy or buy it from independents through competitive bidding. But utilities favored the bids from their own utility or affiliates. Most utilities have added only wind power. Many states tried deregulation but it has failed to encourage much competition because states allowed utilities to have too many advantages. In 2005, the U.S. Congress required FERC to study why competition failed, but the report was not used. Efforts in the early 2000s to reform deregulation by 2010 have also been lacking. FEED-IN TARIFFS The German federal feed-in tariff (FIT), uses simple fixed payments guaranteed over 20 years and has proven to be the world’s most effective policy for boosting adoption of renewable energy technologies. Any excess generation from a PV system will be exported onto the grid and if they get the superpeak $0.29/kWh FIT rate it may still be less than what solar PV needs at $0.30 kWh. The Sacramento Municipal Utility District (SMUD), which is the nation’s sixth largest publicly owned utility, approved the introduction of feed-in tariffs (FITs) for renewable energy. The utility voluntarily moved toward feed-in tariffs to boost renewable energy development. Utilities in Indiana and Michigan have proposed feed-in tariffs and the municipal utility in Gainesville, Florida, began offering a feed-in tariff in 2009. Feed-in tariffs have become increasingly popular. Using a standardized purchase offer, the FIT should streamline the time currently required to contract with power generators. For customers, the FIT provides an opportunity to sell power at fair market prices from small-scale generation units. The FIT also helps SMUD in meeting its goals for their Renewable Portfolio Standard (RPS) as well as greenhouse gas reduction. The program will apply to projects up to 5-MW and the overall program is capped at 100-MW. SMUD’s plan also includes fossil-fuel Combined Heat & Power (CHP) projects. Britain is also offering feed-in tariffs for CHP plants. SMUD’s program includes all renewables unlike the FIT program in Gainesville where the municipal utility has a highly successful feed-in tariff program for solar PV only. The specific tariffs planned by SMUD have an objective of developing a fair price for renewable energy.

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Like the tariffs determined by the California Pubic Utility Commission (PUC) for its feed-in tariff program, SMUD’s tariffs are based on the value of the power generation to SMUD. Also like the PUC’s program, the tariffs vary by time of day and season of the year. Early in the California PUC’s feed-in tariff program only 14-MW were installed while Gainesville, with a population of only 90,000, planned to install 4-MW in its first year. SMUD makes no differentiation between technologies, size, application, or resource intensity, unlike programs in Europe and Ontario, Canada. Payment under SMUD’s program requires a breakdown of hourby-hour generation and the probability of occurrence. The tariffs for a 20-year contract vary from $0.082/kWh to $0.29/kWh during superpeak hours. SMUD is also offering a bonus for the generation’s green value. The tariffs include the wholesale cost of power avoided plus the estimated greenhouse gas mitigation costs and the cost due to natural gas price volatility. For a 20-year contract, the greenhouse cost adder is $0.0111/kWh with a gas-price hedge of $0.0115/kWh for a total of $0.0227/kWh. The main features of the program include a program cap of 100MW with a project cap of 5-MW. Contract terms are 10, 15 or 20 years. SMUD raised the project size limit to 5-MW which indicates that they believe distributed generation projects can be seamlessly integrated into the distribution grid of California. This is higher than the limit of 1.5-MW in the PUC’s program. SMUD serves 1.4 million customers in the area of the state capitol which equates to a statewide equivalent of about 3,000MW. The PUC’s current program is limited to less than 500-MW while the California Solar Initiative (CSI) is limited to 3,000-MW of solar PV. SMUD’s feed-in tariff price structure has 216 different payment rates for the different seasons, times of day, contract lengths, and starting year. Individual projects will be subject to nine different rates that depend on time of day and season of the year. Critics say that tariffs should be cost-based to drive significant amounts of investment. Countries that have had success with feed-in tariffs base their prices on the actual costs of renewable energy generation. If FIT prices are not cost based, they may not attract enough capital. Markets in Germany and Spain with returns of 5-8 percent have been able to draw large amounts of investment. The average payment under the SMUD program for solar PV is expected to be about $0.17/kWh which may not be adequate to push solar

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project development. Gainesville Regional Utilities pays $0.32/kWh for a 20-year contract to a solar PV generator and Vermont is paying a tariff of $0.30/kWh for solar PV. Both programs base their tariffs on the cost of solar PV generation, not the theoretical value to the system. A potential problem occurs when the utility bases prices on the cost of wholesale markets, where regulated utility monopolies are often allowed to dump their excess power at low prices subsidized by the ratepayers. The FITs in Europe for solar PV led to higher prices as well as an increase in production, but when some of these support programs were cut back in Spain there was a large overproduction. If the pricing of tariffs is based on avoided cost, value-based tariffs, then the location of the generation facility becomes a factor. A power generator located near the edge of a grid can avoid significant line loss. Avoided cost in California tends to mean the avoided cost of operating a natural gas fired unit. Because of the price volatility of NG, prices can fluctuate going from 11 cents/kWh in 2008 to 5 cents/kWh in 2009. PV AND POWER DISTRIBUTION Photovoltaics (PV) could become a disruptive technological change in the electricity sector, just as personal computers and cell phones became in their industries, as they emerged from a centralized business product. Economic PV markets may not emerge in every state at the same time since solar resources, electricity costs and state policies will cause an uneven solar adoption making PV market growth state specific. California, New Jersey, and Colorado have been leading the states in installed PV. Utilities normally use 10- to 15-year integrated resource plans (IRPs) which forecast electricity demand and the necessary equipment. Most utilities will be planning for modest to significant PV growth over these time periods. There are technical and financial challenges for utilities associated with the adoption of net metering the demand-side of PV. The technical challenges involve efficient and safe interconnections for the thousands of new systems every year. This may include capturing new streams of data and integrating them into the billing system while managing areas of high PV penetration where peak production of the PV output during


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periods of low consumption might cause grid imbalances. The financial side of these challenges is that more people may purchase less power. But, that aspect of the utility business model is affected by total electricity consumption which fluctuates up and down due to the weather and the energy efficiency measures that consumers use. It also depends on new or replacement products that consume more or less electricity as well as changes in regional population growth and local economic conditions. Since utilities cover their costs and generate profits by selling electricity, if less is purchased, and if this continues to a larger and larger percentage of customers, a utility could, with current business models, in essence go bankrupt. Utilities manage a large amount of infrastructure that allows modern life. Net metering limitations may be imposed by utilities or regulators which limit the size of any one PV installation and/or the aggregate of PV systems in a utility’s region. This impacts PV market development and may dampen the movement to green power. The utility might also require a monthly fixed charge or fee which consumers pay regardless of their consumption levels. This would recover the utility’s fixed costs but it could raise or lower the amount consumers pay for each unit of electricity and not encourage the efficient use of electricity. Fuel clause adjustments would allow utilities to calculate or estimate how much revenue they lose and then ask regulators to reimburse them, which they already do for other programs. Decoupling is another policy, which reimburses utilities based on a metric other than electricity consumption, such as the number of customers, making the utility neutral to how much power is actually sold. Decoupling is being considered in many states and at the federal level. These policies are short- to medium-term fixes that seem incomplete for a future world where large numbers of homes or businesses may operate as small power units. This world requires a reappraisal of present utility business models and the related management of the grid infrastructure. THE GRID AND WIND POWER Wind power is being accommodated into electric power operations around the world. In Europe, Denmark receives over 20% of its electricity from wind energy and by 2007 Germany got about 7% of its electricity

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from the wind. Both Spain and Portugal had periods during that year when wind energy provided over 20% of their electricity. Spain set a single-day record when over 40% of its electricity coming from its wind farms. Wind peaks generated 9,862 megawatts of power which translated to 40.8 percent of total electricity demand. Spain’s wind power also equaled its hydropower in 2007. Wind power is supplying almost 50 billion kilowatt-hours (kWh) of electricity annually in the U.S., for the equivalent of over 4.5 million homes. Minnesota and Iowa both get close to 5% of their electricity from wind power which is becoming a valuable part of the utility generation mix. Wind energy provides a hedge against fuel price volatility associated with other forms of electric generation. When the wind is low, power output is maintained by turning up the output of other generators on the electric power system. System operators can control, or dispatch, generators on their system such as natural gas turbines to the electrical demand, or load, which varies over the course of the day. Wind behaves in a similar way to load in that it is variable and its output rises and falls. The wind generator output can be controlled to a limited extent. System operators also keep generation in reserve, called the operating reserves, which can be called on in case of a shortfall. Wind energy integrates effectively and reliably into power systems with regional market operations which mitigate the impact of wind variability. Storage systems are not needed to integrate wind energy into electric power systems. The power system inherently has storage in the form of hydro reservoirs, gas pipelines, gas storage facilities and coal stock piles that can provide energy when needed. Storing electricity is currently significantly more expensive than using dispatchable generation. In the future, advances in technologies such as batteries and compressed air may make energy storage more costeffective. The expectation of plug-in hybrid electric vehicles holds some promise since the vehicle batteries could provide storage for the power system. Conventional resources occasionally shut down with no notice and these forced outages require operating reserves. A utility that has 1,000 megawatt nuclear or coal plants will typically keep 1,000 megawatts of other generation available, to be ready to quickly supply electricity if a plant unexpectedly shuts down. The geographic diversity of wind energy helps to even out the variability of wind energy. Also, wind farms usually contain many individual


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turbines, which reduces the impact of outages. There may be 60 or 70 1.5MW turbines at a typical wind farm, so if one is down for maintenance only about 1.5% of the total wind farm’s generating capacity is lost. Changes in wind energy output are not immediate, because of the geographic diversity found with large numbers of wind turbine installations, it typically takes over an hour for even a rapid change in wind speeds to shut down a large amount of wind generation. Wind forecasting tools that warn system operators of major wind output variations are becoming more widely used and better integrated into system operations. Because of wind energy’s variability, some incremental generation may be required for system balancing. This can add to the cost of service. These costs include keeping the generators available. System operating cost increases from wind variability and uncertainty amount to about 10% of the wholesale value of the wind energy. REACTIVE POWER CONTROL In wind power applications, grid line voltage regulation can be a problem. Weak grids, coupled with wind gust fluctuations, lightning strikes or physical interference to overhead lines can cause momentary dips in voltage. This results in fluctuating grid voltage and wind turbines that continuously trip offline which creates greater voltage fluctuations and lost generation. Until recently, most wind power plant operators and utilities used capacitors to correct the power factor to near unity. But, these systems are slow and unable to provide fine, continuous control, they cannot react to the sudden momentary dips in voltage commonly seen in weak grid or gusty wind conditions. This strains the utility grid. Some wind projects use static VAR compensators or similar apparatus, but these methods tend to be expensive and complex. GE has its WindVAR electronics system where the voltage is controlled and regulated in real-time similar to conventional utility generators. The system supplies reactive power to the grid at the time it is needed, regulating the system voltage and stabilizing weak grids. This ability to supply reactive power to the grid allows wind power in areas where weak rural distribution systems had discouraged new wind applications. The system can also provide emergency backup support to weak grids in need of transmission and distribution improvements. Variable speed technol-

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ogy is used to reduce torque transients and increase the blades’ ability to capture more of the energy in the wind. A voltage controller measures the line voltage and provides the reactive power needed to bring the line voltage back to the desired range. To reach the desired voltage level at the substation, the controller communicates the reactive power requirement to each of the system’s wind turbines using a distributed control network. Each wind turbine’s power processor excites the generator to produce the correct power factor. As the power factor changes, the line voltage moves to the desired voltage level, forming a closed-loop voltage control system. At the Department of Energy and the Electric Power Research Institute’s Turbine Verification Program in Algona, Iowa, three of these wind turbines, installed 6.5 miles from a 69/13.8-kV 10-MVA substation without voltage rise or flicker problems. More than 2,000 of these units now operate around the world. LARGE-SCALE PV In the past, solar photovoltaic (PV) installations were mainly done in a piecemeal fashion, usually planned and implemented as a rooftop or ground-mounted system, but as solar technology has improved and as governments push for more renewable generation, large-scale projects are becoming more common. A growing number of utilities have launched major solar projects. Duke Energy is one of the largest power companies in the U.S. It is spending $50 million to install 10 megawatts worth of solar PV systems in North Carolina. The initial plan was double this amount, but the North Carolina Utilities Commission Public Staff, which acts as a consumer advocate, asked for a reduction out of concern that the proposal was too aggressive and expensive. The solar systems will be owned and operated by the utility and will be installed on the roofs and grounds of homes, schools, office buildings, warehouses, shopping malls and industrial plants. Between 100 and 400 separate arrays will be installed. They will range from about 2.5 kilowatts on residential rooftops to more than 1 megawatt (MW) on open land or on the rooftops of large commercial buildings. The power will be fed into the electrical grid and participants will be paid for use of their roofs or land, based on the size of the installation and the amount of electricity generated at the site.


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North Carolina’s renewable portfolio standard requires the utility to satisfy 12.5 percent of its customers power needs with renewables or energy efficiency by 2021. A growing portion of the renewable goal is to be met with solar energy, starting at 0.02 percent of the total electricity sold in 2010 and rising to 0.2 percent by 2018. Duke believed that distributed generation would grow as customers make these investments on their own, but they felt that they needed to understand the impact of distributed generation on the grid. Rooftop arrays in large numbers concentrated in one area could lead to imbalances on a circuit. Data from the 10-MW project will give the power company an understanding of the limits of its network and help to avoid potential problems. Since solar arrays are placed closer to the demand, the grid should become more robust. U.S. utilities plan to build more than 800-MW of solar installations that they would own and operate. Southern California Edison will spend $875 million to build 250-MW of PV power generation on 65 million square feet of rooftops in southern California. Pacific Gas & Electric (PG&E) will build 250-MW of distributed PV installations, largely on ground-mounted systems. They choose to own and operate the projects because they view it as less risky than buying from a third party and because they believe they can build them at lower costs. Since utilities are regulated and have predictable revenues, they can raise financing at better rates than most businesses. In large projects, better funding results in significant dollar savings. Duke plans on an average installation price of $5 per watt for silicon and thin-film modules. The silicon systems will be used for residential projects while the less expensive and less efficient thin-film will be used for ground-mounted and large commercial rooftop installations. All the systems will be fixed with no trackers being used. Duke does not plan on using concentrating technology with mirrors. PG&E also added utility-scale solar projects to its power mix. The San Francisco based Pacific Gas and Electric has agreements with two developers of utility-scale photovoltaic solar power, Cleantech America LLC and GreenVolts Inc. This will provide up to seven megawatts (MW) of utility-scale solar energy for PG&E’s customers throughout Northern and Central California. The solar power plants are located in close proximity to PG&E’s infrastructure and customer base to reduce transmission costs. Cleantech America’s CalRENEW-1 project is located near PG&E’s Mendota substa-

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tion in Fresno County. It provides PG&E with five megawatts of peak energy. The 40 acre project will provide energy at the hottest times of the day during the hottest months in central California. The GreenVolts GV1 solar plant is on eight acres in Tracy, California. It will provide PG&E customers with an additional two megawatts of renewable power. The two agreements are part of PG&E’s broader renewable energy portfolio. California’s Renewable Portfolio Standard (RPS) program required each utility to increase its procurement of eligible renewable generating resources by one percent of load per year to achieve a twenty percent renewables goal by 2010. The RPS Program is managed by California’s Public Commission and Energy Commission. POWER RELIABILITY The North American Electric Transmission is constrained, and pushing it beyond its physical limitations causes reliability problems. The actual capacity available is a function of the lines and network. When the network limits are pushed, thermal overloads can occur along with voltages out of proper ranges and there may be instability from generators losing synchronization. U.S. utility networks were designed to deliver generated power to nearby population and load centers and not across large trans-continental distances. The average network capability distance for U.S. utilities is about 200 miles. In the United Kingdom, competition in electricity supply was introduced years ago and power suppliers in the U.K. have an average network capability distance of 600 miles. In the British Isles, the longest distance between generation and load is only one-fifth of that in the U.S. Also, there are more than 3000 independent utilities in the transmission system in North America, but in the U.K., deregulation required the breakup of just one state-owned utility. Building a super grid in North America would require a massive construction program and that would have to be factored into the price of electricity. The transmission system was erected in an era of vertical integration and was never meant to handle the loads of an unbundled electricity sector, where power producers supply bulk electricity to the highest bidders. Transmission will require immense investment in the coming years in order to maintain system-wide reliability. But, invest-


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ments in transmission facilities have gradually declined over the last 20 years. Innovation is needed at the distribution level of utility service. Cutting edge distributed generation sources could be integrated into grids to address the challenges posed by the current electricity infrastructure. A few summers ago, millions of people in developed countries were in darkness. In August, the lights across much of eastern North America went out. Two weeks later, London suffered a brief power cut during rush hour. Then, parts of Scandinavia lost power. Then, in September, most of Italy lost power. Power cuts are a part of life in the developing world, but in the developed world blackouts are thought to be rare. Small power cuts have always been with us, especially outside metropolitan areas. English villages often lose power during winter storms. According to the Electric Power Research Institute, every day half a million Americans may lose power for over two hours which costs the economy $100 billion a year. A power outage in 1965 hit New York hard when the Niagara power grid dropped out during the rush hour on November 9. At about 5:15 p.m. the power lines that connect Niagara Falls and New York City exceeded their maximum load causing a transmission relay to fail and started a chain of events that cut power to more than 25 million people in eight states and two provinces. The power that had been heading for New York took an alternate route to the power grid that feeds New England. The ensuing overload caused the entire grid to collapse placing most of the northeast in darkness. Within minutes, utilities diverted their power northward, causing a shutdown of the grids in Ontario and Quebec. The situation became critical in New York, where the airports had no power, traffic lights were out and people were trapped in highrises and in subway cars. As a result of what was called the Great Northeast Blackout, power utilities across the U.S. instituted fail-safe systems to blackout small areas out to save larger portions of the grid. Many thought the problem was solved, but it was to occur 12 years later. The 1977 New York blackout took on a different path compared to the 1965 outage. At 9:34 p.m. on July 13, 1977, during a mid-summer heat wave, power went out in New York City, plunging nine million people into darkness. While the atmosphere in 1965 was civil, in 1977 it became violent. Within a few hours, the city was aflame, as people in the Bronx and Brooklyn rioted. Police arrested 4,000 people for the looting and pillaging of more than 2,000 stores. Firefighters responded to more than

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1,000 incidents and many of these were deliberately set. In 1989, Quebec had its own crisis as sunspots caused Hydro-Quebec’s power grid to switch off at 2:45 a.m. on March 13, cutting six million people off from the power grid. Nine hours later, the power was restored. In the great Northeast blackout some thought it was due to a terrorist attack. Manhattan subway trains came to a stop, stranding hundreds of thousands. Toronto went dark along with Rochester, Boston, New York and other cities. In less than 15 minutes, the computer-controlled power grid of the 80,000-square-mile Canada/United States Eastern Interconnection area went down. The lights were out for 50 million people in the U.S. and Canada. General Motors was forced to shut down 17 of its 60 North American plants and Ford closed 23 plants out of 44. The lost business was estimated at $1 billion. As power returned, attention focused on overloaded transmission lines around the Lake Erie Loop. Automated protective devices quickly shut down generating plants and distribution networks across more than a 9,000-square-mile area. About an hour before the main collapse, a section of the system in Ohio experienced problems and took itself off the grid. About 30 minutes later, a second section in Ohio also dropped off the main grid. Events inside the automated and computer-driven power system cascaded too quickly and there was not enough time for operators to react. The event took place in nine seconds according to the North American Electric Reliability Council, (NERC) a private, standards-setting organization that monitors the transmission system. Even after electrical service had been restored to New York City and most of the blacked-out areas of the East Coast, the upper Midwest and southern Canada continued to suffer. New York’s subway system slowly resumed service, but airline schedules were impacted and thousands of passengers were stranded. Officials in Detroit and Cleveland urged residents to boil drinking water because of possible contamination. Some also warned that further rolling blackouts may occur before the system returned to normal in perhaps a week. President Bush described the blackout as a wake-up call for the reform of an antiquated system. The White House announced the formation of a U.S./Canada task force to probe the cause of the outage. The inquiry centered on the Lake Erie loop which is a transmission path for the power that goes along the southern shore of the lake from New York


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west to Detroit, then up into Canada and back east to the Niagara area. This loop has been known to be a problem for years. There have been plans to make it more reliable but little was done. Much of the power moving east from the Detroit area to New York would usually move through Canada. Shortly before the power failure, 300 megawatts of power were moving east, but the flow suddenly reversed itself with 500 megawatts going the other way. Such reversals in the flow of power around Lake Erie can cause transmission and generation problems in New York. The power system requires all its parts running at the same rate and the Lake Erie incident can cause transmission shutdowns in New York, which in turn can cause generation problems. The events tend to feed on themselves. Several transmission lines in Ohio went out of operation before the blackout. One system went down an hour before the main crash, and the other a half-hour before. These shutdowns may have triggered the problems around Lake Erie. The Ohio lines are owned by FirstEnergy which is the nation’s fourth-largest utility. The initial problems may have been the result of operator errors or a shortcoming in procedures, exacerbated by the failure of an alarm at FirstEnergy to signal the start of a fast-spreading event. The failed line in Ohio began a cascade that brought down 100 power plants including 22 nuclear plants in the U.S. and Canada as 8 states and 2 Canadian provinces experienced failures. In the winter of 2001 California shut off the power due to massive power consumption by consumers and winter storms. These conditions forced California into a Stage 3 power alert, where random blackouts throughout the state are used to conserve power. Stage 3 blackouts affect businesses and residential areas alike where only vital services like hospitals, police, fire and air traffic control are exempt from the blackouts. Up to two million residents faced the rolling blackouts, which can last as long as four hours. The San Francisco/San Jose area was the hardest hit. Some blamed the increase of technology companies and their 24-hour server farms but power officials said the problem came from excessive residential use, not businesses. If families had used one-third less power, it would have dropped almost 5,000 megawatts off the grid and eliminated the blackouts according to the California Independent System Operator. Cal-ISO manages the California power grid and controls about 75% of the power in the state. The state had been facing power problems for weeks, but it was made worse by a winter storm that brought rain and snow to the state.

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The Diablo Canyon nuclear power plant in San Luis Obispo County was cut to only 20% efficiency. Much of the problem is due to the large amount of power needed in and around San Francisco and the surrounding area. Cal-ISO could not get enough power from the southern part of the state to the north. The main route for this power, Path 15, is congested. For about a 100-mile stretch, the grid shrinks, which is like going from a four-lane to a two-lane highway. In the summer of 2002 there were triple-digit temperatures in California which pushed the state’s energy reserves to their lowest level in a year and sent the state into a one-day Stage 2 emergency. Despite rolling blackouts and increasing wholesale electricity prices, air conditioners continued to run during the first intense heat of the year. The peak demand reached 42,441 megawatts, the highest of the year, according to the California Independent System Operator. It had been about a year since the last rotating outage. The state had been improving power supply margins with new power generation and emergency energy conservation measures. New power plants and improved hydroelectric production helped and over a period of 18 months California increased its power supply by almost 4,500 megawatts. Consumers helped by installing thousands of new, more efficient appliances and millions of energy-efficient light bulbs. Due to conservation measures, California’s larger power customers used about 500 fewer megawatts during the summer. This is the equivalent of the output from a mid-sized natural gas power plant. A real-time metering program allowed large utility customers such as chain stores, hospitals, office buildings and schools to monitor their hourly energy use on the internet and in real-time to control their energy costs. Some municipal utilities made voluntary real-time rates available, where electricity is priced based on the wholesale market. This allowed customers to adjust their production schedules according to the current electricity pricing. The Energy Commission estimated that these meters resulted in reducing peak electric demand by 600 megawatts per year. The cost for implementing real-time electricity meters is approximately $65 per kilowatt. The cost for typical peaking power plants using combustion gas turbine technology are several thousands of dollars per kilowatt. B u i l d ing energy management systems (EMS) also play an important role in demand response programs used by utilities to keep peak electric power


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usage low. A building energy management system allows utility customers to identify and program energy-consuming equipment and systems to shed loads as needed. Although the power plants and hydropower have helped to increase the supply and conservation programs have helped stiffen the grid, California’s energy supply remains vulnerable. Typically, the state’s energy load has climbed every year by a few percentage points. Although loads have dropped below expectations a few summers, economic conditions and conservation efforts have influenced the demand for energy. Loads have increased and regional heat waves tend to thin reserve margins in the west. California has been unable to import electricity from other states in the same amounts as in earlier years. To prevent another power crisis, California is asking utility customers to conserve some 3,000 megawatts of electricity in the summer. Programs like real-time metering are expected to provide over 1,200 megawatts and consumers and businesses must provide the remaining 1,800 megawatts. The California ISO has been asking consumers to reduce power use in peak periods, between 3 and 6 p.m. These periods will probably occur for a few hours on the hottest days of the year when air conditioners are running in large areas of the state. Prior to the 2003 blackout, state and local officials took the necessary steps to be prepared for massive emergencies. In New York, the night of August 14, 2003 was a graphic contrast from previous outages. There were no riots like those that crippled the city in the blackout of 1977. Officials recorded 800 elevator rescues, 80,000 calls to 911 and 5,000 emergency medical service calls. The problem that led to the blackout originated somewhere in northeastern Ohio. The Ohio lines were operated by First Energy, a transmission company based in Akron, Ohio. First Energy confirmed that their facilities in northern Ohio had suffered several mishaps during the afternoon prior to the blackout. These included a tree falling on one of the company’s heavy-duty 345-kilovolt high-tension lines and tripping off a generator at a company plant in Eastlake, Ohio. Another 345-kv line may have been so overloaded that it sagged into a lower-voltage cable below it, shorting out the circuit. But, First Energy believed its equipment had coped with these failures, which were not that unusual on a warm summer day. On August 13, 2003 at 3:06 p.m. the first of three transmission lines that are believed to have triggered the blackout triple off. The outage put

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pressure on another line and in Cleveland the voltage drops to zero. An hour later, utilities in Canada and the Northeast experience major power swings. The Bruce Nuclear Station in Ontario shuts down and blackouts hit Toronto and southern Ontario, where most of the province’s 10 million residents live. A few minutes later the Campbell No. 3 coal-fired power plant near Grand Haven, MI, trips off and then the Enrico Fermi nuclear plant near Detroit shuts down automatically after losing power. A number of transmission lines trip at this time including a 345-kilovolt line in upstate New York and Vermont. In New England the region’s power operator disconnects its system from New York’s after realizing something is wrong. A transmission line between Pennsylvania and Toledo, Ohio, trips off and in 15 minutes five nuclear power plants in New York state shut down. Parts of nine states including all of New York City are now affected. Restoring power to a massive area requires utilities to balance electricity coming from the restarted plants with load demands. An imbalance can trigger more blackouts. Supplementary power sources called black starters are used to re-engage the generators and get auxiliary systems online. Once the generators are up, they could flood the grid with too much power and shut it down again if there are not enough substations online to draw power. At the substations, operators must control the power distribution and gradually send more power to areas that need it. As new power plants are connected to the grid, those that are already up and running must drop back their output to stabilize the system. Essential facilities and services are the first to get their power back. These include hospitals, police and fire departments, water and sewagetreatment plants. As areas are brought up, they are connected with other nearby regions. This merging can cause destablizing fluctuations for a while. By 10 p.m. on the day of the 2003 blackout, 50% of affected areas in New England had their power restored. By 5 a.m. the next day, 50% of Canadian areas were back online. New York was fully restored by 10:30 p.m. Most power-cuts remain local while some recent black-outs grew much larger. Many start with storms as tree branches fall on high-voltage power lines. Another factor is safety equipment that does not work or that was installed improperly as happened in Britain. In some cases human error


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or inaction may have made natural accidents worse turning local problems into regional ones. Many blame utilities and regulators that neglected transmission and generation systems. GRID STABILITY Stability is a property of a system that is disturbed and returns to its original condition. In a power distribution system consisting of transmission lines connected together with two or more generators, the rotors of the generators rotate at a constant speed and are in step as a normal condition. When a fault occurs on one of the lines, the generator closest to the fault will supply the largest portion of the fault current while the other generators supply smaller parts of the current depending on their distance from the fault. The sudden load on the generators will cause them to slow down but not equally. The generator closest to the fault will slow down more than the others and the generators will no longer be in step. The governors connected to the generators will attempt to bring the generators back to normal speed. There will be an angular displacement or difference between the rotors of the generators. The rotor of the generator that has slowed the most will attempt to return to normal while the rotors of the other generators may have already returned to normal speed. The generators will tend to slow down as the load on them is reduced with the slowest generator picking up load. This causes a rocking motion to take place on the rotors. As the fault is removed by taking out of service the line section on which it is located, the rocking motion will decrease and the generators will get back into step. If the fault persists, other generators will try to pick up the load and may fall out of step until a complete shutdown occurs. If the fault is removed quickly enough, the rocking motion will decrease as the generators return in step to their original condition. The system except for the faulted section out of service then returns to normal. Overhead transmission lines employ large conductors that may be made of stranded copper conductor or aluminum conductor steel reinforced (ACSR). The conductors must have enough mechanical strength to support long spans under normal conditions and also under the conditions of ice and wind loading. In ACSR conductors, the steel core is

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considered as taking all the mechanical tension. The AC resistance varies with the amount of alternating current flowing, but it is often determined for a current density of 600 amperes per square inch. There is an increase in the AC resistance due to the skin effect eddies which increases as the diameter of the conductor increases. The skin effect for an ACSR conductor is generally greater. The voltage of transmission lines is generally 500 to 1000 volts per mile of the line. In the United States, the operating voltage increased quickly. In 1890, the Willamette-Portland line in Oregon operated at 3,300 volts. By 1907, a line was operating at 100-kv and in 1913 the voltage rose to 150-kv. In 1926, the voltage was 244-kv. By 1953, lines operating at 345kv were being constructed. The power that can be safely transmitted over a transmission line at a specified voltage varies inversely with the length of the transmission line. The cost of the transmission line increases directly with its length so that the cost per kW transmitted increases more rapidly than the first power of the length of the line. In long-distance alternating current transmission one or more intermediate synchronous condensers are normally used. They allow the transmission of more power over a given transmission line or system at a specified voltage, resulting in a lower cost per kW transmitted. The reliability of the transmission system is also improved since an intermediate synchronous condenser also aids the stability of a transmission system. Transmission lines supply power in large blocks to load centers. This power may originate from several generating stations and other sources that may be part of a large power pool or grid. When a fault occurs on a transmission line that supplies power to a load that has other sources of power supply, that line will be removed from service and the load served from other sources. Each of the other sources may have to increase its output to take care of the loss of supply from the faulted line. In some cases, the other sources may not be capable of the sudden increase in demand so a part of the load may have to be dropped to prevent the complete loss of all of the load. To maintain a high degree of continuity of service, the system is usually designed so with the loss of the largest source of supply, the rest of the system is capable of picking up the load. It is desirable to have power transmitted from a generating station over more than one transmission line in order to provide the continuity of service desired. These transmission lines from a source are often operated in parallel.


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The important operating connections employed in transmission lines include the line step-up and step-down transformers and the high voltage circuit breakers. It is not economical to generate voltages much higher than about 20,000 volts. The power is generated at medium voltages and stepped up by transformers to several hundreds of thousands of volts. At the end of the transmission line, transformers step the voltage down to the distribution voltage which may be as high as 70,000 volts. The distribution transformers then step this voltage down to the distribution voltage which is usually 2300 in suburban communities. In larger communities, the distribution may be done in underground cables at voltages of 6600, 13,200 or 26,400 although higher voltages are also used. Power may be sent 10 or 20 miles at these voltages, although they are not classed as transmission line voltages. For amounts of power greater than 25,000-kW, the voltage used increases directly with the distance involved. This voltage is 500 to 1000 volts per mile so a line of 150 miles would be designed to use 100,000 to 150,000 volts. The transmission system includes the high voltage buses and structures along with the generators and their controls and also the receiver synchronous condensers. For the continuity of service, the source should have enough capacity to immediately pick up the load being carried by the line which may be removed from service. When there is more than one source, the sources remaining in operation may pick up parts of the load and the remaining capacity of each source and associated transmission line may become smaller. The alternating current electric system is essentially a constant speed system where the speed is controlled within very narrow limits. The governors for the generators operate to keep the machines rotating within these limits. If an increase in load occurs on the electrical system, the governor does not start to operate until a small but definite increase or decrease in speed has occurred. In general, the speed will increase or decrease still further before the governor’s action on throttle mechanisms operates sufficiently to balance the increase or decrease in the electrical load. Up to the time that the balance is obtained, the electrical output or input may be greater or lesser than the input to the prime mover. Transient operation following a switching operation follows a set sequence. When a generating system is supplying a load through two paralleled transmission lines and a receiver end condenser is operating, the operating angle between sending end and receiver end low voltage buses may be about 10 degrees. If one transmission line with its trans-

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formers is suddenly removed from service, then the speed of the generators should increase. Part of the load is initially supplied by the stored kinetic energy in the rotor of the condenser which begins to drop back in phase angle. The generator rotor begins to advance in phase angle until the electrical power output of the generator is equal to that of the load. At this point, the rotor of the condenser is running at a slightly slower speed than the rotor of the generator, and the condenser rotor drops farther behind in phase angle and the line transmits more power than required by the load. The excess power transmitted becomes available to increase the speed of the condenser rotor back to that of the generator. When this is accomplished, the speed of the two machines is equal but the power output of the line is greater than the load requires and the condenser rotor is accelerated until it reaches a new normal steady state operating angle. But, it is moving faster than it should be and it will move to a lower operating angle where the power output of the line is less than that required by load. A switching operation that removes one line from service produces a large increase in load on the line remaining in service and produces electrical-mechanical oscillations between synchronous machine rotors at each end of the system until these oscillations are damped out. A small percent change in speed is produced during the oscillation which shows an electrical system under transient operation which is readjusting itself to a new steady state operating condition. There is almost a constant power input through each prime mover during the initial stages of the transient operation. The governors on the prime movers do not act until after the worst portion of the transient operation is over. If a three-phase fault should occur, during the time the fault is on the transmission system, it will reduce the line voltage at the fault to zero and prevent all power from being transmitted between the generators and the load. The time of clearing of a fault may be less than ten cycles on a 60 cycle system or less than 0.2 seconds. If the line was operating at full load, the power available during the time of fault can accelerate the rotating parts of the prime movers and generators above synchronous speed. At the time of fault, the condensers act as generators and supply power to the load as well as to the fault. This causes a decrease in the stored kinetic energy in the rotor of the condensers causing them to slow down. The generators at the sending end of the system are accelerating while the synchronous condensers at the receiving end are decelerating. Both effects produce an increase in the operating angle between internal machine voltages. As the fault is cleared, the


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operating angle between machine rotors increases. If the operating angle should increase beyond 90°, the maximum power output of the transmission system is reached and the system will pull out of step. The machines normally do not lose synchronism during the fault, if it is cleared in a reasonable time by automatic breakers and relays, but the difference in angular velocity acquired during the fault is often sufficient to cause the machines to pull out of step after the fault is cleared. If the machines do not lose synchronism at the end of the first half cycle of the oscillation, then they will probably not fall out of synchronism, because during the next cycle there is more time for the voltage regulation to increase the transient internal voltage and the oscillations are being damped out by losses in the field circuit. Damper windings are used by synchronous condensers while other machines use an approximate equivalent in the solid rotor and metal wedges in their construction. These winding make the damping effect more rapid. The protection of transmission systems from faults must be accomplished by removing the fault as quickly as possible. The usual technique involves high speed circuit breakers actuated by relays. The circuit breakers usually operate in oil. Smaller sizes operate in air. In some air breakers the arc that forms when the contacts separate is controlled by the magnetic field into a series of small gaps. These gaps aid deionization and extinguish the arc quickly. In some types of circuit breakers, compressed air is used to extinguish the arc. In oil circuit breakers, the mechanism is immersed in an oil similar to transformer oil. When the circuit is opened and an arc forms, some oil is vaporized and a pressure is built up. The pressure of the oil helps to extinguish the arc. Some circuit breakers are mounted in the same oil with the transformer. The relaying of faults depends on the types of relays used. These include overcurrent and directional overcurrent relays as well as pilot systems. These types of relays are not used for the protection of long single lines or loop systems. Here, distance relays are employed. They compare the voltages and currents during a fault which are a function of the circuit constants between the relay and the fault along with the distance to the fault. During a short circuit the current flow in the affected conductors is greater than the load currents. This difference allows the relay to discriminate between loads and faults. The fault current will depend on the fault location, type of fault, connections and amount of generating capacity.

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The measurement of fault current alone does not determine the location of the fault. A system can be sectionalized with relays set to operate on a minimum fault current for a fault in that section. To prevent tripping of corresponding breakers, time delays are used in the operation of the relays. The time delay increases as the source is approached so that the breaker nearest the fault clears before other relays operate. When fault currents can flow on either side of a bus, a direction element is used which allows the relay to trip when only current is flowing away from the bus. An inertia factor affects the time required to clear a fault. This is the ratio of stored kinetic energy in the machine rotors at the sending end to the stored kinetic energy in the prime movers at the sending end. In a water wheel generator, the allowable time for clearing a fault varies from about 0.04 to 0.14 seconds. This takes about 2.5 to 8.7 cycles. A large moment of inertia is present in water wheel generators. Steam turbo-generators run at a higher speed and have a higher amount of stored kinetic energy. A transmission system using steam turbo-generators will have an inertia factor of about 10-12 and the allowable time for clearing the fault of more than twice the time if the generators were water wheel machines having factors of about 3. Circuit breakers and relays are designed to provide a high speed interruption which improves the stability. A total relay and circuit breaker time of less than three cycles is typical. This is improved with newer electronic relays. When several breakers are in series, the cascaded time settings require that the relays nearest the generators have longer time delays. When more than a single source of supply is connected to the system, especially in a ring bus system, the appropriate time settings must be calculated. The short circuit currents which exist under the known circuit conditions are calculated by the method of symmetrical components and the currents through each of the relays determined from these calculations. Differential protection is used for protecting generators, transformers and bus structures from internal faults. The vector sum of all of the currents in each phase, flowing out of the equipment being protected, is sensed by the relay. If the currents in the relays are not at the same voltage base, as is the case for transformers, they are brought to the same base by current or auxiliary transformers in the relay circuits. In some cases, the relay itself is used.


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For generators, the vector sum of the currents flowing out of each phase winding is sensed by the relay. For transformers the vector sum of the currents in each winding on the core, after correction in instrument transformer circuits is sensed by the relay currents on a common voltage base. The vector sum of all the currents in each phase of each line connecting to a bus is sensed by the relay. Under normal conditions and for faults outside the equipment being protected, the vector sums should always be zero. When a fault occurs in the equipment, a current should flow which is not included in the vector sum. In transformers, a fault between turns of a winding will change the effective transformer ratio making the sum no longer zero and a current flows through the relay. The relays are given the most sensitive setting which will not cause operation for faults outside the apparatus. The main causes of faulty operation are saturation in current transformers from high values of current, and transformer energizing transients, which cause currents to flow momentarily in the winding which has just been energized. When differential protection is used for polyphase transformer banks with delta connected windings, the current transformers are inserted in the leads of the individual transformers before the delta is closed. Pilot protection is used in transmission lines where the ends of the circuit are some distance apart. Auxiliary circuits using pilot wires are employed to obtain the vector sum. Pilot protection involves the simultaneous opening of circuit breakers at the terminals of transmission lines using the pilot wires as a communication link between the circuit breakers. These physically separate pilot wires are connected in various ways. In the circulating current pilot wire technique, current transformers are used for sensing the load currents and fault currents which circulate over the pilot wires. This technique is also used with current balancing relays. Another scheme uses pilot wires with percentage differential relays. The directional comparison pilot wire scheme uses direct current over a pair of wires with polyphase directional relays. The link may also use the transmission line conductors themselves with a very high frequency current superimposed on the line. The carrier current signal operates the relays to keep the circuit breakers closed. A fault on the line interrupts the signal and opens the breakers, causing the line to fail safe. Pilot systems also use radio signals with microwave channels operating from relay stations located in a line-of-sight along the route

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of the transmission line. The relays operate to de-energize the line in the same fail safe manner. Balance current protection involves the difference of corresponding currents in two similar parallel lines. As long as the lines are alike, the relay current is zero. A fault on one of the lines will cause a difference in the two lines and unbalances the currents unless the fault is near the far end. In this case, relays at the distant end will operate to open the breaker in the faulted line. Then, a difference in current occurs at the near end, since the lines are no longer tied together at the far end. FIXING THE GRID The blackouts in America and Europe are indications of shrinking margins of production and transmission capacity. In today’s markets, regulators have found the best way to achieve adequate reserve margins without damaging the incentives they are trying to bring about. To many Americans, these vast blackouts seem hard to explain. But, over the years of restructuring regional power, companies have merged their generation capacity to become part of large infrastructures. A power sharing network stretches from Florida to Canada and acts much like a single electrical circuit. Electrical grids in Canada and the United States, link up at 37 major points so the two countries can trade power. When one utility has a shortage, it buys power from a neighboring utility. But, this overworked network also has a very old transmission grid of underground and overhead power lines that were upgraded in the 1950s and 1960s. This system of 50-year-old lines cannot handle the rapid transfers of a new power-trading economy. One official confirmed that 80% of the generators that had been off during the initial 2003 blackout were soon running again at capacity but the transmission lines could handle only 20% of the output. Little focus has been given to the grid’s vulnerabilities. Following the big blackout of 1965, the electricity-transmission system was supposed to have been redesigned with safeguards that would not allow such disruptive incidents. For years there has been too little investment in a transmission grid that has been strained. One major factor was deregulation. In the 1990s, many utilities were broken up, separating the transmission businesses from the power generators thus product electricity. Today the system is dominated by independent operators in a market-driven


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system with no link between generation planning and transmission planning. Operators see little benefits in building power lines for other regions and citizens’ groups have made local approval of new transmission lines difficult. In the past, power companies had to invest in transmission because it was part of their business model. Now, they may not own any part of transmission in the deregulated model. Economic growth and the proliferation of computers and other digital devices have strained the power arteries, while utilities and state governments debate over who should repair the problem. Deregulation allows local utilities to sell electricity where they can find a buyer. But the grids are still administered on a state-by-state basis. This is because states do not want to give up control, which stops new transmission lines from being built. State and federal commissions need to meet to consider upgrades of the grid across state lines. The Federal Energy Regulatory Commission (FERC) should order the construction of new lines, like the proposed Arrowhead-Weston line between Wisconsin and Minnesota. The highway system is planned on a federal level, the federal government should also direct expansion of the power grid. As the U.S. economic output doubled between 1975 and today, investment in the grid dropped from $5 billion to about $2 billion annually, according to the Edison Electric Institute. In a deregulated world, utilities use each other’s networks so no one wants to pay for an improvement that would also benefit competitors. Funding upgrades of the system with federal dollars is one solution. Financial incentives for power generators to build transmission lines for new plants is another. New plants could be paid by rate increases over several years. Like the infrastructure itself, the failure of support for long-range planning transcends national borders. As the global economy becomes increasingly dependent on the digital networks made possible by electricity, public funding worldwide for newer cleaner power sources and improving our infrastructure is decreasing. The U.S. spent one-third less on energy R&D in 1995 than it did in 1985. Germany, Italy, and the UK spent two-thirds less. The clumsy, half-hearted approach to electricity deregulation in America and Europe has placed many of the world’s electric networks between old command-and-control markets and a new era of market and competition making them more exposed to major power-cuts. That is not because deregulation inherently carries the risk of more blackouts, open

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and competitive markets are more likely to provide reliable energy than government controlled systems. In India the power network is vertically integrated to the extreme but it is also considered to be the most corruptible, incompetent and blackout-prone in the world. The risk is highest in countries that have implemented halfway reforms like the U.S. America’s flawed deregulation program has left the grid with significant under-investment, which contributes to recent blackouts. Transmission lines are old and overloaded with grid switching equipment that fails to react at critical times. Britain has made major investments in transmission and was able to contain its London blackout and restore power in less than an hour, while America’s eastern outage cascaded through many states and lasted through the night. In Italy, limited reform was blamed by the European Commission which pointed to Italy’s delay to expand cross-border trading and to build new international transmission lines. The Federal Energy Regulatory Commission would like to give all electricity suppliers equal access to power lines. This would provide more power from generators in other regions. But power companies and politicians in the South and West have opposed the plan, stating that it would force prices up in their usually low-cost regions. The modern power grid is stretched over a vulnerable technological infrastructure. The Electric Power Research Institute (EPRI) was founded after the failure of the grid in 1965. EPRI believes we still have not fully heard the message of that massive blackout. One lesson, many believe, is that we need smarter methods of electricity generation, transmission and delivery not just more power and more lines. EPRI is the utilities think tank, an independent research organization funded by more than 1,000 power companies. EPRI was the first industry wide R&D consortium in America. It is one of the largest consortiums in the world and represents utilities in 40 countries. EPRI’s members range from the older giants like Consolidated Edison of New York to the newer companies like Mirant and Dynegy. These members generate 90% of the electricity used in the United States. When the electric power grid suffered a massive blackout in 2003, the lights went out from Ohio and Ontario to New York and it seems that a local system failure cascaded over a wide area, but many have long seen major problems in the grid and search for ways to minimize the effects of blackouts. The grid is always involved in a balancing act. The amount of electricity taken from the lines (the load) has to match the electricity being


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generated. If the power generation drops too much, system controllers have to shed load, causing brownouts or blackouts. The electricity flows through the grid as alternating current so AC frequencies at each station must match. Partial deregulation during the early 1990s allowed some states to separate their generation and transmission industries. Generation systems boomed, but transmission lagged behind due to a patchwork of interstate regulations and jurisdictions. Nationwide policies covering transmission system operation, capacity and investment would force transmission owners to implement a stronger and more resilient grid. Currently protective relays shut down power lines if high currents threaten to make them overheat and sag, but those lines could be kept functioning with more heat-resistant lines, which are available. Generators switch off if the AC frequency or phase changes rapidly because the generators can damage themselves trying to respond to these changes. The use of breaking resistors, which exchange electricity for heat, could help generators make smoother transitions. Better communications among power stations would also aid in stabilizing the grid. Protective relays rely on local information and may disconnect a line unnecessarily. Dedicated fiber-optic cables would permit comparisons of conditions at adjacent stations, reducing needless shutdowns. The Global Positioning System (GPS) could be used to put time stamps on station readings, allowing operators to make better decisions by using successive snapshots of grid conditions. The Bonneville Power Administration, based in Portland, Oregon, and Ameren Corporation, a St. Louis utility, use GPS time stamping. Once operators get a snapshot of grid conditions, they could transfer the information to faster, smarter switches. Flexible AC transmission devices could tune the power flow. Superconducting valves called fault current limiters would allow circuit breakers to disconnect lines cleanly. Southern California Edison (SCE) is building segment one of the Tehachapi renewable transmission project. When all phases are developed, the Tehachapi project will include a series of new and upgraded highvoltage transmission lines capable of delivering 4,500-MWs of electricity from the wind farms and other generating facilities that are proposed for northern Los Angeles and eastern Kern counties. SCE is constructing the Tehachapi project in 11 segments to coincide with the development of independently owned wind farms. The first segment includes the con-

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struction of a 26 mile, 500-kV transmission line connecting SCE’s Antelope Substation in Lancaster with the utility’s Pardee Substation in Santa Clarita. The Tehachapi project will strengthen and enhance SCE’s transmission system by creating a new path for renewable energy to meet the increasing electricity demand of Southern California. This effort to deliver electricity from wind farms in eastern Kern County supports California’s renewables portfolio standard. SCE also has a 1,500-MW wind contract, which was the largest in U.S. renewable history, with Alta Windpower that relies on the development of the full Tehachapi renewable transmission project. The Tehachapi project is part of SCE’s five-year $4 billion transmission expansion program. Installing more AC lines or more powerful lines would increase transmission capacity but could lead to bigger transients in the grid. When something goes wrong, there has to be a way to contain a disturbance, and the most common way to do that is to disconnect lines. A master computer with a total view could serve as traffic control for the grid. Studies indicate that such a global view would have prevented about 95% of customers from losing power during the 1996 blackouts in the western U.S. One technique to improve control would automatically quarantine trouble spots and divide the remaining grid into islands of balanced load and generation. EPRI has commissioned computer-modeling studies of the technique, called adaptive islanding. These studies concluded that it could preserve more load than conventional responses. Adaptive islanding would take about five years to implement, but blackouts would not disappear. The chance of a cascading failure is real in stressed or highly interconnected systems. With every incremental increase in grid reliability, the cost of the next increment goes up. DISTRIBUTED POWER TRENDS Distributed power generation means placing energy generation and storage as close to the point of consumption as possible with maximum conversion efficiency and minimal environmental impact. Typically, centralized power stations are over-designed to allow for future expansion and so they run for most of their life at a reduced efficiency. They also represent a higher financial risk to the owner because of the greater amount of investment in a single plant.


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Distributed generation involves dispersed generators, which are customer sized and usually in the service transformer range of 5-500-kW. These are connected at low voltage to the network. Larger distributed generators are about the size of primary distribution equipment such as feeders or substation transformers in the range 2-10-MW and connected at medium voltages to the network. In transmission and distribution, optimum routing will become more important to match energy usage to local sources. The key objective will be to route electricity by the shortest path and to optimize the energy imported from outside regions. In the future environmental and resource conservation pressures will lead to an increased regional and intercontinental energy exchange. This will require enhanced management systems. By 2060, the World Bank estimates that developing nations will consume over twice the power used by established countries. VIRTUAL UTILITIES Deregulation of the power industry has changed the way the utility business operates, but changes in the future will be more visible. Most noticeable will be a reduction in the number of high profile, monolithic power stations and their replacement by small, localized generators. While this may improve power availability, it will mean an addition to the number of transmission lines already in place. But, it will also make it more economically viable and practical to incorporate less common forms of power generation. While these developments may lead to the need for more local transmission lines, advances in reactive compensation will allow more lines to be run underground. These changes are currently driven by the needs of manufacturers and organizations that could benefit by generating their own electricity and selling any surplus. The benefits of localized generation will grow and this may reduce the need to transmit electricity over very long distances. This increased volume of privately generated electricity requires more control and management and the evolution of virtual utilities. These are organizations that do not own generating capacity, transmission lines or distribution equipment. They control a power network by paying those who supply electricity to the system and collect from those

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who use power. They maintain the infrastructure through subcontractors. In one virtual utility project ABB has a partnership with Progress Energy, which supplies about 3 million customers in the Carolinas and Florida. This project allows the connection of combinations of energy sources, including microturbines, CHP plants, wind power and fuel cells. Internet-based links are used to connect the sources to a central control center. This allows Progress Energy to monitor about 10-MW of distributed generation from a single location. The control of virtual utilities requires monitoring and supervision software with aggregation and reporting software to aid decision-making functions. This software interfaces with other packages that link users to trading and forecasting packages. The market rates are continually available and compared with generation capacity. Unit control and dispatching packages complete the software functions. An increase in virtual utilities should result in increased trading competition and lead to further technical developments. This will improve efficiency in system operation along with forecasting and scheduling. Weather forecasting will also be used as a crucial factor in predicting power usage. Improved simulation software should result in improvements in forecasting and scheduling decisions. The methods used for managing a network will also change. Currently, most power networks use a top-down structure, with centralized controls for energy sources. In the future, it should be possible to have a bottom-up integrated optimization of energy supply based on the availability of generators, with a decentralized control. This would allow more resource optimization and reduce the need for high levels of standby capacity. Microturbines, wind power generators, solar energy and fuel cells do not naturally produce electricity at 50 or 60-Hz. More flexible AC transmission systems would help the efficient connection of these resources to grid systems. Grid stability will become an even more complex issue for control and protection. One technique is to use high voltage direct current (HVDC) systems as isolating links between grids as a way to reduce the need for large-scale synchronization. DC TRANSMISSION The use of direct current on power networks avoids the problems of instability which can occur on long AC transmission lines and cause


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surges and blackouts. When connecting isolated grids, HVDC back-toback stations allow power interchange while blocking power line problems. DC transmission means lower line costs with no need for frequency control equipment and lower line losses and costs. But, HVDC stations are more expensive than AC substations and may interact in an adverse manner under certain conditions. Direct current lines, which have no frequency associated with them, tend to act as shock absorbers to disturbances in AC systems. DC lines separate the Texas power grid from the eastern and western grids. Adding more could help make the grid system more stable, although highvoltage DC is expensive. ABB Power Systems’ HVDC Division in Ludvika, Sweden, has been involved in several developments in HVDC. These include using insulated gate bipolar transistors (IGBTs) instead of thyristor valves for control. This improves the cost range for dc transmission, making it more feasible for local distribution. Another development is deep-hole ground electrode technology, which drops cabling costs by replacing one wire with an earth return. The electrode can be located close to the station, with reduced power loss and interference and provides opportunities to use monopolar HVDC transmissions. Land electrodes usually require a large area, especially where the earth resistivity is high. But, lower resistivity can often be found between 100 to 200m below the surface due to a higher salt content. This means lower electric potentials and potential gradients than at the surface. SMART GRIDS A smart grid replaces analog mechanical meters with digital meters that record power usage in real time. Smart meters provide an advanced metering infrastructure with communications from generation plants to electrical outlets (smart sockets) and other smart grid-enabled devices. Under customer control, these devices can shut down during times of peak demand. A power grid is an aggregate of multiple networks and multiple power generation companies with multiple operators employing varying levels of communication and coordination, most of which is manually controlled. Smart grids increase the connectivity, automation and coor-

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dination between these suppliers, consumers and networks that provide long distance transmission or local distribution. The smart grid is an upgrade of 20th century power grids which sent out power from a few central power generators to a large number of users. The smart grid would be able to route power in more optimal ways to respond to a wide range of conditions. These conditions could occur anywhere in the power generation, distribution and demand chain. Events may occur in the system where clouds block the sun and reduce the amount of solar power or a distribution transformer fails requiring a temporary shutdown of a distribution line. Many of the proposed solutions have similar names, such as smart electric grid, smart power grid, intelligent grid (or intelligrid), FutureGrid, and intergrid and intragrid. One of the first attempts at smart grid technologies in the U.S. caused a hail of criticism and was rejected by regulators in Massachusetts. A Northeast Utilities’ Western Massachusetts Electric Co. subsidiary tried to create a smart grid program using public subsidies that would switch low income customers from post-pay to pre-pay billing using smart cards in addition to premium rates for electricity used above a predetermined amount. The plan was rejected by regulators since it affected protections in place for low-income customers against shutoffs. Transmission networks for medium to long distances generally operate on 345-800kV AC or DC lines. Local networks traditionally move power in one direction, distributing the generated power to consumers and businesses over lines of 132kV and lower. This is changing as businesses and homes began generating more wind and solar electricity, allowing them to sell surplus energy back to utilities. Energy consumption efficiency requires the real time management of power and bidirectional metering to compensate local producers of power. Although transmission networks are already controlled in real time, many networks in the U.S. and Europe are unable to handle challenges such as the intermittent nature of alternative electricity generation and continental scale bulk energy transmission. A smart grid involves the modernization of the transmission and distribution grids. This modernization includes: • Greater competition between providers. • More use of variable energy sources. • Automation and monitoring capabilities for continental bulk transmission.


•

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Greater use of market forces to push energy conservation.

Smart meters serve the energy efficiency goal since they allow suppliers to charge variable electric rates so the charges reflect the differences in cost of generating electricity during peak or off peak hours. Capabilities include load control switches for large energy consuming devices such as hot water heaters. To reduce demand during the high cost peak usage periods, higher peak curtailment or peak leveling prices are used during high demand periods. In Ontario, Canada, the Energy Conservation Responsibility Act in 2006 mandated the installation of Smart Meters in all Ontario businesses and households by 2010. Smart grids should reduce the amount of spinning reserve that electric utilities need to keep on stand-by, since the load curve will flatten. Renewable energy favors smarter grids, since most renewable sources are intermittent and depend on natural phenomena, sun and wind to generate power. Any type of power infrastructure using a significant portion of intermittent renewable energy resources must have the means of effectively reducing electrical demand by load shedding. While the use of two-way communications, advanced sensors, and distributed computing technology will improve the efficiency, reliability and safety of power delivery and use, it also allows new services or improvements, such as fire monitoring and alarms that can shut off power and contact emergency services. A Department of Energy study estimates that internal modernization of U.S. grids with smart grid capabilities could save between 46 to 117 billion dollars over the next few decades. In the U.K., consumers have had almost 10 years to select the company from which they purchase power but more than 80% have stayed with their existing supplier, in spite of significant differences in prices. The government plans to have smart meters to every home in the U.K. by 2020. In 2009, China has announced an aggressive framework for Smart Grid deployment. The development of smart grid technologies is part of the European Technology Platform (ETP) initiative and is called the SmartGrids Technology platform. The SmartGrids European Technology Platform for Electricity Networks of the Future began in 2005 and aims to formulate and promote a vision for the development of European electricity networks looking towards 2020 and beyond.

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Europe’s SuperSmart Grid, as well as earlier proposals such as the Unified Smart Grid make distinctions between local and national grids that sometimes conflict. Some associate the smart grid with local clusters while others see an intelligent interconnecting backbone providing an additional layer of coordination above the local smart grids. However most smart grid schemes intend to allow continental and national interconnection backbone failures without causing local smart grids to fail. They would have to be able to function independently and ration whatever power is available to critical needs. The amount of data required to perform monitoring and switching is very small compared with that already reaching homes to support voice, security, internet and TV services. Latency of the data has been a concern, with some early smart meter systems allowing as long as a 24 hour delay in receiving the data. Some have raised issues on the security of the technology. Researchers from U.S. security consultancy IOActive created a worm that could spread from one smart metering device to another over the wireless technology that is used for connecting them. Since power and communications are generally separate enterprises in North America and Europe, these companies would need to cooperate. Before recent standards efforts, municipal governments, such as Miami, Florida, have been promoting integration standards for smart grids and meters. Municipal electric power monopolies often own some fiber optic backbones and control transit exchanges which communication service providers must meet, so they can force integration. Municipalities also have the responsibility for emergency responses and would in most cases have the legal right to ration or control power to ensure that hospitals, fire response and shelters have priority in an outage. In the U.S. support for smart grids became federal policy with the Energy Independence and Security Act of 2007. It provided $100 million in funding per fiscal year from 2008-2012 for states, utilities and consumers to build smart grid capabilities and created a Grid Modernization Commission to assess demand response and recommend protocol standards. Smart grids received further support with the passage of the American Recovery and Reinvestment Act of 2009, which provided $11 billion for the creation of a smart grid. The United States Department of Energy is providing almost $4 billion in American Reinvestment and Recovery Act funds to support smart grid projects. The DOE’s Smart Grid Investment Grant Program will pro-


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vide grants of $500,000 to $20 million for smart grid technology deployments and grants of $100,000 to $5 million for the deployment of grid monitoring devices. The program will provide matching grants of up to 50% of the project cost. The total funding for the program is $3.375 billion. There is also $615 million to support demonstrations of regional smart grids, utility-scale energy storage systems, and grid monitoring devices. In 2008, the National Science Foundation established the FREEDM Systems Center, an Engineering Research Center to develop smart grid technologies that will allow plug-and-play integrations of distributed generation and storage. Technology development will focus on wide band gap power electronics technology to control and protect the power grid. Most projects are related to technologies to help transmission and distribution systems operate better, but a few are tied to renewable energy. The city of Fort Collins, Colorado, will develop and demonstrate an integrated system of mixed clean energy technologies and distributed energy resources which should allow the city to reduce its peak electrical demand by at least 15%. The Illinois Institute of Technology (IIT) in Chicago will concentrate on implementing distributed energy resources and creating demand-responsive microgrids, which are small power networks that can operate independently of the utility power grid. The University of Hawaii is investigating the management of its electrical distribution system to better accommodate wind power. The Federal Energy Regulatory Commission (FERC) has some general principles that the smart grid standards should follow. It is also looking ahead at the growth of clean energy, so smart grids can accommodate renewable energy resources, demand response systems, energy storage systems, and electric vehicles. In 2009, smart grid companies were one of the biggest and fastest growing sectors in the greentech market. They received more than half of venture capital investments. George W. Arnold was named the first National Coordinator for Smart Grid Interoperability and Europe and Australia are following similar paths. Smart grid standards include: • IEC61850, an architecture for substation automation. • IEC 61970/61968 the Common Information Model (CIM). The CIM provides for common semantics to be used for turning data into information. The IEEE has also created a standard to support synchrophasors C37.118.

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The IEEE P2030 project has been developing a “Draft Guide for Smart Grid Interoperability of Energy Technology and Information Technology Operation with the Electric Power System (EPS), and End-Use Applications and Loads.” The MultiSpeak specification supports distribution functionality of the smart grid. MultiSpeak includes a set of integration definitions that supports most of the software interfaces necessary for a distribution utility or for the distribution sector of a vertically integrated utility. MultiSpeak integration is defined using extensible markup language (XML) and web services. The standards used in smart grids are deliberated by the UCA International User Group. There is also a Utility Task Group within LonMark International, which deals with smart grid related issues. There is a growing trend towards the use of TCP/IP technology as a common communication platform for Smart Meter applications, so that utilities can deploy multiple communication systems, while using IP technology as a common platform. The OASIS EnergyInterop technical committee has been developing XML standards for energy interoperation based on the California OpenADR standard. Some companies like Cisco, see an opportunity in providing devices to consumers which are similar to those they have been providing to industry. Others, such as Silver Spring Networks or Google see themselves as data integrators. Xcel Energy has coal, nuclear and natural gas plants and is developing the SmartGridCity project in Boulder, Colorado. It will switch power through automated substations and re-route power around bottlenecked lines. Xcel Energy will use smart meters with a Web portal to give customers the ability to review their in-home energy usage. Google and Microsoft have also announced online energy management systems. Microsoft’s online application Hohm is based on analytical tools from the Lawrence Berkeley National Laboratory and the Department of Energy. Google partners include utilities in California, Texas, Florida, India, Wisconsin, Missouri, Canada and Kentucky for the development of its Google PowerMeter technology. A home grid extends some of these smart grid capabilities into the home using powerline networking and extensions to DC power over Ethernet. The IEEE P2030 interoperability standards are expected to define global, continental, regional, municipal and home distinctions. Many of the same techniques are common in smart and home grids, so the terms


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intergrid and intragrid are often used. A home grid generally has megabits of additional bandwidth for other services such as burglary, fire, medical and environmental sensors and alarms, CCTV monitoring, access control and keying systems, intercoms and secure phone line services. The AC power control standards suggest that powerline networking would be the primary means of communication among smart grid and home devices. Consumer electronics devices now consume over half the power in a typical U.S. home and the ability to shut down or idle devices when they are not receiving data could be a major factor in cutting energy use. In Europe and the U.S., serious impediments exist to the widespread adoption of smart grid technologies, including: • Regulatory environments that do not reward utilities for efficiency. • Consumer concerns on privacy. • Concerns over the fair availability of power. • Concerns over abuses of information. • The ability of utilities to rapidly transform their business models. Before a utility installs an advanced metering system, or other type of smart system, it must make business sense for the investment. Some components, like the Power System Stabilizers (PSS) installed on generators are expensive and require complex integration in the grid’s control system, but they are needed only during emergencies and are only effective if other suppliers on the network have them. Most utilities find it difficult to justify installing a communications infrastructure for a single application like meter reading. A utility must have several applications that will use the same communications infrastructure such as meter reading, monitoring power quality, remote connection and disconnection of customers or demand response actions. Each utility has its own unique set of business, regulatory, and legislative requirements that guide its investments, so each utility will take a different path in creating their smart grid and different utilities will create smart grids at different adoption rates. There is competition with cable and DSL internet providers for broadband over powerline internet access. Providers of SCADA control systems for grids have intentionally designed proprietary hardware, protocols and software so that they cannot inter-operate with other systems.

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PHASOR MEASUREMENT TRENDS Phasor measurement units (PMUs) are high-speed sensors used to monitor power quality. In the 1980s, it was noted that the clock pulses from global positioning system (GPS) satellites could be used for very precise time measurements in the grid. The use of PMUs provides the ability to compare shapes from alternating current readings on the grid. These automated systems may revolutionize the management of power systems by responding to system conditions in a rapid, dynamic way. A wide-area measurement system (WAM) is a network of PMUs that can provide real-time monitoring on a regional and national scale. Many believe that the Northeast blackout of 2003 would have been contained to a much smaller area if a wide area phasor measurement network was in use. As part of its current 5-year plan, China is building a Wide Area Monitoring system (WAMS) and by 2012 plans to have PMU sensors at all generators of 300 megawatts and above, and all substations of 500 kilovolts and above. All generation and transmission is controlled by the state, so standards and compliance is rapid. There are requirements to use the same PMUs from the same Chinese manufacturer and stabilizers conforming to state specifications. All communications are via broadband using a private network. ADVANCED GRID TRENDS Advances in superconductivity, fault tolerance, storage, power electronics, and diagnostics are expected to change the fundamental abilities and characteristics of grids. Some of these technologies include: • Flexible alternating current transmission system devices. • High voltage direct current. • First and second generation superconducting wire. • High temperature superconducting cable. • Distributed energy generation and storage devices. • Composite conductors. • Intelligent appliances. Power system automation allows the rapid diagnosis of and precise solutions to specific grid disruptions or outages. These technologies


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rely on and contribute to each other. Advanced grid control methods include: • Distributed intelligent agents and control systems. • Analytical tools, software algorithms and high-speed computers. • Operational applications, SCADA, substation automation and demand response. Information technologies include: • Visualization techniques to reduce large quantities of data into easily understood visual formats. • Software systems to provide multiple options when systems operator actions are required. • Simulators for operational training and what-if analysis. Voltage stability monitoring & control (VSMC) software uses sensitivity-based successive linear programming to determine optimal control solutions. Artificial intelligence programming techniques are used in the Fujian power grid in China to provide a wide area protection system that is rapidly able to accurately calculate a control strategy and carry it out. SMART GRID VEHICLES A study of plug-in hybrid electric vehicles (PHEVs) found that there could be a reduction of the overall expense of owning a vehicle and that smart-grid technologies could eliminate vehicle emissions by up to 50 percent. The study considered how adding PHEVs to the road would affect the electric power grid depending on how the cars were charged. A computer-modeling program was used to measure the impact of mass penetration of the PHEVs and the energy needed to charge them. The study indicated that the cars equipped with a 9 kilowatt-hour battery, could reduce overall carbon dioxide vehicles emissions by half and save the owners more than $400 in fuel costs per year compared to an internal combustion vehicle. Smart-grid technologies could enable the charging programs for PHEVs and could manage the charging process in conjunction with the availability of renewable energy sources. For electric vehicles, the smart

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grid would allow charging during times of low power demand and the smart grid would accommodate vehicle-to-grid technologies, which would use electric vehicles as a distributed, energy storage system. References

Hordeski, Michael F., Emergency & Backup Power Sources, The Fairmont Press: Lilburn, GA, 2004. Minkel, J.R., “Heating the Grid: Several Near-term Solutions can Keep the Juice Flowing,” Scientific American, Vol. 289, November 2003, pp. 18-20. Pansini, A.J. Power Systems Stability Handbook, The Fairmont Press, Inc.,: Lilburn, GA, 1992. Russell, Eric, “Virtual Utilities: the Shape of Things to Come,” European Power News, Vol. 26, No. 5, May 2001, pp. 7-9.

Chapter 8

The Future for Renewables Keywords: Clean Energy Stationary Power Trends The World’s First Hydrogen Economy Renewable Energy Trends Marine Thermal Energy Wave Energy Trends Solar Satellites The Future for Energy

A

Bottled Fuel Hydroelectric Power Trends Small Wind Energy Geothermal Power Hydrothermal Power Systems The Future of Geothermal Advanced Solar

s the price of petroleum fuels emerges with that of alternate energy sources, new power systems will become more widely used. Synthetic fuels could be used directly in engines or to generate electricity from fuel cells for electric motors. A renewable future could take many paths. Before our present oil economy, gasoline and other fuels were originally available in small amounts often from hand pumps. The federal government promoted alternative fuels in the 1990s, but there is a lack of interest in alternative fuels when gasoline and other petroleum fuels were widely available. The United States Energy Policy Act of 1992 attempted to reduce the amount of petroleum used for transportation by promoting the use of alternative fuels in cars and light trucks. These fuels included natural gas, methanol, ethanol, propane, electricity, and biodiesel. Alternative fuel vehicles (AFVs) can operate on these fuels and many are dual fueled are also running on gasoline. Another goal was to have alternative fuels replace at least 10% of petroleum fuels in 2000 and at least 30% in 2010. Part of the new vehicles bought for state and federal government fleets, as well as alternative fuel providers, must be AFVs. The Department of Energy (DOE) was to encourage AFVs in several ways, including partnerships with 267

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city governments and others. This work went to the Office of Energy Efficiency and Renewable Energy. By 2000, less than 1/2 million AFVs were in use which is less than 0.2% of all vehicles. In 2000, alternative fuels used by AFVs replaced about 350 million gallons of gasoline, about 0.3% of the year’s total consumption. Almost 4 billion gallons of ethanol and methanol replaced gasoline that year in blended gasoline that was sold for standard gasoline engines. CLEAN ENERGY The DOE has been developing clean energy technologies and promoting the use of more efficient lighting, motors, heating and cooling. As a result of these efforts and efforts by others, there have been savings by business and consumers of more than $30 billion in energy costs. Getting people to use alternative fuel has proven to be more difficult. The GAO stated that the goals in the past for fuel replacement were not met because alternative fuel vehicles have serious economic disadvantages compared to conventional gasoline engines. These include the comparative price of gasoline, the lack of refueling stations for alternative fuels and the additional costs of the vehicles. Hydrogen powered internal combustion engines could promote an infrastructure for fuel cell cars. An internal combustion engine (ICE) can burn hydrogen with a few inexpensive modifications. Some automakers, including Ford and BMW, have been working on hydrogen ICE cars which have the advantage over gasoline engines of very low emissions of urban air pollutants. Because of the energy used in generating hydrogen from natural gas or electricity and the energy required to compress hydrogen for storage, the total energy use of a hydrogen internal combustion engine can be higher than a gasoline engine. One study of different alternative fuels found that burning hydrogen from natural gas had the lowest overall efficiency on a total energy consumed basis. The internal combustion engine, running on gasoline, has been powering transportation for almost a century. Advances in engines and fuels, such as reformulated gasoline, have reduced the pollution of these engines. Competitors such as electric cars and natural gas vehicles have not been able to penetrate their dominance. The competi-

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tion for fuel cell vehicles includes hybrid vehicles and diesels, which are seeing many advances today. Hybrid gasoline electric-powered cars can be twice as efficient as internal combustion vehicles. An onboard energy storage device, which is usually a battery and sometimes a special capacitor (called a super capacitor), increases the efficiency greatly. Regenerative braking is also used to capture energy that is normally lost when the car is braking. The engine is turned off when the car is idling or decelerating. Gasoline engines have lower efficiencies at lower rpm so the gas engine operates only at higher rpms and is more efficient most of the time. In city driving, non polluting electric power is used. Modern diesel engines are much different from the engines of the 1970s and 1980s. Advances have included electronic controls, highpressure fuel injection, variable injection timing, improved combustion chamber design, and turbo-charging. They are 30 to 40% more fuel efficient than gasoline engines. The production and delivery of diesel fuel releases 30% less carbon dioxide than producing and delivering gasoline with the same energy content. Diesels emit higher levels of particulates and oxides of nitrogen. But, they are steadily reducing these emissions. A large amount of R&D is currently going into diesels and it is expected that they will be able to meet the same standards as gasoline engines in the near future. Diesels are less than 1% of car and light truck sales in the U.S. But, they are more popular in Europe with its high gasoline prices. Their fuel taxes help to promote diesels and the emissions standards are less strict. Diesels are in almost 40% of the cars in Europe. By 2001 they were offered in most of the new cars sold in many European countries. Many drivers would trade in their current car for an electric vehicle, if it could perform as well and not cost any more. One poll of California new car buyers conducted by the University of California at Davis found that almost half would buy an electric vehicle over a gasoline car, but they wanted a 300-mile range and a more rational price. These same concepts could be used in fuel cell powered cars. Ultralight fuel cell vehicles are a part of the current generation of clean concept cars, sometimes called Green Cars. A fuel cell car, bus or truck is in essence an electric vehicle powered by a stack of hydrogen fueled cells that operates like a refuelable battery. A battery uses chemical energy from its component parts,

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while a fuel cell uses an electrochemical process to generate electricity and receives its energy from the hydrogen fuel and oxygen that are supplied to it. Like the plates in a battery, the fuel cell uses an anode and cathode, attached to these are wires for the flow of current. These two electrodes are thin and porous. Most automotive fuel cells use a thin, flurocarbon-based polymer to separate the electrodes. This is the proton exchange membrane (PEM) that gives this type of fuel cell its name. The polymer provides the electrolyte for charge transport as well as the physical barrier to block the mixing of hydrogen and oxygen. An electric current is produced as electrons are stripped from hydrogen atoms at catalysis sites on the membrane surface. The charge carriers are hydrogen ions or protons and they move through the membrane to combine with oxygen and an electron to form water which is the main byproduct. Trace amounts of other elements may be found in this water, depending on the cell construction. In most cells the water is very pure and fit for human consumption. Individual cells are assembled into modules that are called stacks. PEM fuel cells can convert about 55% of their fuel energy into actual work. The comparable efficiency for IC engines is in the range of 30%. PEM cells also offer relatively low temperature operation at 80°C. The materials are used to make them reasonably safe with low maintenance requirements. The emergence of commercial fuel cell cars will depend on developments in membrane technology, which are about one third of the fuel cell cost. Improvements are needed in fuel crossover from one side of a membrane to the other, the chemical and mechanical stability of the membrane, undesirable side reactions, contamination from fuel impurities and overall costs. One breakthrough in membrane technology was a hydrocarbon polymer membrane with improved performance and lower costs. This cellophane like film performs better than more common perfluorinated membranes, such as DuPont’s Nafion material. Fluorcarbon membranes may cost about $300 per square meter, the newer materials cost about half of this. Another key part of a PEM membrane is the thin layer of platinum-based catalyst coating that is used. It makes up about 40% of the fuel cell cost. The catalyst prepares hydrogen from the fuel and oxygen


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from the air for an oxidation reaction. This allows the molecules to split and ionize while releasing or accepting protons and electrons. If the reaction on the oxygen side is not controlled properly, highly corrosive byproducts such as hydrogen peroxide can result, which quickly damage the internal components. Over time and usage tiny holes can form on the film which reduces fuel cell performance. If the film is made thicker and stronger, then performance suffers. Although many questions involve fuel cell availability and much is dependent on the auto industry, fuel cells have begun to appear in a number of autos in limited production. Hydrogen may not be more expensive than gasoline as oil prices move upward. Hydrogen could cost about $4 or more per kilogram (kg) which is close to the equivalent-energy price of gasoline. A kilogram of hydrogen has almost the same energy as a gallon of gasoline. Tanker trucks with liquefied hydrogen are typically used to deliver hydrogen today. This is the method NASA uses. It is popular for delivery in Europe as well as North America. It is currently less expensive than small on-site hydrogen generation. Liquefaction has a high energy cost, requiring about 40% of the usable energy in hydrogen. Liquid tanker trucks could be the least expensive delivery option in the future. After delivery, the fueling station still has to use an energyintensive pressurization system, which can consume another 10 to 15% of the usable energy in the hydrogen. This means that storage and transport might require as much as 50% of the energy in the hydrogen delivered. If liquefaction is to be viable, a less energy-intensive process is needed. Pipelines can also be used for delivering hydrogen. Several thousand miles of hydrogen pipelines are in use around the world, with several hundred miles in the U.S. These lines are short and located in industrial areas for large users. The longest pipeline in the world is almost 250 miles long and goes from Antwerp to Normandy. It operates at 100 atmosphere of pressure which is approximately 1,500 psi. Air Products plans on constructing a hydrogen production plant in Port Arthur, Texas, to supply 110 million standard cubic feet per day of hydrogen to Premcor Refining and others on Air Product’s Gulf Coast hydrogen pipeline system. Hydrogen pipelines are expensive because they must have very effective seals. Hydrogen is also reactive and can cause metals, including steel, to become brittle over time. Hydrogen pipelines of 9 to 14

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inch diameter can cost $1 million per mile or more. Smaller pipelines for local distribution cost about 50% of this. Siting major new oil and gas pipelines is often political and environmentally litigious. Political pressures may favor one location over another. Whether global warming concerns will be enough to override other considerations is still unknown. Trailers carrying compressed hydrogen canisters could provide a flexible way of delivery suited for the early years of hydrogen use. This is a relatively expensive delivery method since hydrogen has a low energy density and even with high-pressure storage, not that much hydrogen is actually being delivered. Current tube or canister trailers hold about 300-kg of hydrogen which is enough to fill sixty fuel cell cars. It is estimated that with improved high-pressure canisters, a trailer could hold about 400-kg of hydrogen or enough for about 80 fuel cell cars. A tanker truck for gasoline delivers about 26 metric tons of fuel, or 10,000 gallons which is enough to fill 800 cars. About one in 100 trucks on the road is a gasoline or diesel tanker. Replacing liquid fuels with hydrogen transported by tube truck means that about 10% of the trucks in the U.S. would be transporting hydrogen. There may be additional options in the future with the significant R&D going into each of the storage and transportation technologies. STATIONARY POWER TRENDS Stationary power is the most mature application for fuel cells with units used for backup power, power for remote locations, standalone power for towns and cities, distributed generation for buildings, and co-generation where excess thermal energy from electricity generation is used for heat. More than a thousand systems that produce over 10 kilowatts each have been installed worldwide. Most of these are fueled by natural gas. Phosphoric acid fuel cells (PAFCs) have typically been used for large-scale applications, but molten carbonate and solid oxide units also compete with PAFCs. Thousands of smaller stationary fuel cells of less than 10 kilowatts each are used to power homes and provide backup power. Polymer electrolyte membrane (PEM) fuel cells fueled with natural gas or hydrogen are the principal units for these smaller systems.


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A 200-kilowatt (kW) PAFC unit produced by UTC Fuel Cells is used to provide electricity and heat to the U.S. Postal Service’s Anchorage Mail Handling Facility. In 2000, the Chugach Electric Association installed a 1 Megawatt (MW) fuel cell system which consists of five natural gas powered 200-kW PC25 fuel cells developed by UTC Fuel Cells. The fuel cell station provides primary power for the facility as well as half of the hot water needed for heating. Excess electricity from the system flows back to the grid for use by other customers. The Town of South Windsor, Connecticut, installed a natural gas powered 200-kW PC25 fuel cell system, from UTC Fuel Cells, at the South Windsor High School. The system provides heat and electricity to the high school along with education opportunities for the students. The school has an extensive fuel cell curriculum and uses computer monitors to allow students to track the operation of the fuel cell. South Windsor High School has been designated as a regional emergency shelter and the fuel cell system will be able to provide power in the event of an electric power outage. The Department of Defense (DOD) Fuel Cell Demonstration Program is managed by the U.S. Army Corps of Engineers. Since the mid1990s it has advanced the use of PAFCs at DOD installations. Under this program, stationary fuel cells were installed at 30 facilities and locations in the Armed Services. The fuel cells are used for primary and back-up power as well as heat. The DOD also has a residential fuel cell demonstration program using polymer electrolyte membrane (PEM) fuel cells ranging in size from 1 to 20 kilowatts. This includes twenty-one PEM fuel cells at nine U.S. military bases. The DOE’s Distributed Energy and Electric Reliability Program involves a series of traveling road shows for building code inspectors, fire marshals and others on distributed energy technologies, including hydrogen and fuel cells. THE WORLD’S FIRST HYDROGEN ECONOMY Iceland could become the world’s first hydrogen economy. This island nation in the North Atlantic has many active volcanoes, hot springs, and geysers. Iceland uses this renewable energy for power

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generation and heating. But, to fuel its vehicles and fishing fleet, Iceland imports about 6 million barrels per year of petroleum. There are no sources of oil or other fuels other than some landfill methane on the island. Energy is tapped from the hot water or steam in the ground to run turbine generators while lower temperature water is used to heat buildings or provide process heat for industries. Using some of its renewable energy would allow Iceland to produce hydrogen and replace all the oil used for the country’s transportation and fishing industry. Iceland has about 170 megawatts (MW) of geothermal electric power generation which provide more than 1.3 million MWh per year. Its hydroelectric plants have a capacity of approximately 1,000-MW and supply almost 7 million MWh per year of electric power. The current capacity at hydroelectric plants would allow significant hydrogen production. The hydrogen could be produced during non-peak hours and stored until it is needed. This would allow Iceland to replace almost one fourth of the fossil fuels consumed by vehicles and vessels using its present generating capacity. Iceland could also develop wind power with coastal or offshore facilities. A study indicated that 240 wind power plants could produce the electricity needed to replace fossil fuel from vehicles and fisheries. Other studies suggest that only 17% of Iceland’s renewable energy has been developed. This renewable electricity has been estimated at up to 50 million MWh per year for hydropower and geothermal. This represents six times the current renewable energy capacity. In 1978, Iceland began to develop hydrogen. Support grew in the 1990s with advances in fuel cells. By 1999, Shell, DaimlerChrysler, Norsk Hydro, an Icelandic holding company, Vistorka hf (EcoEnergy) and others created the Icelandic Hydrogen and Fuel Cell Company, now called Icelandic New Energy Ltd. Almost 65% of the population lives near the capital of Reykjavik so a hydrogen infrastructure can be established with a few fueling stations in Reykjavik and nearby connecting roads. In 2003, Iceland opened the first public hydrogen filling station in the world, even though there were no privately owned hydrogen vehicles in the country. Icelandic New Energy has proposed a six-phase plan for hydrogen. Phase 1 started with the opening of a hydrogen fueling station


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in 2003. Fuel cell buses which make up 4% of the city’s bus fleet have been in use in Reykjavik. Phase 2 would replace the Reykjavik city bus fleet with proton exchange membrane (PEM) fuel cell buses. Phase 3 begins the use of PEM fuel cell cars, while phase 4 demonstrates PEM fuel cell boats. Phase 5 replaces the fishing fleet with fuel cell powered boats and in the next phase Iceland sells hydrogen to Europe and elsewhere. The last phase is expected to be completed by 2030-2040. Iceland may start with methanol powered PEM vehicles and vessels. The University of Iceland is involved in research on the production of methanol (CH3OH) from hydrogen combined with carbon monoxide (CO) or CO2 from the exhaust of aluminum and ferrosilicon smelters. This would capture hundreds of thousands of tons of CO2 and CO2 released from these smelters. If this is combined with hydrogen generated from electrolysis using renewable power, Iceland could cut its greenhouse gas emissions in half. RENEWABLE ENERGY TRENDS Renewable energy has many attributes similar to those of fuel cells, including zero emission of urban air pollution, but some believe renewable sales have been slowed in the United States because of their high cost. Actually, renewable technologies have succeeded in meeting most projections with respect to cost. As costs have dropped, successive generations of projections of cost have either agreed with previous projections or have been less. Renewables should become important parts of the power generation mix in the U.S. They represent an important long-term success for government R&D. Government R&D funding for renewables has been exceedingly successful, bringing down the cost of many renewables by a factor of ten in two decades, even though the R&D budget for renewables was cut by 50% in the 1980s and did not rebound to similar funding levels until the mid-1990s. Renewable energy is about 13% of the world’s energy while fossil fuels make up 80% and nuclear power 7%. Wind power has become a major part of power generation in Europe, with 20 to 40% of power loads in parts of Germany, Denmark, and Spain. Photovoltaics has made much progress, but has had to compete with conventional generation. Traditional electricity generation costs

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dropped in the 1980s and 1990s rather than increasing, as had been projected in the 1970s. This occurred while reducing emissions of urban air pollutants. Utilities were also allowed to place barriers in the path of new projects while new technologies typically received little appreciation for the contributions they made in meeting power demand, reducing transmission losses or improving the environment. Nevertheless, the competition from renewables does push the utilities to improve their performance. A major part of the R&D conducted by DOE’s office of Energy Efficiency and Renewable Energy involves energy-efficient technologies that reduce energy bills. More efficient devices include refrigerators, light bulbs, solid-state ballasts for fluorescent lights and improved windows. Many of these products have achieved significant market success. The National Academy of Sciences found that they saved the U.S. $30 billion in energy. The products that were most successful had a good payback combined with similar or superior performance. Solid state ballasts can reduce energy use in half or more while providing a high quality light without the flicker of earlier fluorescents. They can provide a payback of less than two years. MARINE THERMAL ENERGY Ocean thermal energy conversion (OTEC) is growing with several pilot plants under way including the U.S. Navy’s 8-MW plant on the island of Diego Garcia. Along with creating electricity, this plant will desalinate almost 5 million gallons of drinking water every day. OTEC is moving forward in spite of minimal government funding, but the technology needs to prove new pipe and plant designs as it moves from demonstration to commercial plants. OTEC plants will be expensive to build, although they will be inexpensive to run. In addition to drinking water, there are other uses for the cold water such as cooling buildings. In seawater air conditioning, the cool, deep water is run through tubes alongside others containing freshwater, cooling it down. The cooled freshwater then circulates through building’s pipes. On Hawaii’s Big Island, this type of system is, cutting energy use for air conditioning by 80% for the National Energy Laboratory of Hawaii Authority (NELHA). This represents a savings


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of $30,000 per month. Maintenance is low since the system is so simple. Makai Ocean Engineering is also implementing a seawater air conditioning system for cooling areas in downtown Honolulu. Similar systems are used in Stockholm, which uses water from the Baltic Sea, and Toronto and Cornell University, which use cool water from nearby lakes. The deep water is also rich in nutrients, such as phosphates and nitrates, and its free from pollution and pathogens that can affect sea life near the surface. The deep water is used at the NELHA site to raise lobsters, abalone and algae. Using the deep-water tubes to cool the soil would also allow temperate crops to grow in tropical areas. This aggregate of water, energy, and food could help support development on remote tropical islands. In areas such as in the Gulf of Mexico and off the coast of Indonesia, OTEC plants may rest on platforms similar to those used for offshore oil drilling. In these areas, there is warm surface water and cold deep water close enough to shore so the plants could produce electricity and send it onshore, using power cables up to 100 kilometers long. This could help to power cities such as New Orleans and Tampa, Florida. Taiwan and the Brazil coast are also potential sites, along with the Philippines and Papua, New Guinea. OTEC may use large factory-like vessels, with long cold-water pipes. They could supply electricity for energy-intensive products such as ammonia for fertilizer. This is now made from fossil fuels using the Haber-Bosch process and it requires about 2 percent of the world’s energy use. Ammonia can also be burned as a fuel or used as a source of hydrogen since each ammonia molecule contains three hydrogen atoms. Just a decade ago, an oil rig in 500 feet (150 meters) of water was considered to be deep, now oil rigs are going down 15,000 feet (4,500 meters). Much of the technology that oil drilling uses will be utilized by OTEC. This includes newer materials and the building of offshore platforms and mooring them to the sea floor. The oil industry may also provide investment. The electrical power potential of OTEC is estimated at 3 to 10 terawatts which is up to five times the electric power the world now requires. But, building OTEC plants will be a major challenge, since they have never been built at the sizes that would be needed to exploit the resource. The biggest challenge may be scaling up the deep-water

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pipeline. Makai Ocean Engineering puts the minimum commercially viable size at 100 megawatts and the largest deep-water pipe used for OTEC is 1.4 meters in diameter. A 100-megawatt plant would need a pipe diameter of 10 meters or equivalent. Lockheed Martin plans to build such a pipe with proprietary composite material, which is light and strong but has enough flexibility to handle ocean currents. The composite material would be cheaper than the plastic or steel pipes that have been used in OTEC plants before. OTEC may also have other benefits besides clean energy, which is potentially free from carbon dioxide emissions and might even be able to reduce these emissions. The nutrient-rich water that is brought up to the ocean surface could make the open ocean bloom with microbes. These blooms would take up carbon dioxide from the water surrounding them, allowing more carbon in the air to dissolve into that water. If the first blooms are plankton followed by organisms known as cyanobacteria, then they could help draw carbon dioxide out of the air according to one hypothesis. However, this would cool down the water near the surface, which may disrupt the ocean ecosystems. The OTEC plants built so far, and those proposed in the near term, instead send the cool water stream back to the deep, to avoid affecting ocean temperatures. Apart from the issue of ocean temperatures, many are doubtful if artificial upwelling will really work, since it may only sequester carbon under perfect conditions. Upwelling could also release the carbon dioxide in the deep water, allowing it to escape into the atmosphere. The deep water has about 15 percent more carbon dioxide dissolved in it than surface waters. But, this release would be small compared to that from fossil fuels. Even if the carbon dioxide escaped, OTEC plants would produce a fraction of what a fossil fuel plant would produce. WAVE ENERGY TRENDS Wave energy is a promising renewable source in maritime countries. As a wave travels forward in an up-and-down motion, its height is an indication of its power. Ocean waves could be providing large amounts of power for maritime countries. The energy potential has been estimated as being as much as 4,000 gigawatts (GW). The sea also has the potential to destroy wave-energy stations, but several nations


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have been designing more rugged small-scale wave power stations. A wave power station must be able to withstand the power of the largest waves without being damaged. Two operating wave power stations, one in Scotland and one in Norway, have already been damaged by high waves. Wave energy was considered at the time of the French Revolution, but there has not much progress in turning this motion into useful energy until the last quarter century. A recent advance is the oscillating water column (OWC). This is a column that sits on the seabed and admits the waves through an opening near the base. As the waves rise and fall, the height of the water inside rises and falls pushing air in and out of a turbine which drives a generator. The turbine spins in the same direction regardless of the direction of the air flow. Norway built a wave energy station on the coast near Bergen in 1985. It combined an OWC with a Norwegian device called a Tapchan (TAPered CHANnel). The waves move up a concrete slope where they fill a reservoir. As the water flows back to the ocean, it drives a turbine generator. Wave power generators ranging from 100 kilowatts (kW) to 2 megawatts (MW) are now in use in more than a dozen countries. Scotland had an 75-kW OWC on the island of Islay for 11 years. This has been replaced by a 500-kW unit with plans for a 2-MW seagoing device called the Osprey. Portugal has an OWC off the island of Pico in the Azores. An American company has a 10-MW system on buoys 3 kilometers off the south coast of Australia. China, Sweden and Japan are also involved with wave energy. Wave energy is capital-intensive with most of the costs for construction. Major breakthroughs are in sight and wave electricity should be part of the renewable mix in many countries before long. Permitting and licensing energy projects is not always easy but in the marine environment for both fossil and renewable energies the process can be much more difficult. Regulation is complex and that complexity is impeding technological progress. There are many layers of local, state and federal regulation and the lack of regulatory experience among ocean energy companies may also be hindering technological progress. A related technique used to harness energy involves the difference between sea levels. In Egypt, water running through an underground canal linking the Mediterranean to the El-Qattar depression

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could be used to generate electricity. In Israel, the same principle could be used in a canal between the Mediterranean and the Dead Sea which would descend 400 meters. SOLAR SATELLITES Solar power satellites (SPSs) promised to provide cheap, clean power, but there has been very little progress on the concept in over 30 years. A 2004 conference on space based solar power generation held in Granada, Spain, provided progress reports from groups in Europe, the U.S., and Japan who are working on concepts and plans for building solar power plants in orbit that would beam power down for use on Earth. These concepts include building parts of the Solar Power Satellite from lunar and asteroidal materials. The conference focused the technological and political developments required to construct and employ a multi-gigawatt power satellite. It provided perspectives on the cost savings achieved by using extraterrestrial materials in the construction of the satellite. The Sun is constantly sending energy to the Earth, but any point on land is in the dark half of the time and during the day clouds can also block sunlight and power production. In orbit, a solar power satellite would be above the atmosphere and could be positioned so that it received almost constant direct sunlight. There is no air in space, so the satellites receive intense sunlight, unaffected by weather. In a geosynchronous orbit an SPS would be illuminated over 99% of the time. The SPS would be in Earth’s shadow for a few days at the spring and fall equinoxes. This would be for a maximum of an hour and a half late at night when power demands are at their lowest. In some ways, the SPS is simpler than most power systems on Earth. This includes the structure needed which in orbit can be considerably lighter due to the lack of weight. Another advantage is that waste heat is re-radiated back into space, instead of warming the biosphere as occurs with conventional sources. Some energy is lost in transmitting power to stations on the Earth, but this would not offset the advantages of an orbiting solar power station over ground based solar collectors. The concepts of solar power satellites were worked up in the


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1960s, but there were a number of problems impeding them. The SPS concept was considered impractical due to the lack of an efficient method of sending the power down to the Earth. In 1974, Peter Glaser was granted a patent for his method of transmitting the power to Earth using microwaves from a small antenna on the satellite to a much larger one on the ground, known as a rectenna. NASA granted a broader study in 1972 they found that while the concept had several major problems, mainly putting the required materials in orbit and the lack of experience in space, it showed enough promise to merit further investigation and research. Most major aerospace companies then became briefly involved in some way, either under NASA grants or on their own. At the time the needs for electricity were soaring, but when power use leveled off in the 1970s, the concept was shelved. Recently, interest in the concept has grown and at some point the construction costs of the SPS become favorable due to the low-cost delivery of power and the rising costs of electricity. Continued advances in material science and space transport reduce the projected costs of the SPS. Using solar panels on Earth is far less costly, so much of the present focus on solar energy is not on satellite systems. A major barrier is the high cost of launching. Launch costs need to come down before generating solar power in space makes economic sense. There may not be a financial reason to start building a solar power system unless we include the environmental costs of our current non-renewable sources of energy. A solar power system must compete with other options. Among the barriers holding back solar power satellites are the political will and insight to make the money available for development. In areas with plenty of sun and available land, satellites may not compete with generating solar power locally. There would be more demand for beaming solar power to locations that could not generate it otherwise. Microwaves broadcast from the SPS would be received with about 85% efficiency. Rectennas would be several kilometers across and crops and farm animals could be raised under the rectenna, since the thin wires used only slightly reduce sunlight. A satellite antenna of between 1 and 1.5 kilometers in diameter and a ground rectenna around 14 kilometers by 10 kilometers would allow the transfer of 5 to 10 gigawatts of power.

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One concept is to build the SPS in orbit with materials from the Moon. Launch costs from the Moon are about 100 times lower than from Earth, due to the lower gravity. This concept will work if the number of satellites to be built is near several hundred. Otherwise, the costs of setting up the production in space and mining facilities on the Moon are as high as launching from Earth. The use of microwave transmission of power has been the most controversial item in SPS development, but the safety of anything which strays into the beam’s path has been misrepresented. The beam’s center is the most intense region and it is far below dangerous levels of exposure even if prolonged indefinitely. An airplane flying through the beam protects its passengers with a layer of metal, which will intercept the microwaves. Over 95% of the beam will fall on the rectenna. The remaining microwaves will beat low concentrations well within the standards for microwave emissions. The intensity of microwaves at ground level in the center of the beam is likely to be comparable to that used by mobile phones. Outside of the rectenna area the microwave levels rapidly drop off and nearby objects should be completely unaffected. But the long-term effects of beaming power through the ionosphere in the form of microwaves has yet to be studied. The use of microwave beams to heat the oceans has been studied. Some research suggests that microwave beams would be capable of deflecting the course of hurricanes. NASDA (Japan’s national space agency) has been researching this area and plans to launch an experimental satellite of 10-kW to 1-MW. Japan plans to assemble a spacebased solar array by 2040. THE FUTURE FOR ENERGY Shell Energy has conducted extensive future energy studies. From 1975 to 2000, the world gross domestic product (GDP) more than doubled while primary energy use grew by almost 60%. From 2025 to 2050 in one Shell future vision, the GDP almost doubles, but primary energy use grows by only 30%. This means that energy use would have to become twice as efficient. This future vision has natural gas consumption increasing through 2025 and then dropping due to supply problems.


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As renewable energy grows, by 2020 a variety of renewable sources supply a fifth of the power in many developed countries. By 2025 biotechnology, materials advances and sophisticated power grid controls provide a new generation of renewable technologies. Its spread is aided by advances in storage technology. Oil becomes limited by 2040, but more efficient vehicles using liquid biofuels from biomass farms solve this problem with some help from super clean diesel fuel made from natural gas. By 2050 renewables supply a third of the world’s primary energy and most incremental energy. These are major increases in renewable energy and energy efficiency. Today, renewables supply about 13% of the world’s energy, but in the U.S. renewables now only provide less than 1% of electric power generation.

BOTTLED FUEL Another view of the future Shell sees is a technological revolution based on hydrogen. It is based on the development of bottled fuel for fuel cell vehicles. Two liter bottles hold enough fuel to drive forty miles and are distributed like bottled water through existing distribution channels including vending machines. A package of eight bottles can provide 320 miles of driving. Consumers would get their fuel anywhere and at any time. By 2025, in this scenario, one-quarter of fleet vehicles use fuel cells, which make up half of new sales. Renewables grow quickly after 2025. Almost a billion metric tons of CO2 are sequestered in 2025. Then, hydrogen is produced from coal, oil and gas fields, with the carbon dioxide extracted and sequestered cheaply at the source. Largescale renewable sources and nuclear energy are producing hydrogen by electrolysis by 2030. Global energy use nearly triples from 2000 to 2050. Worldwide nuclear power production almost triples during this time. Natural gas use is large in this scenario, and its use more than triples over these 50 years. Renewable energy is also abundant. By 2050, CO2 sequestration is over 8 billion metric tons per year, one-fifth of emissions. The world is sequestering more CO2 than the United States produces now from coal, oil and natural gas use.

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Shell stresses that these are not predictions but conception exercises. Bottled fuel would have to be like liquid propane distribution today, but propane is liquid at a much higher temperature and lower pressure than hydrogen. The form of hydrogen contained would not be high-pressure storage, since that would be bulky, heavy, and certainly dangerous to distribute by vending machine. Metal hybrids would be even heavier. Chemical hybrids would be a possibility. Liquid hydrogen could not be dispensed in small, portable, lightweight bottles with today’s technology. But, in the future something that could be easily used by the consumer to fuel a hydrogen vehicle would be a major breakthrough. The Shell studies imply that fuel cell sales will start with stationary applications to businesses that are willing to pay a premium to ensure highly reliable power without utility voltage fluctuations or outages. This demand helps to push fuel cell system costs below $500 per kW, providing the era of transportation use which drives costs down $50 per kilowatt. But, can the high-reliability power market really drive transportation fuel cell demand and cost reductions, especially for proton exchange membrane (PEM) fuel cells? By 2025 the world is sequestering 1 billion metric tons of CO2 per year while simultaneously producing hydrogen and shipping it hundreds of miles for use in cars. This is equivalent to sequestering the CO2 produced by more than 700 medium-sized generation plants, about two-thirds of all coal-fired units in the U.S. today. The Department of Energy (DOE) has started the billion-dollar, FutureGen project to demonstrate a 275-megawatt prototype plant that cogenerates electric power and hydrogen and sequesters 90% of the CO2. The goal of the project is to validate advanced coal near zero emission technologies that by 2020 could produce electric power that is only 10% more costly than current coal generated power. This type of advanced system would grow to be 700 worldwide according to the Shell studies. Advances can occur quickly in technology, these would be needed in hydrogen production and storage, fuel cells, solar energy, biofuel production and sequestration. Government and industry would need to spend hundreds of billions of dollars to bring these technologies to the marketplace. Those in industry commercializing these advances would reap the benefits while those with older technologies would be


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left behind. Political obstacles to tripling nuclear power production would need to be set aside. Natural gas supplies would need to be increased. Another problem is cost-effectiveness, hydrogen must be able to compete with alternative strategies including more fuel-efficient internal combustion engine vehicles. The Shell studies estimate that the cost in the U.S. to supply 2% of cars with hydrogen by 2020 is about $20 billion. In the near term, hydrogen is likely to be made from fossil fuel sources. The annual operating costs of fuel cell power are likely to be higher than those of the competition in the foreseeable future. There are those who believe that global warming is the most potentially catastrophic environmental problem facing the nation and the planet this century and it is the problem that requires the most urgent action. They may advocate that spending money on building a hydrogen infrastructure would take away resources from more costeffective measures. But, a hydrogen infrastructure may be critical in achieving a major CO2 reduction in this century. In the first half of the 21st century, alternative fuels could achieve greater emissions and gas savings at lower cost, and reducing emissions in electricity generation. This is true for natural gas as well as renewable power in the near future. A natural gas fuel cell vehicle running on hydrogen produced from natural gas may have little or no net CO2 benefits compared to hybrid vehicles. Natural gas does have major benefits when used to replace coal plants. Coal plants have much lower efficiencies at around 30% compared to natural gas plants at 55%. Compared with natural gas, coal has nearly twice the CO2 emissions, while gasoline has about one third more CO2 emissions than natural gas. In the United States, vehicle emissions other than CO2, have been declining steadily. Noxious emissions have been reduced by federal and state regulations and the turnover of the vehicle fleet. As vehicles go out of service, they are replaced with newer and cleaner vehicles. Many new cars are called near zero emissions by their manufacturers. Hydrogen fuel cell vehicles will have almost no emissions besides some water vapor and would be much cleaner. The U.S. has been building new natural gas power plants because they are more efficient and cleaner. By 2003, the nation had more than 800 gigawatts (GW) of central station power generation. One giga-

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watt is 1,000 megawatts (MW) and is about the size of a very large existing power plant or three of the newer, smaller plants. Almost 145 gigawatts were added from 1999 to 2002 and almost 96% of this was natural gas. This included 72 gigawatts of combined-cycle power and 66 gigawatts of combustion turbine power which are used generally when demand is high. The Energy Information Administration predicts an increase in coal generated power. The EIA estimates that from 2001 to 2025, about 75-GW of new coal plants will be built. Over 90% of the coal plants are projected to be built from 2010 to 2025. The EIA forecast also predicts that existing coal plants will be used more often. From 2001 to 2025, the EIA estimates a 40% increase in coal consumption for power generation. This could increase U.S. greenhouse gas emissions by 10%. The rising demand for natural gas already affects North American supplies and has pushed up prices. Canada is an important source of our imported natural gas, but it has little capacity left to expand its production. While not as energy-intensive a process as liquefying hydrogen, cooling natural gas to a temperature of about -260°F and transporting the resulting liquid has an energy penalty of up to 15%, according to the Australian Greenhouse Office. From a global standpoint, it might be better to use foreign natural gas to offset foreign coal combustion than to import it into the United States in order to turn it into hydrogen to offset domestic gasoline consumption. The projected growth in global coal consumption could be an even bigger CO2 gas problem than the projected growth in U.S. coal consumption. By 1999, there were over 1,000-GW of coal power generating capacity around the world. About one third of this is in the United States. From 2000 to 2030, more than 1,400-GW of new coal capacity may be built, according to the International Energy Agency of which 400-GW will be used to replace older plants. These plants would need to use carbon capture equipment or their estimated carbon emissions could equal the fossil fuel emissions from the past 250 years. Carbon capture and storage (CCS) is an important research area but widespread commercial use may be years away. Many of these plants may be built before CCS is ready and we will need to use our electricity more efficiently to slow the demand for such power plants, while building as many cleaner power plants as possible. Natural gas is far more cleaner for this power than coal. Generating hydrogen with renewables may be needed in order to


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avoid building coal-fired plants. More electricity from renewable power would reduce the pressure on the natural gas supply and reduce prices. The United States could have essentially carbon-free electricity before 2050 with hydrogen fuel playing a key role. Some studies indicate that higher carbon savings can be achieved by displacing electricity from fossil fuel power stations. Abundant renewable power and the practical elimination of CO2 emissions from electricity generation could take 30 years. The United Kingdom’s power generation mix has less CO2 emitted per megawatt-hour by one third compared to U.S. The U.K. has moved away from extensive coal power generation in the past few decades and is aggressively pushing renewable energy and cogeneration. Nuclear power is quietly reappearing in the United States and around the world. Major U.S. utilities have applied for site permits for new reactors, and interest is also growing through Europe. The nuclear plants now operating in the U.S. are light water reactors, which use water as both a moderator and coolant. These are sometimes called Generation II reactors. In these Generation II Pressurized Water Reactors, the water circulates through the core where it is heated by the nuclear chain reaction. The hot water is turned into steam at a steam generator and the steam is used by a turbine generator to produce electric power. The Generation III reactors Evolutionary Pressurized Reactor has expanded safety features such as 2 separate 51-inch-thick concrete walls with the inner one lined with metal. Each of the walls is strong enough to withstand the force of a large commercial airplane. The reactor vessel is on top of a 20-foot concrete slab with a leaktight core catcher. In the event of a meltdown the molten core would collect there and cool down. Four safeguard buildings are also used with independent pressurizers and steam generators. Each of these buildings is able to provide emergency cooling for the reactor core. A dozen utilities around the country have started the process of applying to build nuclear plants. These would be Generation III and III+ designs. In 2000, 10 countries including the U.S. evaluated more than 100 Generation IV designs and after 2 years picked six. Fourth generation nuclear plants replace the water coolants and moderators to allow higher temperatures with the potential to create hydrogen as well as electric power. Tests show that electrolysis is almost twice as efficient

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at the high temperatures. One of the Generation IV designs is a melt-down proof pebblebed reactor. It uses grains of uranium encased in balls of graphite for fuel. Helium gas is heated as it circulates through a vessel of the pebbles. It is then used to turn a turbine generator. A heat exchanger is used to transfer heat from the helium to produce hydrogen. This type of reactor is fail-safe, if the cooling system fails the reactor shuts down on its own. The hot helium gas is inert, so leaks are not radioactive. The heat could also be used to refine shale oil or desalinate water. Each day about 3,000 pebbles are removed from the bottom as some fuel is spent from the 360,000 pebbles, so there is no need to shut down the reactor to replace fuel. The pebbles are fireproof and extremely difficult to turn into weapons. If the fuel gets too hot, it begins absorbing neutrons, shutting down the reactor. A modular 250-MW reactor of this type could be constructed offsite and then shipped by truck or train. This could shorten construction time by 2 years with corresponding cost savings. China and South Africa plan to build full-scale prototypes. Three of the Generation IV designs under consideration are fast breeder reactors. The fast neutrons in the core have no moderator to slow them down. When these fast neutron collide with fuel particles, they can generate more fuel. These reactors use gas, sodium or molten lead for cooling. The burning of coal and other fossil fuels is driving the concerns over climate change, but nuclear energy provides an alternative. The risks of atomic piles are manageable beside that of fossil fuels. Unlike global warming, radiation containment, waste disposal, and nuclear weapons proliferation are more manageable. The latest generation III+ reactors should be more fuel-efficient, use passive safety technologies, and could be cost-competitive. Four crucial factors could help to ease the leap from a hydrocarbon to a nuclear era: regulating carbon emissions, revamping the fuel cycle, revitalizing innovation in nuclear technology, and replacing gasoline with hydrogen. This push is due to several factors and the most significant is the global-warming question. Large companies are now supporting greenhouse gas reduction and several of the world’s major environmentalists now support nuclear power, noting that with the threat of warming, an emission-free power source is critical.


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HYDROELECTRIC POWER TRENDS Among the renewable resources used in the U.S. since the 1930s, hydroelectric power, electricity generated by water-driven turbines, is the most important. During the 1930s, great dams were built across major waterways throughout the country, and about 40% of all U.S. electricity was generated by hydroelectric facilities. Today, water power accounts for almost 10% of America’s total electric energy, but it is about 95% of all electricity generated from renewable resources. The growth of hydroelectric power has slowed during the last few decades since many of the nation’s most promising sites for dams are occupied. The Columbia River system alone has over 190 dams. The electricity generated by these and other dams costs approximately half as much as that generated from more traditional sources. Environmental problems at each dam site include changes in reservoir water levels which affect plants and wildlife. Dams can lower downstream water temperatures when the cold water drawn from the bottom of the dams passes through the generators and is released downstream. The cold temperature can affect the life cycle of plants, insects, fish, birds and mammals. If the licensing procedures for new dams could be eased, hydroelectric power could become an even larger source of renewable energy. Small hydro projects vary in size but a generating capacity of up to 10 megawatts (MW) is generally accepted as the upper limit although 25-MW and 30-MW projects have been done in Canada and the U.S. Most hydroelectric projects are very large, the plant at the Hoover Dam is rated at 2,074 megawatts. Small hydro can be subdivided into mini-hydro, usually less than 1,000-kW and micro-hydro which is less than 100-kW. Micro-hydro installations may also provide multiple uses. Microhydro projects in rural Asia have incorporated processing facilities such as rice mills alongside power generation. Old water mills have been rebuilt as small turbines of 5-kW or less for domestic requirements in developing countries. A small, seasonal stream of 60-130 gallons per minute can generate about 5 kilowatt hours (kWh) per day in the dry season and about 10-kWh in the wet season. Small hydro plants can be connected to conventional electrical distribution networks as a source of low-cost renewable energy. They may be built in isolated areas that would be uneconomical to serve

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from a network, or in areas where there is no electrical distribution network. Since small hydro projects usually have minimal reservoirs and construction work, they are viewed as having a relatively low environmental impact compared to large hydro. The environmental impact depends on the stream flow and power production. Reduced diversion helps the river’s ecosystem, but reduces the hydro system output. During 2008 small hydro installations grew by 28% over 2005 to increase the total world small hydro capacity to 85 gigawatts. Over 70% of this was in China with 65-GW, followed by Japan with 3.5-GW, the United States with 3-GW and India with 2-GW. China plans to electrify 10,000 more villages by 2010 under the China Village Electrification Program using renewable energy, which includes small hydro and photovoltaics. The 1895 hydroelectric plant near Telluride, Colorado, is an example of a small hydro development on a scale serving a small community or industrial plant. Other examples of small installations are the Bario Asal & Arur Layun Micro-Hydro Community Project in the Kelabit Highlands, Sarawak, Malaysia; St Catherine’s, a National Trust site near Windermere, Westmorland, United Kingdom; the Green Valleys Project, Brecon Beacons National Park, Wales, United Kingdom; Ames Hydroelectric Generating Plant in Colorado; Snoqualmie Falls in Washington; and the Childs-Irving Hydroelectric Facilities in Arizona. Small hydro is often developed using existing dams or through the development of new dams whose primary purpose is river and lake water-level control, or irrigation. Old, abandoned hydro sites may also be re-developed, sometimes using substantial parts of the installation such as penstocks and turbines or just re-using the water rights for an abandoned site. Many firms offer standard turbine generator packages in the range of 200-kW to 10-MW. These are called water to wire packages and simplify site development of the site since one vendor supplies most of the equipment supply. Synchronous generators are often used, but small hydro plants connected to an electrical grid can use more economical induction generators. Micro-hydro plants can use special purpose turbines or centrifugal pumps connected in reverse to act as turbines. These units do not have the best hydraulic characteristics when operated as turbines but their low cost makes them attractive.


291

Small hydro generating units may require the diversion of water around the turbine, since the project may have no reservoir to store unused water. For micro-hydro systems feeding small loads, a resistor bank may be used to convert electrical energy as heat during periods of low demand. Other small hydro systems may use tidal energy or propellertype turbines immersed in flowing water to extract energy. Tidal systems may require water storage or electrical energy storage to level out the intermittent although predictable flow of power. Small hydro projects usually have minimal environmental and licensing procedures, the equipment is usually standard and simple, and construction is often small so the project may be developed rapidly. The small size of equipment also makes it easier to transport to remote areas. SMALL WIND ENERGY In 2009 the economic conditions were pushing small wind energy projects. Utility-scale wind project developers found themselves unable to obtain the financing needed for large wind farms. The economic climate and falling turbine, steel and labor prices caused small and mid-scale wind energy projects to flourish. In 2008 almost 9,000-MW were installed in North America and in 2009 the conditions were right for even more small wind development. General Electric and Vestas turbines that were going into large wind farms were now available for smaller projects. In 2008 manufacturers pushed large quantities of turbines but then became eager to sell to colleges and small developers at prices that were 10-15 percent lower. In the past, many utility- grade turbine manufacturers were not interested in selling small quantities, but flat inventories pushed them toward smaller markets. Small wind projects range in size from 100-kW to 30-MW. They typically serve schools, farms, rural villages, businesses and municipal utility companies. Since these installations can access funding from various sources, they are less vulnerable to a credit crisis than large-scale wind farms. A small rural Iowa utility, Waverly Light and Power financed two 900kW turbines with Clean Renewable Energy Bonds (CREBs). These are tax-credit bonds that can be used to finance renewable energy projects. The bonds provide, in essence interest-free financing for clean

292


energy projects. The 2009 stimulus bill provides up to $1.6 billion in new CREBs but to take advantage of them, bondholders must have a tax liability. Universities may have other means for raising funds for small wind projects. At Appalachian State University in Boone, North Carolina, students will pay an additional $5 fee per semester towards the installation of a 100-kW wind turbine. Carleton College in Northfield, Minnesota, paid for the installation of a 1.65-MW turbine from its operating budget with a second turbine paid for by a donor. In small projects a major concern is operation and maintenance (O&M). Qualified technicians must be available to service the machines when needed without large transportation costs or delays. If a project is too small to have its own service and maintenance crew, then the operating costs per turbine become higher. If a smaller project can use the same type of turbine as a larger project nearby, the crew can travel over and service their machines. In the past, this was not always an option for smaller project developers, but now they have a variety of utility grade turbines available. High O&M costs can be a problem for schools and other potential small wind projects. Schools may be interested in doing more wind projects, but they are concerned about the costs of mechanical failures. Waverly Light and Power experienced installation problems with the second turbine during installation in February 2009. The blades and generator collapsed as the 50 ton structure fell 200 feet to the frozen ground when the blades of the turbine caught the wind and started rotating to a speed of 60-rpm. The hub housing the generating components of the turbine and the structure’s three 177 foot blades collapsed after spinning for hours. When a gust of wind caught the blades prematurely, prior to the installation, they were not turned in a direction that would have protected them until installation was complete. Many projects are expected to be built from late 2010 to 2012. Third-party financing is popular for many customers in order to reduce the O&M risk and up-front capital costs. NexGen started a project at a McGuffey, Ohio, high school for two Northern 100-kW turbines. The project was possible because of third-party funding. Technology advances in direct-drive wind turbines have reduced maintenance concerns since the lack of a gearbox and fewer moving parts makes turbines more dependable. Appalachian State University


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and Waverly Light and Power have direct-drive turbines with no gearbox and only two bearings in the drive train instead of 50. Eliminating the gearbox removes a major maintenance concern and improves the reliability of the machine since many failures have occurred in gear boxes which are the weakest part of a turbine. Lower commodity prices and technology advances allowed Northern Power Systems to lower the cost of its direct-drive permanent magnet turbines considerably. The company currently has a 100kW turbine that is suitable for schools, remote villages, farms and businesses. Direct-drive technology also allows energy to be generated at lower wind speeds, increasing the energy potential of many sites. Government support for wind energy through net-metering laws and extension of the renewable energy production and investment tax credits has provided stability to the industry, while stimulus funding gave it a boost. Along with the $1.6 billion in CREBs that became available to state and local governments, municipal utility companies and rural electric cooperatives, some state and local governments have grant or rebate programs available. These incentives make wind projects more attractive, along with the lower commodity and labor costs. Steel prices have come down so much that towers are now $100,000 less. Due to the economic crash in late 2008, steel prices have come down at least 50 percent. The cost of labor has also come down because contractors are looking for work. While these factors also help large wind projects, financing difficulties have made it harder for large wind developers to take advantage of them so smaller projects with greater access to capital have grown. The large-scale wind industry is inclined to return to growth as liquidity returns to the market. With the three-year extension of the production tax credit and the investment tax credit, more wind farms should be built. Massachusetts has a pending Wind Energy Siting Reform Bill that may affect property rights by a transfer of power from towns, legislators, and the courts to the executive branch where the governor would have more power to determine the future landscape for wind projects. The Xcel Energy 100 megawatt wind farm near Austin, Minnesota, was the first wind farm in Minnesota owned by Xcel Energy. The farm consists of 67, 1.5 megawatt wind turbines on approximately 40 square miles. The site for the wind farm is capable of supporting up to

294


200 megawatts of wind generation. In Minnesota, Xcel Energy currently receives approximately 775 megawatts of electricity from wind and has plans to add another 500 megawatts of wind power under the Community-Based Energy Development (C-BED) program. The utility estimates that it will need to add between 3,000 and 3,400 megawatts of new wind generation to its Minnesota system by 2020 to meet the renewable energy standard which was passed in 2007. South Africa launched its first commercial wind farm in 2007. The wind farm, at Darling near Cape Town, has a capacity of 5.2-MW, and consist of four 1.3-MW turbines. There are plans to install another 16 turbines. Previous wind farms in South Africa have consisted only of small pilot projects. The new development is modest by international standards, but it represents an important step in tapping South Africa’s renewable energy potential and more growth can be expected in the future. The City of Cape Town has set a target of generating 10% of energy from renewables by 2020, while the Western Cape government has set a target of 15%. Germany, with a land mass of one fifth that of South Africa, has over 20,000-MW of wind installed, which represents about half of South African electricity demand. Along with its wind potential, the Western Cape is a prime area for wave power generation, with companies such as UK-based Ocean Power Delivery. The new wind farm has required almost 11 years to obtain all the necessary permits and consents. The Darling Independent Power Producer company along with the government’s Central Energy Fund each one third of the equity in the new wind farm, with another third owned each by the Bank of South Africa and the Danish development agency, DANCED. The World Bank is aiming to increase its funding for renewable energy projects by up to 40%, increasing the money available from $7 billion over the last three years to $10 billion over the next three years. GEOTHERMAL POWER Power can be extracted from heat stored in the earth. This geothermal energy comes from the original formation of the planet, radioactive decay of minerals and from solar energy absorbed at the


295

surface. It has been used for space heating and bathing since Roman times, but is now used for generating electricity worldwide. Geothermal plants had a generating capacity of almost 10-GW by 2007 and generate about 0.3% of global electric power. Another 30-GW of geothermal heat is used for district heating, space heating, spas, industrial processes desalination and agricultural use. Geothermal power is cost effective, reliable, and environmentally friendly, but has been limited to areas near tectonic plate boundaries. Recent technological advances have greatly expanded the range and size of these resources. Geothermal wells release greenhouse gases trapped deep in the earth, but these emissions are much lower per energy unit than fossil fuels. The first geothermal generator was tested in 1904, at the Larderello dry steam field in Italy. In 1946 the first geothermal heat pump was successfully implemented and the first residential version was built two years later. Geothermal became popular in Sweden as a result of the 1973 oil crisis and has been growing slowly since then. The 1979 development of polybutylene pipe greatly aided the heat pump’s commercial viability. By 2004, there were over a million geothermal heat pumps installed worldwide providing 12-GW of thermal capacity. Each year, about 80,000 units are installed in the U.S. and 27,000 in Sweden. In 1960, Pacific Gas and Electric began operation of the first successful geothermal electric power plant in the United States at The Geysers in California. The original turbine lasted for more than 30 years. In 2008, the plant produced over 725-MW of power, making it the largest geothermal development in the world. A 2006 report by the Massachusetts Institute of Technology (MIT) estimated that an investment of $1 billion for research and development over 15 years would allow the development of 100-GW of generating capacity by 2050 in the U.S. alone. The MIT report estimated that with technology improvements geothermal could provide all the world’s present energy needs for several millennia. Most geothermal wells are less than 3-km deep. The upper estimates of geothermal resources assume wells as deep as 10-km. This depth is now possible in the petroleum industry, although it is expensive. Exxon has drilled an 11 kilometre (7 mi) hole at the Chayvo field, Sakhalin. Depths greater than 4 kilometres (2 mi) usually involve drilling costs of tens of millions of dollars. The technological challenges

296


for geothermal power are to drill wide bores at low cost and to break larger volumes of rock. Geothermal power is considered to be sustainable since the heat extraction is small compared to the Earth’s heat content, but extraction can still cause local depletion. Individual wells may cool down or run out of water. The three oldest sites, at Larderello, Wairakei, and the Geysers have all reduced production from their peak output. These plants may have extracted energy faster than it was replenished from greater depths, or the aquifers supplying them may be depleted. If production is reduced, and water is reinjected, these wells might recover their full capability. The Lardarello field in Italy has operated since 1913 and the Wairakei field in New Zealand since 1958 while The Geysers field in California opened in 1960. HYDROTHERMAL POWER SYSTEMS There are three geothermal power plant technologies being used to convert hydrothermal fluids to electricity. These are dry steam, flash, and binary cycle. The type of conversion used depends on the state of the fluid (steam or water) and the temperature. Dry steam power plants systems were the first geothermal power generation plants built. They use the steam from the geothermal reservoir as it comes from wells, and send it directly through the turbine/ generator units. Dry steam technology is used at The Geysers in northern California. These plants emit only excess steam and very minor amounts of gases. Flash steam plants are the most common type of geothermal power generation plants in operation. They use water at temperatures greater than 360°F (182°C) that is pumped under high pressure to the generation equipment at the surface. Binary cycle geothermal power generation plants differ from the others in that the water or steam from the geothermal reservoir never comes in contact with the turbine/generator units. In flash plants, fluid is sprayed into a tank held at a much lower pressure than the fluid, causing some of the fluid to rapidly vaporize, or flash. The vapor then drives a turbine/generator. If any liquid remains in the tank, it can be flashed again in a second tank to extract more energy.


297

Most geothermal areas contain moderate-temperature water below 400°F. Energy is extracted from these fluids in binary cycle power plants. Hot geothermal fluid and a secondary or binary fluid with a much lower boiling point than water pass through a heat exchanger. Heat from the geothermal fluid causes the secondary fluid to flash to vapor, which then drives the turbines. Since this is a closed-loop system, virtually nothing is emitted to the atmosphere. Moderate-temperature water is the more common geothermal resource, and most geothermal power plants in the future will be binary cycle plants. THE FUTURE OF GEOTHERMAL Steam and hot water reservoirs are just a small part of the total geothermal resource. The Earth’s magma and hot dry rock can provide cheap, clean, and almost unlimited energy when we develop the technology to use them. In the meantime, moderate-temperature sites running binary cycle power plants will be the most common geothermal producers. This is estimated at 15,000 megawatts of new capacity in the next decade. Russia demonstrated the first binary cycle power plant in 1967. In 2006, a binary cycle plant in Chena Hot Springs, Alaska, went online, producing electric power from a fluid temperature of 57°C. In 2004, El Salvador, Kenya, Philippines, Iceland and Costa Rica all generated more than 15% of their electric power from geothermal sources. In 2005, contracts were placed for an additional 0.5-GW of power in the U.S. and there were plants under construction in 11 other countries. Twenty-four countries generated a total of 56,786 GW-hours (GWh) of electricity from geothermal power in 2005. This is growing by 3% annually with more and improved plants. Geothermal power does not depend on variable sources of energy, like wind or solar so its capacity factor can reach 90%. The global average was 73% in 2005. The development of binary cycle power plants and improvements in drilling and extraction technology allows enhanced geothermal systems over a wider geographical range. Demonstration projects are underway in Germany, France and Australia. Most renewables are on a decreasing cost curve, while non-renewables are on an increasing cost curve. In 2009, costs became comparable between wind, nuclear, coal, and natural gas, but CSP (concen-

298


trating solar power) and PV (photovoltaics) remain somewhat higher. Some renewables have had additional costs to cover increased grid interconnection to allow for the diversity of weather and loads, but these have been low in Europe making wind energy cost about the same as conventional fossil power. Global geothermal heat pump capacity has grown by 10% annually. The direct application for heating is more efficient than power generation and requires much lower temperatures. In areas of natural hot springs, the heated water can be piped into radiators. If the ground is hot but dry, earth tubes or heat exchangers can be used without a heat pump. Seasonal ground temperature variations cease entirely below 10 meters. Heat may then be extracted with a geothermal heat pump more efficiently than by conventional furnaces. In Iceland hot water from geothermal plants is piped below the pavement to melt snow. District heating applications use networks of piped hot water to heat buildings in whole communities. Geothermal desalination has also been demonstrated. At the Krafla Geothermal Station in northeast Iceland fluids taken from the earth have a mixture of gases, mainly carbon dioxide and hydrogen sulfide. These pollutants may affect global warming, acid rain and produce noxious smells. Geothermal power plants emit about 122-kg of carbon dioxide per megawatt-hour (MWh) which is a small fraction of emission from fossil fuel plants. Some plants use emissioncontrol systems to lessen the vapors of acids and volatile chemicals. Along with dissolved gases, hot water from geothermal sources may contain trace amounts of hazardous elements such as mercury, arsenic, and antimony. Geothermal plants could send these toxins, along with the gases, back into the earth, using an expanded form of carbon capture and storage. Plant construction may adversely affect land stability and subsidence has occurred in geothermal fields in New Zealand and Germany. Enhanced geothermal systems may also trigger seismic events due to hydraulic fracturing as happened in Basel, Switzerland. The project was suspended when more than 10,000 seismic events measuring up to 3.4 on the Richter Scale occurred during the first week of water injection. Geothermal has minimal land and freshwater requirements. Plants use 1-8 acres per MW versus 5-10 acres per for nuclear and 19


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acres per MW for coal plants. They use 20 liters of freshwater per MWh versus over 1000 liters per MWh for nuclear, coal, or oil plants. Since geothermal power requires no fuel, it is immune to fuel cost fluctuations, but capital costs are high. Drilling accounts for most of the costs and the exploration of resources has significant risks although some governments subsidize geothermal power. Chevron is the world’s largest producer of geothermal energy and other companies such as Reykjavik Energy Invest are building plants around the world. ADVANCED SOLAR Concentrating solar thermal plants in California have been delivering electricity for decades. Advanced solar thermal systems are dropping in price and some companies are introducing thermal storage to match power demand. Models show that solar thermal power could replace most fossilfueled electricity generation in the U.S. along with oil-based transportation. These models indicate that it is economically feasible for the U.S. as well as China and India. The peak load requirements are 50GW for California, 63-GW for Texas, and 1067-GW installed and 789GW non-coincident peak load for the U.S. overall. Oil storage was demonstrated commercially in the mid-1980s and molten salt is being used in parabolic trough plants in Spain. Low cost water-based thermal storage is expected to be commercialized within a few years. Thermal storage can lower the cost per kWh since it reduces the turbine size required for a given thermal output. The storage used is only enough to carry loads for one or two days, and is used to match hourly output fluctuations in solar input with hourly load. These storage levels do not provide seasonal or even weekly storage, so are subject to local weather events, especially sustained cloudy periods. There is an overproduction of thermal energy at peak solar periods in summer, which is discarded by turning some of the reflector field off-focus. In the model, if the system is provided with 16 hours of storage, the output exceeds the grid load requirement at all times except in winter, using a peak turbine capacity equal to the peak load of 50-GW.

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The correlation with annual load was 92%, without the use of a peaking plant and with only 3% of energy having to be dumped by switching to off-focus. For the Texas ERCOT grid, 16 hours of storage was assumed. A 91% correlation was achieved without a peaking plant. Supply of the U.S. would take place from many southern and western states, but using California and Texas with a 108-GW coincident peak resulted in a solar generation correlation of 96% for the national grid. Solar power with storage can take up much of the grid generation load or vehicle energy load. A mixture of storage and non-storage renewable options would be an alternative to the present generation mix with other contributors probably being hydro and wind. Not only is solar thermal an energy option of significance, but with only 16 hours of storage it has sufficient diurnal and seasonal natural correlation with the electricity load to supply a major part of the U.S. national grid and those of China and India over the year, even with the hourly solar radiation data including typical cloudy weather patterns. Solar thermal could also supply much of an electrified transportation market without destroying these natural correlations. Zero emissions technology is required to replace most of the current generation by mid-century to meet most climate goals. What is also needed to facilitate such a vision is a rework of the function and form of electricity grid networks with the inclusion of high capacity solar electricity in the redesign of continental electricity systems. Much work needs to done with prototype projects that have 16 hour thermal storage. The efficiency of collecting the solar energy, storage and the turbine cycle needs to be demonstrated. Distributed generation is the energy future combined with a base load generation system. Distributed energy offers a solution to those who suffer when a power line goes down and includes small hydrogen plants, plasma gasification, solar, wind, trigeneration and cogeneration systems located at industrial sites with offshore wind power and even tidal power in the mix. The result is a hybrid system that combines the best of local generation with the best of the remote sources of renewable energy. References

Colvin, Geoffrey, “Nuclear Power Is Back—Not a Moment Too Soon” Fortune, Volume 151, p. 57, May 30, 2005. Glaser, Peter E., “Power from the Sun, Its Future,” Science, Volume 162 No.3856, Nov. 22,


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1968, pp. 857-861. Glaser, Peter E., Frank P. Davidson and Katinka Csigi, Solar Power Satellites, John Wiley & Sons: New York, 1998. IEEE Article No: 602864, Automatic Beam Steered Antenna Receiver-Microwave. Mankins, John C., “A Fresh Look at Space Solar Power: New Architectures, Concepts and Technologies,” IAF-97-R.2.03, 38th International Astronautical Federation. O’Neil, Gerald K., “2081 A Hopeful View of the Human Future,” ISBN 0-671-24257-1, pp. 182-183. Reiss, Spencer and Peter Schwartz, “Nuclear Now: How Clean, Green Atomic Energy Can Stop Global Warming,” Wired, Volume 13, pp. 78-80, February 2005. Rodenbeck, Christopher T. and Chang, Kai, “A Limitation on the Small-Scale Demonstration of Retrodirective Microwave Power,” Space Resources, NASA SP-509, Volume 1. “Transmission from the Solar Power Satellite,” IEEE Antennas and Propagation Magazine, August 2005, pp. 67-72. www.nexgen-energypartners.com/2009/08/17/work-begins-on-historic- wind-powerproject-in-ohio www.spacefuture.com/archive/a_fresh_look_at_space_solar_power _new_architectures_ concepts_and_technologies.shtml www.space.com/businesstechnology/technology/nasda_solar_sats_011029.html www.spacefuture.com/archive/conceptual_study_of_a_solar_power_satellite_sps_2000. shtml www.wikipedia.org/wiki/Solar_power_satellite

INDEX

Index Terms

Links

A AB32 absorption chillers ACES

69 191 4

100

101

103

186

187

188

189

ACSR

243

244

AFUE

96

AFV AMFA anaerobic digestion

267

268

19 128

155

156

B back-pressure turbine

73

BACnet

83

BACtalk

84

BAS

83

BCHP

78

biological moderation

44

84

87

88

Index Terms

Links

C CAFE

47

CAGR

5

California Fuel Cell Partnership

144

Cal-ISO

239

cap and share

201

cap and trade

195

Carbon Trade Watch

200

cascaded system

101

catalytic synthesis

124

C-BED

294

CCS

212

286

CCX

213

214

CDM

196

cellulosic ethanol

134

CER

200

CFCL

72

CFC

42

CHCP

78

196

197

Clean Development Mechanism

203

CNG

137

138

compressed hydrogen

142

143

98

107

192

291

292

293

cooling tower CREB Cryoplane CSI

32 229

Index Terms

Links

D demand limit control

92

demand limiting

94

Dreamliner

31

DSM

159

181

160

E ECC

213

economizer

106

EMCS

89

EnerGuide

115

Energy Star

114

ERCOT

300

F FCHV

58

FCX

26

FERC

251

FFV

20

21

FIT

228

229

fue economizers

97

fuidized bed combustion

61

Forest Biomass for Energy

132

FREEDM

261

FreedomCAR

26

FREEPOWER Microturbine

74

174

230

Index Terms

Links

FutureGen

218

219

G GBI Global Observer

114 32

Green Lights

162

Green Sigma

115

green tags

198

GRHC

111

H HaveBlue

29

Hubbert

12

HVDC

256

Hydrogen Highway Project

33

Hydrogenics

29

hydrogen production

257

141

HydroPlus

60

HyLyzer

30

I i-Blue

58

Icelandic New Energy

274

ICES

100

101

102

187

188

189

IES

163

103

Index Terms

Links

IGFC

215

indirect/direct fxtures

165

in-situ conversion

166

15

irreversible hydrides

143

ITM

215

K Krafa

298

L LCA

171

LFTR

223

light scheduling

167

liquid hydrogen

141

Little Ice Age LNG load shedders LWRs

172

49 137 93

94

182

220

221

222

M Mahogany Ridge

15

microbial production

60

micro-fuel cells

22

micro-hydro

289

290

183

Index Terms

Links

N NERC Nevada Solar One

238 8

O OTEC

276

OWC

279

277

P Palo Verde

37

PHEVs

265

photocatalytic water splitting

145

Pickett Act

14

PID

90

plasma arc gasifcation

65

Plataforma Solar proportional zone control PS10

178

8 90

178

9

purge mode

95

PURPA

75

227

R REC

200

RFS

121

RGGI

199

RPS

76

236

278

Index Terms R-value

Links 168

169

54

55

170

S SECA Sleipner

211

SmartGrids

259

smart meters

259

SPR

13

SPS

280

281

282

steam electrolysis

24

steam reforming

23

Stirling cycle engines

35

summer/winter switching

95

supercapacitors

59

supercritical

62

63

64

127

129

218

syngas

75

T TERI thermochemical conversion thermochemical water splitting TMI TOTEM

18 127 24 152

153

71

173

U Ultracapacitors

30

Index Terms

Links

V variable fuel fow

97

VFDs

20

107

virtual reality

91

180

W WAM Western Governor’s Association

264 4

Weyburn

208

WindVAR

233

211

193

194

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