Comprehensive Energy Systems, vol.1b - Energy Fundamentals [1b, 1 ed.] 978-0-12-814925-6

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1.12 Fossil Fuels Ilhami Yildiz, Dalhousie University, Halifax, NS, Canada r 2018 Elsevier Inc. All rights reserved.

1.12.1 Introduction 1.12.1.1 Global Energy Source and Demand 1.12.1.2 Fossil Fuel 1.12.1.3 Hubbert Peak Theory 1.12.2 Oil 1.12.2.1 Sources of Oil 1.12.2.1.1 Conventional sources 1.12.2.1.2 Unconventional sources 1.12.2.2 Oil Reserves 1.12.2.2.1 Reserves of unconventional oil 1.12.2.3 Oil Production, Demand and Trade 1.12.2.4 Peak Oil 1.12.2.5 Environmental Impacts of Oil 1.12.2.5.1 Case Study: Oil sands production in Alberta, Canada 1.12.3 Natural Gas 1.12.3.1 Sources of Natural Gas 1.12.3.2 Natural Gas Reserves 1.12.3.3 Natural Gas Production, Demand, and Trade 1.12.3.4 Peak Gas 1.12.3.5 Environmental Impacts of Natural Gas 1.12.4 Coal 1.12.4.1 Sources of Coal 1.12.4.2 Coal Reserves 1.12.4.3 Coal Production, Demand, and Trade 1.12.4.4 Peak Coal 1.12.4.5 Environmental Impacts of Coal 1.12.4.5.1 Case Study: coal mining in China 1.12.5 Further Case Studies 1.12.5.1 Case Study: Global Fossil Fuel Consumption and Supply 1.12.5.2 Case Study: Fossil Fuel Consumption and Supply in Africa 1.12.5.3 Case Study: Fossil Fuel Consumption and Supply in North America 1.12.5.4 Case Study: Fossil Fuel Consumption and Supply in the Unites States 1.12.5.5 Case Study: Fossil Fuel Consumption and Supply in Brazil 1.12.5.6 Case Study: Fossil Fuel Consumption and Supply in the European Union 1.12.5.7 Case Study: Fossil Fuel Consumption and Supply in the Middle East 1.12.5.8 Case Study: Fossil Fuel Consumption and Supply in Russian Federation 1.12.5.9 Case Study: Fossil Fuel Consumption and Supply in India 1.12.5.10 Case Study: Fossil Fuel Consumption and Supply in Other Emerging Asia 1.12.6 Future Prospects 1.12.6.1 Oil 1.12.6.2 Natural Gas 1.12.6.3 Coal 1.12.7 Concluding Remarks 1.12.7.1 Oil 1.12.7.2 Natural Gas 1.12.7.3 Coal References Further Reading Relevant Websites

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Comprehensive Energy Systems, Volume 1

521

doi:10.1016/B978-0-12-809597-3.00111-5

522

Fossil Fuels

1.12.1

Introduction

Fossil fuels have always had the major share in the global primary energy consumption. Even though the share of fossil fuel consumption has decreased in recent years and is predicted to decrease further, they will continue to hold the major share in the primary energy mix in the foreseeable future as more unconventional fossil fuels are explored. Overall fossil fuel consumption increased approximately 51% in the period of 1995–2015, and it is predicted that the consumption will increase approximately 18% more in the period of 2015–35. The following sections of this chapter overview the past, current, and future developments of fossil fuels, including oil, natural gas, and coal with their reserves, productions, consumptions, peaks and environmental impacts.

1.12.1.1

Global Energy Source and Demand

Energy supports all forms of life on Earth, and is directly acquired from sunlight by photosynthetic organisms, including plants and microorganisms. This natural energy source is transmitted, converted, and released through the living tissues and food chain [1]. The most primitive forms of energy, such as oil, natural gas, and coal, are produced and accumulated underneath the earth due to natural processes in the past millions of years. These nonrenewable fossil fuel resources, which have tremendous value for us now and for our future generations, are expected to be depleted due to the world population growth and industrial development [1,2]. With the emergence and development of industrial and agricultural activities, numerous products, including plastics, textiles, fertilizers, and products from steel manufacturing and petrochemical industry, have been generated to meet our daily needs. As larger and more industrial plants are built, obviously more energy is required for operation, processing, and transportation [3]. The world population is increasing rapidly, especially in the developing countries, with an approximately 80 million more addition every year [4]. People’s lifestyles have been changing gradually, particularly in the developed countries, and the developing nations are following the trend. Energy makes work and life more convenient and efficient. The rising population and demand for convenient lifestyles will require more goods and therefore more energy resources. Considering the imbalance between supply and demand due to depletion of nonrenewable energy resources might eventually trigger an energy crisis, open and undercover conflicts from an international perspective have already started to take place. Therefore, renewable energy exploitation and energy efficiency improvement are critical themes for sustainable energy supply, as well as play an essential role in continuously providing a decent living standard for human beings [1]. In the years between 1973 and 2010, the global energy consumption grew by 186% and supply for industrial use increased by 157% [2,5,6]. Currently, the world energy sources are primarily contributed by fossil fuels, hydropower, nuclear energy, wind energy, solar energy, and other renewables (see Fig. 1). And the International Energy Outlook 2016 projects remarkable growth in worldwide energy consumption in different regions over the period of 2012–40 (see Table 1). The World Energy Council (WEC) and International Energy Agency (IEA) reported that the world energy demand in 2020 is expected to rise by 50% to 80% from the 1990s and the number is projected to increase by more than one-third by the year 2035 on the basis of the present level. It should be noted that approximately 60% of the growth in demand will mainly come from China, India, and the Middle East [2,7,8]. The global energy demand from all sources is expected to expand, including oil (13%), coal (17%), natural gas (48%), nuclear (66%), and renewables (77%) [9]. Global electricity demand as well is forecasted to increase by 70% by the year 2030 [10]. The renewable energy contribution, including hydropower, geothermal, and solar, is expected to reach 30% of total electricity supply by 2035 [10]. However, thermal electricity generation using coal, natural gas and nuclear will still serve for power generation around the world, and coal will continue to dominate having the largest share [11]. Over the past two decades, hundreds of millions of people living in developing countries, particularly in China and India, have gained access to modern energy services due to their quickly growing urbanization and economic development [3]. However, there were still 1.3 billion people who did not have any share in the use of electricity generated in the year 2010, and approximately 2.6 billion people still relied on traditional biomass energy, such as wood and other forms of biomass, for cooking and heating purposes [9,12]. Moreover, Global Energy Assessment (GEA) stated that about nine billion people are projected to require affordable energy services by the year 2050 [13]. The renewable energy has recently experienced exponential growth in the share of the energy markets; however, it still accounts for only a small portion of total primary energy supply, and their contribution is not likely to have enormous impacts in the near future. The WEC’s Outlook Report in 2013 indicated that development of the renewables not only faces demand challenges, but also significantly depends upon financial and legal supports from governments in developing countries [7]. In fact, the renewable energy development rate has been slower than it was predicted 20 years ago [7]. A comparison of global primary energy consumption over the past 10 years is summarized in Fig. 1. The findings clearly show that the majority of consumption was in the form of fossil fuels, while a slight decline (0.61%) observed from 2005 to 2015. Renewables only shared a small fraction that fluctuated from 12% to 14%, but it seems to have gone up steadily.

1.12.1.2

Fossil Fuel

Fossil fuel is a primary energy resource that plays a critical role in our daily activities, including transportation, manufacturing, electricity production, cooling and heating systems, and many other uses [14]. Fossil fuels are formed by natural processes, such as anaerobic decomposition of dead organisms, and the energy contained originates in ancient photosynthesis [15]. These fuels

Fossil Fuels

523

2005 Nuclear, 5.7%

Solar, 1.0%

Other renewables, 0.5% Oil, 35.6%

Wind, 0.2%

Hydro, 6.0% Gas, 22.7%

Coal, 28.3%

2010 Nuclear, 5.1 %

Solar, 0.1%

Wind, 0.6%

Hydro, 6.4%

Other renewables, 0.7%

Oil, 33.5% Gas, 23.7%

Coal, 29.8%

2015 Solar, 0.5% Wind, 1.4%

Nuclear, 4.4%

Other renewables, 0.9% Oil, 32.9%

Hydro, 6.8% Gas, 23.9%

Coal, 29.2%

Fig. 1 Global primary energy consumption comparisons. Data from World Energy Council. 2016 Survey of world energy resources, London; 2016.

Table 1

Projection of the world’s regional energy consumption 2012–40 (EJ)

Regions

2012

2025

2040

OECDa America Europe Asia

251 124 85 41

274 135 92 47

298 146 101 51

Non-OECD Europe Asia Middle East Africa Americas

322 54 186 34 34 33

413 58 260 47 32 39

533 61 340 65 46 50

World Total

591

710

860

a

Organization for Economic Cooperation and Development member countries. Europe: Austria, Belgium, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, the Netherlands, Norway, Poland, Portugal, Slovakia, Slovenia, Spain, Sweden, Switzerland, Turkey, United Kingdom. Other member countries: Australia, Canada, Chile, Israel, Japan, Mexico, New Zealand, South Korea, United States. Source: Modified after World Energy Council. 2016 Survey of world energy resources, London; 2016.

524

Table 2

Fossil Fuels

Oil, natural gas, and coal reserves in top five countries and their productions in 2016

Oil

Gas Production (Mt)

Countries

Reserves (Mt)

Venezuela Saudi Arabia Canada

47,000 36,600

124.1 285.7

27,600

Iran Iraq Global

Countries

Coal Reserves (tcm)

Production (bcm)

Countries

Reserves (Mt)

Production (Mt)

33.5 32.3

202.4 579.4

United States China

281,582 244,010

521.1 2408.1

218.2

Iran Russian Federation Qatar

24.3

181.2

160,364

275.4

21,800 20,600

216.4 218.4

Turkmenistan United States

17.5 8.7

66.8 749.2

Russian Federation Australia India

144,818 94,769

427.6 401.3

240,700

4382.4

186.6

3551.6

1,139,331

5223.4

Global

Global

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

formed from the fossilized remains of dead plants [16] are formed by exposure to heat and pressure in the Earth's crust over millions of years [17], and the age of the organisms and hence the resulting fuels is many times older than 650 million years [18]. Fossil fuels contain high percentages of carbon and include coal, oil, and natural gas. Some other used derivatives can be listed as kerosene and propane. Fossil fuels cover a range from nonvolatile materials with almost pure carbon (e.g., anthracite coal), to volatile materials with low carbon to hydrogen ratios (e.g., methane) to liquids (e.g., petroleum). In hydrocarbon fields, methane can be found either alone, associated with oil, or in other forms of methane. Fossil fuels are formed via natural processes continually; however, they are generally considered as nonrenewable resources because they take millions of years to form, and the known reserves are being depleted much faster than the new ones being made available [19,20]. As Fig. 1 shows, the global primary energy consumption in 2015 consisted of petroleum 32.9%, coal 29.2%, and natural gas 23.9%, amounting to an 86.0% share for nonrenewable fossil fuels in primary energy consumption in the world. Nonfossil energy consumption in 2015 included hydroelectric 6.8%, nuclear 4.4%, wind 1.4%, solar 0.45%, and other renewables amounting to 0.89% [21]. And world energy consumption is growing. As it is seen clearly, fossil fuels are closely linked to our lives; therefore, it is important to figure out their impacts on the surrounding environment and other related resources [22]. The burning of fossil fuels produces around 21.3 billion tonnes of carbon dioxide (CO2) per year. And natural processes can only absorb part of this release, and it is estimated that only about half of this amount can be absorbed by natural processes. Hence, there is a surplus of 10.65 billion tonnes of CO2, which is released to the atmosphere every year [23]. It is now a common knowledge that CO2 is a greenhouse gas, which increases the atmospheric radiative forcing due to its global warming potential and therefore contributes to global warming. There is a global trend toward the generation of more renewable energy to help reduce global greenhouse gas emissions including the emissions from fossil fuels. Also, the linkage between energy and water has become clearer recently [2,3,24]. The extraction and processing of fossil fuels require a large amount of water input, which frequently impacts the water quality negatively [24]. Due to the environmental concerns and others, the contribution of fossil fuels is expected to drop with the rapid growth of clean and renewable energy sources. Fossil fuel reservoirs are not equally distributed around the world. In 2017, the British Petroleum (BP) published reserves and production of oil, natural gas and coal from the top five countries in the year 2016. Table 2 shows that reserves are mainly concentrated in the Middle East, North America, Russian Federation, and Asia. About 77% of total coal production was exploited from the top five reserves, while only 50% and 24% of global natural gas and oil productions, respectively. Furthermore, the IEA [22] predicted and published the world petroleum and other liquid fuels, natural gas, and coal production by Organisation for Economic Cooperation and Development (OECD) and non-OECD countries over the period from 2012 to 2040 (Fig. 2) [11].

1.12.1.3

Hubbert Peak Theory

American geophysicist M. King Hubbert, in 1956, proposed that fossil fuel production in a given region over time would follow roughly a bell-shaped curve, without providing a precise formula. However, for estimating future production using past observed discoveries, he later used the Hubbert curve (Fig. 3) – the derivative of the logistic curve (common S-shaped sigmoid curve) [25,26] – which is an approximation of the production rate of a resource over time. He assumed that after fossil fuel (oil, coal, and natural gas) reserves are discovered and as more extraction takes place, production follows approximately an exponential increase. And at some point of extraction, eventually a peak output is reached, and production starts to decline until it forms, this time, approximately an exponential decline. The Hubbert curve is roughly symmetrical and has a single peak, satisfying the abovementioned characteristics; and production reaches the peak when about half of the fossil fuel that will ultimately be produced has been produced. Provided any past fossil fuel discovery and production data, a Hubbert curve that approximates past discovery data can be constructed and used to provide estimates for future production. Eventually, the approximate time of peak fuel production and the total amount of fuel that would ultimately be produced are estimated that way.

Fossil Fuels

25

OECD

525

Non-OECD

Million m3/day

20 15 10 5

11.89

7.12

8.66

7.23

7.23

7.33

2012

2020

2040

0 (A) 7.0

OECD

Non-OECD

Trillion m3

6.0 5.0 4.0

2.0 1.0

3.85

2.76

3.0 2.13 1.26

1.47

1.88

2012

2025

2040

6671

7099

2029

2174

7133

2012

2025

2040

0.0 (B) 10,000

OECD

Non-OECD

Million tons

8000 6000 6115 4000 2000 0 (C)

Fig. 2 World production of (A) petroleum and other liquid fuels, (B) natural gas, and (C) coal by regions over the period from 2012 to 2040. OECD, Organisation for Economic Cooperation and Development. Data from United States Energy Information Administration. International energy outlook 2016, U.S. Department of Energy, Washington, DC; 2016.

0.25

0.20

0.15

0.10

0.05

0 −6

−4

−2

0

2

4

6

Fig. 3 The standard Hubbert curve. For applications, the x and y scales are replaced by time and production scales.

526

Fossil Fuels

1.12.2

Oil

As mentioned earlier, just like natural gas, oil is formed by the anaerobic decomposition of organic matter including phytoplankton and zooplankton, which were settled in large quantities in deposition basins, such as a seabed or lakebed, over geological time. This organic matter, after being mixed with mud, remained buried under increasing layers of sediment over millions of years. As a result, the organic matter and mud mixture was exposed to high pressures and temperatures over millions of years causing the organic matter to chemically change, first into kerogen (a waxy material, which is found in oil shales), and then, with more exposure to further heat, into liquid and gaseous hydrocarbons in a process known as catagenesis. Throughout all these processes, the energy density of hydrocarbons might increase; however, the origin of the energy is still the ancient photosynthesis. Currently, the world’s primary fuel source for transportation is oil, which also exists in shale and tar sands; however, most oil is pumped out of underground reservoirs. Oil is extracted, and then it is processed in refineries to create fuel oil, gasoline, liquefied petroleum gas, and other products like fertilizers, pesticides, pharmaceuticals, and plastics. However, oil causes serious environmental problems and the heavy reliance on oil particularly for transportation makes it difficult to reduce its consumption. Furthermore, the environmental degradation caused by extraction and oil spills, combustion of oil emits fine particulates, which can lead to serious health problems for humans, and is also a major source of greenhouse gas emissions. As we keep depleting conventional oil sources from underground reservoirs, unconventional sources, such as tar sands and oil shale, attract more attention. Heavier crude oils extracted from such sources result in more emissions and environmental disturbance compared to conventional oil because their extraction is involved in the use of energy intensive methods.

1.12.2.1

Sources of Oil

Oil comes from both conventional and unconventional sources. The terms, conventional and unconventional sources, are however not clearly defined in the literature and the definitions vary considerably. For instance, Hubbert limited his peak oil prediction in 1956 to the crude oil producible by methods then in use. His later analyses included future improvements in exploration and production [27]; however, all his peak oil analyses excluded the oil from oil sands and oil shale. We can give a 2013 study, as an example, which predicted an early peak, excluded the oil, such as deepwater oil, tight oil, and oil close to the poles, all of which were defined as nonconventional sources [28]. This chapter provides commonly used definitions for conventional and unconventional oil as presented below.

1.12.2.1.1

Conventional sources

Oil extracted on land and offshore using standard techniques is defined as conventional. And with respect to grade, though the exact definitions of the grades vary based on where the oil comes from, these sources are categorized as light, medium, heavy, or extra heavy. Light oil flows naturally to the surface and can simply be extracted by pumping it to the surface. Heavy oil obviously refers to the oil that does not flow easily because of its higher density. While conventional techniques are partly used for producing this heavy oil, typically the use of unconventional methods proves to provide better recovery rates [29].

1.12.2.1.2

Unconventional sources

It does not mean that it will be so forever; however, currently the following oil sources are considered unconventional.

•

• • •

•

Oil sands: these are unconsolidated sandstone deposits containing large amounts of viscous crude bitumen or extra heavy crude oil. They can be recovered by surface mining or oil wells using steam injection or other techniques. Such deposits are liquefied by blending with diluents, upgrading, or heating; and then, processed at an ordinary oil refinery. The recovery of these deposits requires an advanced technology, which is different from a conventional technology and more efficient than that of oil shale, for instance, due to the sandstone deposits’ producing oil much more easily compared to oil shale or marl. These formations are quite often called "tar sands," such as Canadian tar sands; however, the material exists there is actually not tar, rather it is an extra heavy and viscous oil known as bitumen [30]. Oil shale: oil shale is used as a common term for sedimentary rock, such as shale or marl, which contains kerogen that is yet to be transformed into crude oil by the high pressures and temperatures due to deep burial. These formations are close to the surface; therefore, they are generally mined, crushed, and retorted, eventually manufacturing oil (synthetic) from the kerogen [31]. Tight oil: this is the oil extracted via hydraulic fracturing from low-permeability rock deposits, shale deposits, and many times from other rock types as well [32]. It should not be confused with shale oil, which is, as mentioned above, the oil manufactured from the kerogen contained in an oil shale. Coal liquefaction or gas-to-liquids (GTLs) product: these are synthesized liquid hydrocarbons from the conversion of coal or natural gas by a number of processes, such as Fischer–Tropsch process, Bergius process, or Karrick process. Sasol currently has working commercial scale synthetic oil technologies based on coal-to-liquid (CTL) and natural GTL technologies, producing $4.40 billion in revenues. Shell has also employed these processes to convert and recycle waste flare gas burnt off at oil wells and refineries into usable synthetic oil. However, for CTL conversion, it has been noted that coal reserves may not be sufficient to supply world’s needs for both liquid fuels and electric power generation [33]. Minor sources: these include thermal depolymerization, which could indefinitely be used to produce oil out of waste feedstocks, such as agricultural waste, garbage, and sewage. For instance, Los Alamos Laboratory, United States, stated that hydrogen

Fossil Fuels

527

– potentially produced using hot fluid from nuclear reactors to split water into hydrogen and oxygen – in combination with sequestered CO2 could be used to produce methanol, which could then be converted into gasoline [34].

1.12.2.2

Oil Reserves

Primary energy source levels are the carbon based fossil energy reserves in the ground. Flows or daily productions of such sources are known as production of fossil fuels from these reserves. When we talk about oil reserves, we specifically mean the amount of crude oil, which can technically be recovered in a financially feasible manner at the present price of oil [35]. The total estimated amount of oil in an oil reservoir, including both producible and nonproducible oil, is called oil-in-place. Due to the limitations of oil extraction technologies at the time and reservoir characteristics, not the whole but only a portion of this oil can be recovered and brought to the surface of the Earth. And this producible portion is considered as reserves. Oil resources however include all oil that can technically be recovered at any price, not only at the present price. Therefore, as it is clearly seen and understood, unlike oil resources, oil reserves vary as a function of the price. Reserves for instance typically indicate the reserves for a point of interest, such as a single oil well, a single oil reservoir, a single oil field, a single country, or the whole world. The ratio of reserves to the total amount of oil in a specific reservoir is called the recovery factor. Thence, the method of oil recovery used, the operation itself, and the relevant technological developments all together determine the recovery factor for a given field, for instance [36]. Most early estimates of the oil field reserves are generally considered conservative and tend to grow with time (which is called reserves growth) as a function of new technological developments [37]. Fig. 4 shows the global oil reserves in billion barrels (bbl) in 2013. Oil producing nations do not typically reveal their engineered reservoir data due to their national security concerns, and instead, provide manipulated data for political reasons [38,39]. However, BP at the end of 2016 reported (see Table 3) that the highest proved oil reserves (including nonconventional oil deposits) are located in Venezuela (17.6% of global reserves), Saudi Arabia (15.6% of global reserves), Canada (10% of global reserves), Iran (9.3%), and Iraq (9.0%), with the highest reserves-toproduction (R/P) ratios belonging to Venezuela and Canada, 341.1 and 105.1 years, respectively, and the global ratio of 50.6 years. Organization of the Petroleum Exporting Countries (OPEC) data at the end of 2016 showed similar reserve numbers [40].

301 bn bbl 267 bn bbl 110 bn bbl

30 bn bbl

0 Fig. 4 Global map of oil reserves in 2013. Reproduced from Wikipedia. Available from: https://en.wikipedia.org/wiki/Oil_reserves [accessed 21.10.17]. Table 3 Countries

Proved oil reserves in top five countries between 1996 and 2016 (reserve levels are in thousand million barrels) 1996

2006

2016

Share of total (%)

Reserves-to-production (R/P) ratio

Venezuela Saudi Arabia Canada Iran Iraq

72.7 261.4 48.9 92.6 112.0

87.3 264.3 179.4 138.4 115.0

300.9 266.5 171.5 158.4 153.0

17.6 15.6 10.0 9.3 9.0

341.1 59.0 105.1 94.1 93.6

Total world

1148.8

1388.3

1706.7

100.0

50.6

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

528

Fossil Fuels

1.12.2.2.1

Reserves of unconventional oil

Oil becomes less and less available every passing year. And this can only be substituted with production of liquid fuels from unconventional fuel sources, such as oil sands, tight oil, shale oil, ultra-heavy oils, biofuel technologies, CTL, and GTL technologies [41]. That is why, International Energy Outlook (IEO) in its 2007 and later reports, in presenting world energy reserves, production and consumption, used the word “Liquids” rather than the “Oil” [42,43]. Also, biofuels was included in the “Liquids” section instead of in the “Renewables” in 2009 [44]. However, the inclusion of natural gas liquids in the “Liquids” section has up to certain extent been criticized as it is a chemical feedstock (by-product of natural gas) and generally not used as a transport fuel [45]. As mentioned earlier, oil reserve estimates are function of the oil price; and therefore, as unconventional sources are included in the picture and new techniques reduce the cost of extraction, the reserve estimates will vary in time. It is a well known fact that it is more labor and resource intensive to produce the unconventional sources, which obviously require additional energy to refine (i.e., higher production costs). Also, on a “well-to-tank” basis, approx. three times more greenhouse gas emissions are emitted per bbl equivalent [46,47]. The energy and other resources needed, and environmental effects of extracting unconventional sources have always been high prohibiting the extraction of such sources; however, a number of major unconventional sources have been brought to the table for large-scale production. The oil sands in the Western Canadian Sedimentary Basin (see Fig. 5) [48], the oil shale of the Green River Formation in Colorado, Utah, and Wyoming in the United States, and the extra heavy oil in the Orinoco Belt of Venezuela [49], can be given as examples of such efforts. Bitumen has also been extracted for many decades by companies, such as Suncor and Syncrude; but with the support of new extraction technologies, production has tremendously increased in recent years [50]. It is estimated that, taken together, these resource occurrences in the Western Hemisphere, are approx. equal to the identified reserves of conventional crude oil sources in the Middle East [51]. It is believed that the world's reserves of unconventional oil are several times larger than those of conventional oil [52] (see Fig. 6). The US Geological Survey, in October 2009, updated Venezuela’s Orinoco tar sands recoverable mean value to 513 billion bbls (81.6 billion m3), with a 90% chance of being within the range of 380–652 billion bbls (103.7 billion m3), making this area as one of the world's largest recoverable oil fields [53]. Oil extracted from unconventional sources contains sulfur and heavy metals, which are energy intensive to extract and can leave the site in some cases [46,54]. The same thing is true for much of the undeveloped conventional oil reserves in the Middle East, which is heavy, viscous, and contaminated with sulfur and metals [55]. However, these sources become more appealing financially

Fig. 5 Syncrude's Mildred Lake mine site and plant near Fort McMurray, Alberta, Canada. The yellow structures are the bases of pyramids made of sulfur – not economical to sell so Syncrude stockpiles it instead. Behind the piles is the tailings pond, recognized as the largest dam in the world. The extraction plant is to the right of this picture and the mine is to the left. Reproduced from Wikipedia. Available from: https://en. wikipedia.org/wiki/Peak_oil#cite_note-102 [accessed 21.10.17].

Fossil Fuels

529

Total world oil reserves 80% 70% 60%

Conventional oil Heavy oil Extra heavy oil Oil sands bitumen

50% 40% 30% 20% 10% 0% Conventional

Unconventional

Fig. 6 Comparison of conventional and unconventional oil reserves. Reproduced from Alboudwarej H, Felix J, Taylor S, et al. Highlighting heavy oil. Oilfield Rev 2006;18(2):34–53.

150

120

North America S & C America Europe and Eurasia Middle East Africa Asia Pacific World

160 140 120 180

90

80 60

60 40

30 20 North S & C Europe America America and Eurasia

Middle East

Africa

Asia Pacific

0

86

91

96

01

06

11

16

0

Fig. 7 2016 (left) and history (right) of regional oil reserves-to-production (R/P) ratios (years). Reproduced from BP. Available from: http://bp. com/statisticalreview [accessed 21.10.17].

when oil prices go high [56]. Mackenzie [57] forecasted that the world's extra oil supply by the early 2020s will likely be coming from unconventional oil sources. The oil reserves were suspected to be running out in the coming decades. However, with the help of advanced technologies, more oil reserves have been discovered and became viable; as a result, the global oil reserves increased by 60% within past 20 years with a 25% growth in oil production [7], now having South and Central America the highest (120 years) oil R/P ratios rather than the Middle East (see Fig. 7). It is presently expected to expand further as unconventional oil sources mentioned above are taken into account. We know that oil sands are mixture compounds that contain clay, water, sand, and bitumen [58]; and Gosselin et al. [195,59] indicated that the Alberta oil sands (see Fig. 5), for instance, have great competitiveness in Canada that accounted for approximately 50% of total Canadian oil production in 2009. Also, there is no oil in the oil shale; however, it contains a unique material called kerogen, which is a precursor of crude oil [58]. The world resources of oil shale are estimated around 730 trillion liters, which is reported to have four times greater than crude oil reserves currently [21]. Both oil sands and oil shale must be refined before they can work as conventional crude oil [60]. Therefore, they not only represent an increased oil reserve, but also an

530

Fossil Fuels

increased environmental burden. The more technologies employed for extraction and processing, the more severe is the impact on air, water, land and energy resources.

1.12.2.3

Oil Production, Demand and Trade

Fig. 8 below shows the global distribution of oil producing nations in 2013 [61]. BP Energy Outlook 2017 [62] provided a detailed report for the current and past 20 year’s oil production data as well as the projections for the next 20 years. Based on this report, annual production in million tonnes of oil equivalent (Mtoe), oil, coal, and natural gas provided 85.4% of primary energy production in 2015 (32.4% þ 29.2% þ 23.9%, respectively). Currently, oil is the world's largest primary source of energy. Table 4 indicates that global oil production in 2015 increased by 32.7% compared to that in 1995, and is projected to increase further in the next 20 years (9.3% based on the 2015 production figures). The main increase has been and will be in the Middle East and North America (Canada, Mexico, and the United States), while there is a major decline in oil production in Europe and almost a steady production in Africa and Asia Pacific. Table 5, on the other hand, shows the regional oil productions in 1995, 2015, and projected oil productions in 2035, as well as the relevant changes in regional productions. Based on this report, the Middle East, North America, and the Commonwealth of Independent States (CIS) will continue to preserve their leading shares of global oil production with further production increases through 2035, while the South and Central America sustaining its share with increased production, and other regions observing a

Barrels per day (bbl/day) ≥ 10,000,000 ≥ 3,000,000 ≥ 1,000,000 ≥ 500,000 ≥ 150,000 ≥ 100,000 ≥ 50,000 ≥ 25,000 ≥ 10,000 ≥ 5000 ≥ 1000 >0 0

Countries by oil production in 2013

Fig. 8 Global map of oil producing countries in 2013. The map is Ali Zifan’s work, which was prepared using data from CIA World Factbook. Reproduced from Wikipedia. Available from: https://en.wikipedia.org/wiki/Peak_oil#cite_note-102 [accessed 21.10.17].

Table 4

Oil production by region (million tonnes of oil equivalent)

Regions

Years 1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

2000

2005

2010

2015

2020

2025

2030

2035

645.8 300.1 311.1 358.3 979.2 339.6 352.2

642.6 343.4 332.3 396.2 1151.1 370.9 380.8

637.8 374.4 268.6 580.3 1227.4 466.4 382.4

638.8 375.8 196.5 662.8 1220.7 481.8 402.4

910.3 396.0 164.7 682.0 1412.4 398.0 398.3

940.0 389.9 146.4 692.7 1508.0 386.6 355.8

1007.5 404.5 133.3 708.3 1618.2 392.8 348.7

995.9 434.8 94.6 716.2 1727.6 390.2 331.6

1004.1 454.0 66.6 730.2 1818.7 382.7 311.9

3286.3

3617.4

3937.5

3978.8

4361.6

4419.5

4613.2

4690.9

4768.1

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Fossil Fuels

531

Table 5 Changes in regional oil production between 1995 and 2015 and 2015 and 2035 (production levels are in million tonnes of oil equivalent) Regions

1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

1995 Total 2015 share (%)

2015 Total 2035 share (%)

2035 Total 1995–2015 1995–2015 share (%) Change (%) Annual change (%)

2015–35 Change (%)

2015–35 Annual change (%)

645.8 300.1 311.1 358.3

19.7 9.1 9.5 10.9

910.3 396.0 164.7 682.0

20.9 9.1 3.8 15.6

1004.1 454.0 66.6 730.2

21.1 9.5 1.4 15.3

41.0 31.9 47.1 90.4

2.0 1.5 2.2 4.3

10.3 14.7 59.6 7.1

0.5 0.7 2.8 0.3

979.2 339.6 352.2

29.8 10.3 10.7

1412.4 398.0 398.3

32.4 9.1 9.1

1818.7 382.7 311.9

38.1 8.0 6.5

44.2 17.2 13.1

2.1 0.8 0.6

28.8 3.8 21.7

1.4 0.2 1.0

4768.1 100.0

32.7

1.6

9.3

0.4

3286.3 100.0

4361.6 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 6

Oil production in top five countries from 2006 to 2016 (production levels are in million tonnes)

Countries

2006

2011

2016

Annual growth rate (%) 2016

Saudi Arabia Russian Federation United States Iraq Canada Total world

2005–15

Share of 2016

508.9 485.6 304.5 98.0 150.6

525.9 518.8 344.9 136.7 169.8

585.7 554.3 543.0 218.9 218.2

2.9 2.2 4.2 10.8 0.9

0.4 1.3 6.2 8.2 4.2

13.4 12.6 12.4 5.0 5.0

3964.8

4007.9

4382.4

0.3

1.0

100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 7

Oil consumption by region (million tonnes of oil equivalent)

Regions

Years 1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

2000

2005

2010

2015

2020

2025

2030

2035

951.4 208.9 738.5 210.4 215.8 106.2 864.2

1061.1 234.3 763.6 169.1 242.8 119.6 997.3

1129.1 248.6 792.5 172.7 301.5 138.9 1150.6

1040.3 294.6 733.3 178.0 368.3 164.5 1300.9

1036.3 322.7 673.6 188.5 425.7 183.0 1501.4

1039.1 330.5 666.7 188.4 447.3 201.3 1684.1

1001.9 353.9 639.4 206.7 485.0 226.4 1871.5

947.1 366.0 596.0 218.0 521.3 254.8 2018.4

894.9 372.2 552.9 226.5 550.0 284.8 2140.4

3295.5

3587.7

3933.9

4079.9

4331.3

4557.6

4784.8

4921.7

5021.8

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

decline in oil production. The major decline took place in Europe and will continue to drop further through 2035. Overall, there has been an annual increase (1.6%) with 32.7% total change in global oil production in the period of 1995–2015, and the annual increase is expected to happen around 0.4% with 9.3% total change in the period of 2015–35. Table 6 presents the top oil producing nations in the past 10 years with their relevant growth rates and shares of global oil production. Based on this report, Saudi Arabia has consistently been the top producer of oil followed by the Russian Federation and the United States, with their shares of 2016 as 13.4%, 12.6%, and 12.4%, respectively. Iraq, on the other hand, has experienced a major increase (48.0%) in oil production in the past 10 years and moved to the fourth place in production. Table 7 shows that, except in the CIS, oil consumption continued to increase everywhere else between the years 1995 and 2015 with a 31.4% global increase compared to that in 1995, and is projected to increase further in the next 20 years (15.9% based on the 2015 consumption). Oil consumption in Europe, along with the other forms of fossil fuels (either sustained or decreased),

532

Fossil Fuels

sustained its levels until 2010; however, it started to decrease thereafter, and is forecasted to maintain the decreasing trend further through 2035. The decrease in fossil fuel consumption in Europe has been compensated by the renewable energy sources, which are expected to have more shares in the mix with an exponential growth in the next 20 years, benefiting from energy efficiency transition as well. The main increase in consumption has been and will be in Asia Pacific and the Middle East. The oil consumption along with the consumption of other forms of energy in most of the CIS decreased after the collapse of the former Soviet Union up until 2010, and after establishing and starting to develop further, the consumption started to increase again. Table 8, on the other hand, reports the regional oil consumptions in 1995, 2015, and projected oil consumption in 2035, as well as the relevant changes in regional consumption. Based on this report, as in the past 20 years, Asia Pacific and North America will continue to preserve their leading shares of global oil consumption with the United States having some drop in consumption (28.9% in 1995 to 23.9% in 2015, and to 17.8% in 2035) and Asia Pacific having a further consumption increase (42.6%) through 2035. The Middle East as well has doubled its oil consumption in the past 20 years, and is expected to increase it further through 2035 reaching a total share of 11% of the global consumption with a 29.2% change in between 2015 and 2035. Europe, on the other hand, has had the third largest share in global oil consumption in the past 20 years with a drop of 8.8%; however, it is expected to drop (17.9%) further in between 2015 and 2035 reaching the same level as that of the Middle East. The CIS experienced a 10.4% drop in oil consumption between the years of 1995 and 2015; however, it is forecasted that it will have a 20.1% increase in the next 20 years. Overall, there has been an annual increase (1.5%) with a 31.4% total change in global oil consumption in the period of 1995–2015, and the annual increase is expected to take place around 0.8% again with a 15.9% total change in the next 20 years. Table 9 presents the top oil consuming nations in the past 10 years with their relevant growth rates and shares of global oil consumption. Based on this report, the United States has consistently been the top consumer of oil followed by China and India (replaced Japan in 2016), with their shares of 2016 as 19.5%, 13.1%, and 4.8%, respectively. India is highly dependent on imported crude oil, which comes from overseas oil fields, such as the Middle East and South America [12]. Japan, on the other hand, has experienced a major decline (2.6%) in annual growth of oil consumption in the past 10 years, with an annual drop of 2.8% in 2016 alone. However, in many other Asian countries, the oil consumption is still rising at high speeds to give access to urbanization and industrialization. The reason that oil has remained the leading energy supplier is that the consumption growth in developing economies exceeds the declined demands in the OECD countries [6,63]. The OECD countries have already benefited from energy efficiency transition and upgrading strategies that can satisfy the needs [12]. Table 8 Changes in regional oil consumption between 1995 and 2015 and 2015 and 2035 (consumption levels are in million tonnes of oil equivalent) Regions

1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

1995 Total 2015 share (%)

2015 Total 2035 share (%)

2035 Total 1995–2015 1995–2015 share (%) Change (%) Annual change (%)

2015–35 Change (%)

2015–35 Annual change (%)

951.4 208.9 738.5 210.4

28.9 6.3 22.4 6.4

1036.3 322.7 673.6 188.5

23.9 7.5 15.6 4.4

894.9 372.2 552.9 226.5

17.8 7.4 11.0 4.5

8.9 54.5 8.8 10.4

0.4 2.6 0.4 0.5

13.6 15.3 17.9 20.1

0.6 0.7 0.9 1.0

215.8 106.2 864.2

6.5 3.2 26.2

425.7 183.0 1501.4

9.8 4.2 34.7

550.0 284.8 2140.4

11.0 5.7 42.6

97.3 72.3 73.7

4.6 3.4 3.5

29.2 55.7 42.6

1.4 2.7 2.0

5021.8 100.0

31.4

1.5

15.9

0.8

3295.5 100.0

4331.3 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 9

Oil consumption in top five countries between 2006 and 2016 (production levels are in million tonnes)

Countries

2006

2011

2016

Annual growth rate (%) 2016

United States China India Japan Saudi Arabia Total world

2005–15

Share of 2016

930.7 353.1 128.3 238.0 98.4

834.9 465.1 163.0 203.7 139.1

863.1 578.7 212.7 183.4 167.9

0.5 2.7 8.3 2.8 0.5

0.9 5.5 4.9 2.6 5.9

19.5 13.1 4.8 4.2 3.8

3984.2

4125.7

4418.2

1.5

1.0

100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Fossil Fuels

533

0−0.75 0.75−1.5 1.5−2.25 2.25−3.0 > 3.0 Fig. 9 Global map of oil consumption (tonnes) per capita in 2016. Reproduced from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 10

Oil consumption by sector (million tonnes of oil equivalent)

Sectors

Years 1995

2000

2005

2010

2015

2020

2025

2030

2035

Transportation Power Industry Non-combusted use Buildings sector

1555.9 291.2 592.9 401.5 444.7

1751.2 284.8 614.1 461.8 466.6

2001.2 279.7 669.8 511.1 452.6

2142.4 235.3 664.4 565.4 412.7

2351.1 238.9 670.0 589.1 408.0

2536.8 207.0 672.8 644.6 409.3

2660.1 187.6 706.1 714.0 415.3

2719.2 177.7 712.1 784.1 411.4

2756.9 164.0 709.0 859.2 403.1

Total

3286.2

3578.5

3914.3

4020.2

4257.1

4470.5

4683.0

4804.5

4892.1

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Fig. 9 however demonstrates a global map of oil consumption per capita in 2016. Based on this, while the United States, China, India, Japan, and Saudi Arabia are the top five oil consuming nations in total, Saudi Arabia, South Korea, Canada, and the United States are the highest per capita oil consuming nations in the world. Tables 10 and 11 show the sectoral oil consumptions in the period of 1995–2015, and the consumption projections until 2035, as well as the relevant changes in sectoral consumption. Based on this report, in the past 20 years, transportation and industrial use of oil had their leading shares of total global oil consumption (47.3% and 18%, respectively, and with a total of 65.3% in 1995; and 55.2% and 15.7%, respectively, and with a total of 70.9% in 2015). In the next 20 years, transportation is forecasted to maintain its leading position with a projected share of 56.4%; however, it is expected to be followed by non-combusted use of oil with a share of 17.6% instead of industrial use with 14.5% share in 2035. As mentioned earlier, in 2015, global energy consumption from oil occupied 32.4% of total primary energy consumption, and we see that approx. 55% of which was utilized in transportation sector. Tables 10 and 11 show that except for the consumption in power and building sectors, the oil consumption in other sectors has increased since the 1990s and this trend is expected to continue through 2035. Due to the environmental concerns growing more every passing year, less high-sulfur oil is used in power generators [21]. The share of transportation sector in oil consumption, however, is not projected to change much, and will maintain its share in the next 20 years. Although renewable energy sources have been exploited for the past few decades, the alternative products are not expected to grow with rapid rates in the short-term. These substitutions still need to experience a longterm evolution period to overcome the technology problems and market acceptance challenges. Consequently, the global oil

534

Table 11 equivalent) Regions

Fossil Fuels

Changes in sectoral oil consumption between 1995 and 2015 and 2015 and 2035 (consumption levels are in million tonnes of oil

1995

1995 Total share (%)

Transportation 1555.9 Power 291.2 Industry 592.9 Non-com401.5 busted use Buildings 444.7 sector Total

2015

2035

2015 Total share (%)

2035 Total share (%)

1995–2015 Change (%)

2015–35 2015–35 Annual Change (%) change (%)

1995–2015 Annual change (%)

47.3 8.9 18.0 12.2

2351.1 238.9 670.0 589.1

55.2 5.6 15.7 13.8

2756.9 164.0 709.0 859.2

56.4 3.4 14.5 17.6

51.1 18.0 13.0 46.7

2.4 0.9 0.6 2.2

17.3 31.4 5.8 45.8

0.8 1.5 0.3 2.2

13.5

408.0

9.6

403.1

8.2

8.2

0.4

1.2

0.1

4892.1 100.0

29.5

1.4

14.9

0.7

3286.2 100.0

4257.1 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

37.6

266.7

24.5

54.8

67.4 27.3 160.8

20.9

188.6

153.3

67.0 42.1

34.6

24.4

199.1

49.3

33.2

58.4 89.5

69.9

46.5

24.4

33.5

41.3 153.8

89.4

270.8 21.8

United States Canada Mexico S & C America Europe and Eurasia Middle East Africa Asia Pacific

42.3

70.7

22.4 28.9 60.1

27.7 54.2

Fig. 10 Major oil trade movements (million tonnes) in 2016. Reproduced from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

demands are likely to remain at a higher level over the next decades [6,9,12]. The WEC [7] confirmed that the oil industries have already experienced a structural transition. The majority of the oil market switched to developing and emerging economic areas, and advanced technologies greatly improved the energy efficiency [7]. Fig. 10 shows the major oil trade movements in 2016. While Canada, the Middle East, Russian Federation, and the South and Central America are the main regions of oil outflow, the United States, China, Europe, and other regions are the main oil importing regions in the world.

1.12.2.4

Peak Oil

Peak oil, based on the theory of M. King Hubbert, is defined as the point in time when the maximum rate of extraction of crude oil is reached, and after that the extraction is expected to enter final decline [64]. Peak oil is based on the observed rise, peak, fall, and depletion of aggregate production rate in oil fields over time. It is frequently mixed with oil depletion; however, peak oil is indeed the point of maximum production, while depletion is a falling period of reserves and supply instead.

Fossil Fuels

535

14

Production (109 bbls/y)

12

Proven reserves 250×109 bbls

10 8 6 4

Future discoveries 910×109 bbls

Cumulative production 90×109 bbls

2 0 1850

1900

1950

2000

2050

2100

2150

2200

Year Fig. 11 A 1956 world oil production distribution, showing historical data and future production, proposed by M. King Hubbert – it has a peak of 12.5 billion bbls per year in about the year 2000. New presentation of data in Fig. 20 of Hubbert Peak of Oil Production. Available from: http:// www.hubbertpeak.com/hubbert/1956/1956.pdf [accessed 21.10.17].

Even though predictions vary greatly as to what exactly the effects would be, the experts predict negative global economy implications after a post-peak production decline and subsequently an increase in oil price due to the high dependence of most agricultural, industrial, and transport systems on the high availability and low cost of oil [65,66]. Pessimistic future oil production predictions made after 2007 stated that the oil peak had already occurred [67–70], or would occur shortly [71,72]. Optimistic estimations [73], on the other hand, forecast the global decline in oil production will begin after 2020 (see Fig. 11). In these optimistic approaches, it is assumed that major investments in alternatives would take place before the actual crisis occurs, hence requiring no major changes in the lifestyles of oil consuming nations. It should however be noted that Hubbert's original predictions for world peak oil production proved premature [73]. Furthermore, Hubbert's prediction for US peak oil (which was about to happen in 1970) seemed accurate, and the average annual production eventually peaked at 9.6 million bbls per day in 1970 [74]. However, the application of hydraulic fracturing to tight oil reservoirs caused the US production to rebound, and proved that there is a need for new predictions for the US oil production under the light of new technological developments [75]. BP Statistical Review of World Energy 2017 [62] reported that top oil producing regions (the Middle East, Russian Federation, and the United States) had oil production increases of 50%, 77%, and 50%, respectively, for 1995–2015 period; and projects further oil production increases of 29%, 11%, and 26%, respectively, for 2015–35 period. It also reported that a 37% increase in global oil supply took place for 1995–2015 period, and projects that a 12% increase in global oil supply will occur for the period of 2015–35.

1.12.2.5

Environmental Impacts of Oil

One of the main sources of environmental pollution is producing or burning fossil fuels like oil, coal, and natural gas. The largest human source of CO2 emissions is from the combustion of fossil fuels. This produces 87% of human CO2 emissions. In 2011, fossil fuel use created 33.2 billion tonnes of carbon dioxide emissions worldwide [76]. During the process of production and combustion of fossil fuels, pollutants, such as particulate matter (PM), SO2, and NOx, are released to the environment; at the same time, a significant amount of CO2 is also released, which is the main cause of greenhouse effect, hence global warming. IEA in 2012 [77] reported that 36% of CO2 emissions is produced by oil. The evaporation or incomplete combustion of fossil fuels release volatile organic compounds (VOCs) as well. Furthermore, methane (CH4) – that is, natural gas – itself is also a greenhouse gas, which has approx. 22 times greater global warming potential than that of CO2. In the United States alone, more than 90% of greenhouse gas emissions come from the combustion of fossil fuels [78]. Combustion of fossil fuels also releases heavy metals, such as As, Cd, Cr, Ni, Mn, and Pb, that cause air pollution. As well, almost each step of the oil production process has significant impacts on water resources [79]. For instance, steam injection and hydraulic fracturing are two common techniques used for extracting oil from reservoirs, which lead to contamination of water [3,60]. Oil fields usually contain a large volume of water and gas, so water or steam are frequently injected into reservoirs to maintain the pressure. After that, more steam is injected and the pressure is utilized to push oil up through the well [80,81]. In some cases, hydraulic fracturing is applied for deep source extraction procedures (1500–1600 m) [81,82]. However, extraction of oil requires a lot of water withdrawal; and meanwhile, it contaminates the water. The polluted water that comes from the oil extraction process is called produced water [58,83]. The components in the produced water are complex, including heavy metals,

536

Fossil Fuels

hydrocarbons, hydrogen sulfide, organic acids and other chemicals added through the extraction and separation processes [84–86]. The amount of produced water that is generated from oil production has been estimated about three times as much as the amount used for crude oil [79]. In the past few decades, most of the produced water is discharged directly into surrounding aquatic systems without any treatment, resulting in groundwater and even ocean contamination [87]. Oil spills are another direct environmental concern that happens regularly during transportation of oil from place to place. Similarly, a large amount of oil may leak from underground storage tanks and flow into underground water resources [88]. Oil production also causes indirect impacts on water quality. For instance, pollutants are released into the atmosphere during combustion of fuels. However, these particles can return to the water systems with precipitation [58]. Unconventional oil mining, on the other hand, requires a massive amount of water and energy to refine and separate crude oil [85]. Obviously, the generation of produced water is immense, thereby causing severe water pollution.

1.12.2.5.1

Case Study: Oil sands production in Alberta, Canada

The WEC survey on oil energy resources indicated that reserves in Canada comprise 2508 million m3 of oil sand and natural bitumen [7]. In recent years, oil sands production in Alberta has dramatically expanded, with about 100 to 255 million liters of bitumen production per day since 2000 [89,90]. The research in the oil sands reservoirs found that the expansion of the oil sands exploitation has negative impacts on local land use, air and water resources. For instance, surface mining extraction of 158 L bitumen requires about 480–720 L of water [91,92]. Jordan [196] suggested that water use can be reduced by an in site recovery technology or operators could switch to using brackish water [91,93]. In fact, it is suspected that the water availability from the Athabasca River, where oil sands extraction occurs, will decline because of uncertain climate changes in the near further. That will bring a difficult time in winter as flows are naturally lower in winter months [94,95]. As a result, the water withdrawals during the winter months would impact the aquatic habitats because of declined dissolved oxygen content in the river. This can subsequently change the spawning and hatching time for some species [91,96,97]. Government of Alberta offered that there was no sufficient information about oil sand development impacts on water quality; however, in the oil production regions it was observed that the levels of seven pollutants, including cadmium, copper, lead, mercury, nickel, silver, and zinc, exceeded the standard limits for protecting aquatic systems [98,99]. Moreover, tailing ponds (see Fig. 5) are used to store the produced water after bitumen extraction. Since produced water contains a variety of toxic chemicals, tailing ponds have killed over 1600 birds as they landed on the ponds [100,101]. It has been reported that about 11 million liters of tailings were generated per day in 2007, and the number is rapidly increasing [102]. The concerns for water scarcity and water quality issues in Alberta oil sand resources have grown; so it is expected to have more transparent data and improved management of potential environmental risks.

1.12.3

Natural Gas

Natural gas is a hydrocarbon gas mixture mainly consisting of methane (CH4), varying amounts of other higher alkanes, and sometimes a small portion of carbon dioxide, nitrogen, hydrogen sulfide, or helium [103]. Natural gas forms when layers of decomposing biogenic material are exposed to very high temperatures and pressures under the surface of the Earth over millions of years. It is often referred to as “gas” when compared to other energy forms, such as oil or coal; and is a nonrenewable fossil fuel resource that is used as a source of energy for heating, cooking, and electricity generation, as fuel for vehicles, and as a chemical feedstock for manufacturing fertilizer, plastics, paints, and other chemicals. Natural gas comprised 24% of world’s primary energy use in 2015 [62] and is most commonly used to produce heat or electricity for buildings or industrial processes. It is most commonly transported by pipeline; however, natural gas is increasingly being transported by ship in a liquefied form (liquefied natural gas, LNG) to meet greater global demand for the fuel. Natural gas is found isolated in natural gas fields in deep rock formations or associated with coal reservoirs as coalbed methane, and in close proximity to and with oil fields [104]. Most natural gas is formed over time by biogenic and thermogenic mechanisms [105]. Biogenic gas is formed by methanogenic organisms in marshes, bogs, landfills, and shallow sediments, while thermogenic gas is created from buried biogenic material deeper in the Earth at greater temperatures and pressures [106,107]. It usually contains a significant amount of ethane, propane, butane, and pentane, which are removed for commercial use prior to the methane being sold as a fuel or chemical feedstock. Non-hydrocarbons, such as carbon dioxide, nitrogen, helium, and hydrogen sulfide, are also removed before the natural gas is transported [108]. In petroleum production, natural gas is often burnt as flare gas, which is estimated by the World Bank that over 150 km3 of natural gas is flared or vented annually [109]. Natural gas, which is primarily composed of methane, is also generated by the decomposition of municipal waste in landfills and manure from livestock production. Methane is a greenhouse gas that is more than approx. 22 times as potent as carbon dioxide. Capturing and burning the gas to produce usable heat and power prevents the methane from being released from the landfill or feedlot into the atmosphere directly. Before natural gas can be used as a fuel, not always, but most of the time, is processed to remove impurities, such as water, to meet the specifications of marketable natural gas. The by-products of such processing include ethane, propane, butanes, pentanes, and higher molecular weight hydrocarbons, hydrogen sulfide (can be converted into pure sulfur), carbon dioxide, water vapor, and sometimes helium and nitrogen [110].

Fossil Fuels 1.12.3.1

537

Sources of Natural Gas

It was reported [105] that natural gas, resulted from the drilling for brines, was accidentally discovered in ancient China, and used to boil brine to make salt [111]. Natural gas was first used by the Chinese in about 500 BC (possibly even 1000 BC) [112]. The Chinese discovered a way to transport natural gas seeping from the ground in simple pipelines of bamboo to where it was used to boil salt water to extract the salt [113], in the Ziliujing District of Sichuan [111]. However, the world's initial industrial extraction of natural gas started in 1825 at Fredoni, New York, United States [114]. Natural gas was usually obtained as a by-product of producing oil in the 19th century due to the light gas carbon chains came out of solution as the extracted fluids went through pressure reduction from the reservoir to the surface. This unwanted natural gas posed a disposal problem in the active oil fields, and was burned off at oil fields. However, unwanted gas associated with oil extraction today is often returned to the reservoir with injection wells and wait for a possible market in future. When it becomes economically feasible to transport natural gas from a well site to an end user, pipelines are built in high natural gas demand regions, and mainly used in power generation, while other uses for natural gas include exporting as LNG or conversion of natural gas into other liquid products using GTL technologies, which can convert natural gas into liquids products, such as gasoline, diesel, or jet fuel. Gas liquefaction is one of the advanced technologies that make natural gas transportation more convenient. Pollutants, such as heavy metal, CO2, and H2S, need to be removed, and then natural gas is compressed into LNG through refrigeration processing [11,115]. Apparently, sufficient regasification terminals are required to support gas liquefaction. Nowadays, more and more countries are using LNG and the market is expected to expand in the near future [116]. Many studies predict that natural gas will account for a larger portion of electricity generation and heat in the future [117]. The natural gas industry is extracting an increasing quantity of gas from challenging resource types, such as coalbed methane, tight natural gas, and shale gas.

1.12.3.2

Natural Gas Reserves

Fig. 12 shows the global map of natural gas reserves in 2014. The gas reserves are broadly however unevenly distributed around the world. And there is no agreement on which country has the largest proved natural gas reserves. The US CIA (47,600 km³) [118], the US Energy Information Administration (EIA) (47,800 km³) [119], and OPEC (48,700 km³) [120], consider that Russia has the largest proved reserves. However, BP credits Russia with only 32,900 km³, which would put it in second place, just behind Iran (33,100 to 33,800 km³, depending on the source) (also see Table 12). Major proven resources (in km³) at the end of 2016 are world 186,600, Iran 33,500 (18.0% of total world), Russian Federation 32,300 (17.3%), Qatar 24,300 (13.0%), Turkmenistan 17,500 (9.4%), and the United States 8,700 (4.7%) (Table 12). The world's largest gas field is the offshore South Pars/North Dome Gas-Condensate field, shared between Iran and Qatar. It is estimated to have 51,000 cubic kilometers of natural gas and 50 billion bbls (6 km³) of natural gas condensates. In 2015, natural gas had already accounted for 21.5% of global power generation with the largest growth in total primary energy. This number is expected to maintain its share through 2035 [62]. Moreover, natural gas is

Billion cubic meters (Bm3) ≥ 10,000 Bm3 ≥ 3000 Bm3 ≥ 1000 Bm3 ≥ 100 Bm3 ≥ 50 Bm3 ≥ 10 Bm3 ≥ 1 Bm3 > 0 Bm3 0 Bm3

Countries by natural gas proven reserves (2014) Fig. 12 Global map of natural gas reserves in 2014. The map is Ali Zifan’s work, which was prepared using data from CIA World Factbook. Reproduced from Wikipedia. Available from: https://commons.wikimedia.org/wiki/File:Countries_by_Natural_Gas_Proven_Reserves_(2014).svg [accessed 21.10.17].

538

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Table 12

Proved natural gas reserves in top five countries between 1996 and 2016 (reserve levels are in trillion cubic meters) Reserves-to-production (R/P) ratio

Countries

1996

2016

Share of total (%)

Iran Russian Federation Qatar Turkmenistan United States

23.0 30.9 8.5 n/a 4.7

33.5 32.3 24.3 17.5 8.7

18.0 17.3 13.0 9.4 4.7

165.5 55.7 134.1 261.7 11.6

Total world

123.5

186.6

100.0

52.5

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

160

North America S & C America Europe and Eurasia Africa

600

Middle East Asia Pacific World

500 120 400

300

80

200 40 100

North S & C Europe America America and Eurasia

Middle East

Africa

Asia Pacific

0

86

91

96

01

06

11

16

0

Fig. 13 2016 (Left) and history (right) of regional natural gas reserves-to-production (R/P) ratios (years). Reproduced from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

regarded as the cleanest energy resource among the three types of fossil fuels. According to the data provided by BP [62], with the development of exploitation technology, the natural gas reserves have intensively increased by 51.1% over the past 20 years. Having the Middle East the highest natural gas R/P ratios (4120 years, see Fig. 13), it is presently expected to expand further as unconventional natural gas sources are taking part in the overall picture. There are three main types of unconventional natural gas, including coalbed methane, tight natural gas, and shale gas [58]. Currently, the global resources of unconventional natural gas reservoirs have not been fully calculated, so it is hard to determine their total proved volumes. However, it is estimated that there are about 900,000 km³ of unconventional natural gas, such as shale gas, of which 180,000 km³ may be recoverable [121]. Shale gas has become a major source of natural gas in the United States and Canada since 2000 [122]. After the success in the United States, shale gas exploration has begun in other countries, such as China, Poland, and South Africa [123–125]. Due to this increase in shale production, the United States is now the number one natural gas producer in the world [126]. Unconventional natural gas resources have a great prospect in natural gas markets because of limited resources of conventional natural gas [127,128]. In unconventional natural gas reservoirs, their forms of natural gas are trapped by rocks and the permeability is very low [58]. Technology methods are thereby playing a critical role in this situation. For instance, hydraulic fracturing and fractionation are common ways that help to significantly improve the production efficiency from various types of unconventional natural gas sites [58,128]. Water requirements are indispensable as well. The US Environmental Protection Agency (EPA) reported that fractionation method consumed approximately 7–19 million liters of water, and this recovery technology is responsible for groundwater contamination as produced water is released along with the extraction processes [129]. Even though many defects have been discussed, Allen et al. [58] indicated that countries, such as China and India, still plan to apply the fractionation method because there is no alternative option. As a result, the scale of contamination of water might be exacerbated around the world.

Fossil Fuels 1.12.3.3

539

Natural Gas Production, Demand, and Trade

According to the data provided by BP released in 2017 [62], following oil (32%) and coal (29%), natural gas was the world’s third largest (24%) source of primary energy in 2015 (see Table 30). However, the share of natural gas, with a projected change of 38% between the years 2015 and 2035, is expected to rise to 25% making natural gas the world’s second largest source of primary energy in 2035. Fig. 14 below shows the global distribution of natural gas producing nations in 2014. BP Energy Outlook 2017 [62] provided a detailed report for the current and past 20 year oil production data as well as the projections for the next 20 years. According to this report, as mentioned earlier, annual production in million tonnes of oil equivalent (mtoe), oil, coal, and natural gas provided 85.4% of primary energy production in 2015 (32.4% þ 29.2% þ 23.9%, respectively). Table 13 indicates that global natural gas production in 2015 increased by 67.9% compared to that in 1995, and is projected to increase further in the next 20 years (35.9% based on the 2015 production). In the past 20 years, the main increases in production have been in the Middle East, North America, and Asia Pacific, while a slight decline in natural gas production was observed in Europe. The increasing trends in natural gas production are expected to continue in these regions with the addition of the CIS, and with further decline to be observed in Europe. Table 14, on the other hand, shows the regional natural gas productions in 1995, 2015, and projected natural gas production in 2035, as well as the relevant changes in regional production. As mentioned earlier, the main changes have been and will be in the Middle East, Asia Pacific, and North America, while there is a major decline in natural gas production in Europe. Based on this report, North America, the CIS, and the Middle East will continue to preserve their leading shares of global natural gas production,

+ 100.000.000.000 m3 + 10.000.000.000 m3 + 1.000.000.000 m3 + 100.000.000 m3 + 1.000.000 m3 No production

Fig. 14 Global map of natural gas production in 2014. The map is Ali Zifan’s work, which was prepared using data from CIA World Factbook. Reproduced from Wikipedia. Available from: https://commons.wikimedia.org/wiki/File:Countries_by_Natural_Gas_Proven_Reserves_(2014).svg [accessed 21.10.17].

Table 13

Natural gas production by region (million tonnes of oil equivalent)

Regions

Years 1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

2000

2005

2010

2015

2020

2025

2030

2035

651.7 68.1 218.6 569.1 134.1 76.8 187.4

693.9 91.0 256.3 584.1 189.6 119.4 251.3

683.0 126.5 270.6 651.7 288.9 159.3 339.3

745.2 149.6 256.1 657.0 446.0 192.0 448.0

900.4 160.6 214.4 676.5 556.1 190.6 501.0

1036.6 159.5 189.8 749.9 604.7 190.7 642.5

1128.9 161.7 165.2 824.5 673.5 211.1 678.4

1275.8 165.0 135.1 854.9 733.1 237.2 708.8

1330.7 168.8 111.6 881.4 792.8 280.3 756.0

1905.7

2185.5

2519.4

2893.9

3199.5

3573.6

3843.4

4109.8

4321.5

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

540

Fossil Fuels

Table 14 Changes in regional natural gas production between 1995 and 2015 and 2015 and 2035 (production levels are in million tonnes of oil equivalent) Regions

1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

1995 Total 2015 share (%)

2015 Total 2035 share (%)

2035 Total 1995–15 share (%) Change (%)

2015–35 1995–15 Annual change Change (%) (%)

2015–35 Annual change (%)

651.7 68.1 218.6 569.1

34.2 3.6 11.5 29.9

900.4 160.6 214.4 676.5

28.1 5.0 6.7 21.1

1330.7 168.8 111.6 881.4

30.8 3.9 2.6 20.4

38.2 135.9 1.9 18.9

1.8 6.5 0.1 0.9

47.8 5.1 47.9 30.3

2.3 0.2 2.3 1.4

134.1 76.8 187.4

7.0 4.0 9.8

556.1 190.6 501.0

17.4 6.0 15.7

792.8 280.3 756.0

18.3 6.5 17.5

314.5 148.3 167.4

15.0 7.1 8.0

42.6 47.0 50.9

2.0 2.2 2.4

4321.5 100.0

67.9

3.2

35.1

1.7

1905.7 100.0

3199.5 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 15

Natural gas production in top five countries between 2006 and 2016 (production levels are in billion cubic meters)

Countries

2006

2011

2016

Annual growth rate (%) 2016

United States Russian Federation Iran Qatar Canada Total world

2005–15

Share of 2016

520.0 595.2 111.5 50.7 171.7

648.5 607.0 159.9 145.3 144.4

749.2 579.4 202.4 181.2 152.0

2.5 0.5 6.6 1.3 1.7

4.1 0.1 6.4 14.6 1.3

21.1 16.3 5.7 5.1 4.3

2876.7

3290.2

3551.6

0.3

2.4

100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

having Asia Pacific with further production increases through 2035, while Europe decreasing its share with major reduction in natural gas production. Overall, there has been an annual increase (3.3%) with 67.9% total increase in global natural gas production in the period of 1995–2015, and the annual increase is expected to happen around 1.7% with 35.1% total change in the period of 2015–35. Table 15 presents the top natural gas producing nations in the past 10 years with their relevant growth rates and shares of global natural gas production. Based on this report, the United States, Russian Federation, and Iran (after replacing Canada) have consistently been the top producers of natural gas. The United States alone, in 2016, produced 749.2 billion cubic meters of natural gas, 21.1% of 3551.6 billion cubic meters of world natural gas production. Other major producers in the same year were Russian Federation with 579.4 billion cubic meters of production (16.3% of the world’s total), Iran with 202.4 billion cubic meters (5.7% of the world’s total), Qatar with 181.2 billion cubic meters (5.1% of the world’s total), and Canada with a production of 152.0 billion cubic meters (4.3% of the world’s total). The International Energy Outlook in 2016 reported that global natural gas consumption is projected to increase from 3.4 to 5.8 trillion m3 during 2012 to 2040 [11]. Table 16 as well shows that consumption continued to increase globally between the years 1995 and 2015 with a 63.0% increase globally, and is projected to increase further in the next 20 years (37.7% based on the 2015 consumption). The main increase in absolute natural gas consumption has been and will continue to be in Asia Pacific, the Middle East and North America. Table 17, on the other hand, reports the regional natural gas consumptions in 1995, 2015, and projected natural gas consumption in 2035, as well as the relevant changes in regional consumptions. Based on this report, North America and the CIS (although dropped from 24.5% in 2005 to 15.7% in 2015) continued to preserve their leading shares of global natural gas consumption in the past 20 years, with Europe having some drop in consumption (18.2% in 1995 to 13.1% in 2015) and Asia Pacific having a further consumption increase (9.9% in 2005 to 20.1% in 2015). Europe had the third largest share in global natural consumption in 1995; however, the share dropped in 2015 moving it to the fifth place, and is expected to drop further in between 2015 and 2035 reaching 11.4%. It is also expected that North America (with a total share of 26.0%) and Pacific Asia (with 25.9%) will maintain their leading consumptions, while the Middle East (with 15.8%) taking the third place and replacing the CIS (with 11.5%) by 2035. Overall, an annual increase in global natural gas consumption (3.0%) with a 63.0% total change in

Fossil Fuels

Table 16

541

Natural gas consumption by region (million tonnes of oil equivalent)

Regions

Years 1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

2000

2005

2010

2015

2020

2025

2030

2035

673.8 67.7 350.6 472.2 126.9 42.7 189.9

720.5 85.2 420.0 467.7 171.4 51.8 268.6

711.5 111.1 481.7 502.5 251.4 76.5 369.8

770.0 135.8 494.6 509.8 359.5 96.5 520.5

880.7 157.3 412.2 490.9 441.2 121.9 631.0

992.4 164.7 459.4 491.5 501.2 134.4 800.0

1026.9 172.3 458.5 496.0 564.9 157.4 921.6

1096.4 183.6 475.9 499.6 620.6 185.7 1032.7

1123.6 186.5 492.0 494.6 682.7 220.0 1119.1

1923.8

2185.3

2504.5

2886.7

3135.2

3543.7

3797.6

4094.5

4318.5

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 17 Changes in regional natural gas consumption between 1995 and 2015 and 2015 and 2035 (consumption levels are in million tonnes of oil equivalent) Regions

1995

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific Total

2015 Total 2035 share (%)

1995 Total 2015 share (%)

2035 Total 1995–2015 1995–2015 share (%) Change (%) Annual change (%)

2015–35 Change (%)

2015–35 Annual change (%)

673.8 67.7 350.6 472.2

35.0 3.5 18.2 24.5

880.7 157.3 412.2 490.9

28.1 5.0 13.1 15.7

1123.6 186.5 492.0 494.6

26.0 4.3 11.4 11.5

30.7 132.4 17.6 3.9

1.5 6.3 0.8 0.2

27.6 18.6 19.4 0.8

1.3 0.9 0.9 0.0

126.9 42.7 189.9

6.6 2.2 9.9

441.2 121.9 631.0

14.1 3.9 20.1

682.7 220.0 1119.1

15.8 5.1 25.9

247.8 185.4 232.3

11.8 8.8 11.1

54.8 80.4 77.3

2.6 3.8 3.7

4318.5 100.0

63.0

3.0

37.7

1.8

1923.8 100.0

3135.2 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 18

Natural gas consumption in top five countries between 2006 and 2016 (production levels are in million tonnes)

Countries

2006

2011

2016

Annual growth rate (%) 2016

United States Russian Federation China Iran Saudi Arabia Total world

2005–15

Share of 2016

614.4 415.0 59.3 112.0 73.5

683.1 424.6 137.1 162.2 92.3

778.6 390.9 210.3 200.8 109.4

0.4 3.2 7.7 5.0 4.4

2.2 0.2 15.0 6.4 3.9

22.0 11.0 5.9 5.7 3.1

2850.6

3245.9

3542.9

1.5

2.3

100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

consumption was observed between the years 1995 and 2015, and the annual increase is expected to take place around 1.8% with a 37.7% total change in the next 20 years. Table 18 presents the top natural gas consuming nations in the past 10 years with their relevant growth rates and shares of global oil consumption. Based on this report, the United States has consistently been the top consumer of natural gas followed by Russian Federation, and China, with their shares of 2016 as 22.0%, 11.0%, and 5.9%, respectively. It should be noted that the United States is burning almost quarter of the global natural gas production (more than what it produces) and the trend is expected to continue due to its high energy demand. Fig. 15 however demonstrates a global map of natural gas consumption per capita in 2016. Based on this, while the United States, Russian Federation, China, Iran, and Saudi Arabia are the top five oil consuming nations in total, the United States, Canada, Russian Federation, Iran, and Saudi Arabia are the highest per capita oil consuming nations in the world.

542

Fossil Fuels

0−0.5 0.5−1.0 1.0−1.5 1.5−2.0 > 2.0 Fig. 15 Global map of natural gas consumption (tonnes of oil equivalent) per capita in 2016. Reproduced from BP. Available from: http://bp.com/ statisticalreview [accessed 21.10.17].

Table 19

Natural gas consumption by sector (million tonnes of oil equivalent)

Sectors

Years 1995

Transportation Power Industry Non-combusted use Buildings sector Total

2000

2005

2010

2015

2020

2025

2030

2035

1.9 562.2 721.9 95.3 542.5

3.2 686.8 802.6 113.7 579.0

10.9 879.9 859.8 129.9 623.9

29.6 1082.5 961.9 149.5 663.2

43.3 1187.9 1073.1 171.9 659.0

54.6 1337.0 1238.6 195.4 718.0

76.0 1415.3 1338.4 228.3 739.6

105.1 1549.0 1415.2 261.4 763.8

138.7 1613.8 1479.5 294.5 792.1

1923.8

2185.3

2504.5

2886.7

3135.2

3543.7

3797.6

4094.5

4318.5

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

As mentioned earlier, global energy consumption from natural gas occupied approx. 23.9% of total primary energy consumption, we see that approx. 37.9% and 34.2% (72.1% in total) of which were utilized for power generation and industrial use in 2015, respectively. Tables 19 and 20 show that natural gas consumption in all sectors has dramatically increased for the past 20 years; and having the highest percent changes in transportation and power sectors, this trend is expected to continue until the year 2035. Although renewable energy sources have been exploited for the past few decades, they are not expected to grow with rapid rates to fill the needs particularly in power and industry sectors in the short-term. Due to the environmental concerns growing more every passing year, the increase in natural gas consumption in all sectors is expected to increase further through 2035 because it is considered a clean burning fossil fuel. Fig. 16 shows the major natural gas trade movements in 2016. While Canada, the Middle East, the CIS (mainly Russian Federation, Turkmenistan, and Azerbaijan) are the main regions of natural gas exporting regions, Europe, Asia Pacific, the United States, and other regions are the main natural gas importing regions in the world.

1.12.3.4

Peak Gas

Natural gas is a finite resource and therefore considered as a nonrenewable energy source. According to the peak theory, peak gas is the point in time when the maximum global natural gas production rate will eventually be reached. After this time, the rate of production will enter its eventual decline [130]. This concept follows from Hubbert peak theory, which is most

Fossil Fuels

543

Table 20 Changes in sectoral natural gas consumption between 1995 and 2015 and 2015 and 2035 (consumption levels are in million tonnes of oil equivalent) Regions

Transportation Power Industry Non-combusted use Buildings sector Total

1995

1995 Total share (%)

2015

2015 Total share (%)

2035

2035 Total share (%)

1995–2015 Change (%)

1995–2015 Annual change (%)

2015–35 2015–35 Annual Change (%) change (%)

1.9 562.2 721.9 95.3

0.1 29.2 37.5 5.0

43.3 1187.9 1073.1 171.9

1.4 37.9 34.2 5.5

138.7 1613.8 1479.5 294.5

3.2 37.4 34.3 6.8

2163.3 1,11.3 48.7 80.3

103.0 5.3 2.3 3.8

220.6 35.9 37.9 71.3

10.5 1.7 1.8 3.4

542.5

28.2

659.0

21.0

792.1

18.3

21.5

1.0

20.2

1.0

4318.5 100.0

63.0

3.0

37.7

1.8

1923.8 100.0

3135.2 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

143.0

24.7 23.2 82.4

21.9

1.2

21.7

25.6

9.5 20.9 12.5

10.5 23.8 9.2 36.9

4.4

14.2

6.7

34.2

38.4 20.0 15.0

1.1 United States Canada Mexico S & C America Europe and Eurasia Middle East Africa Asia Pacific

8.4

6.4

1.4

34.4

8.8

8.8

10.4 5.8

15.7 29.2

7.1

8.3

2.5

Pipeline gas LNG

Fig. 16 Major natural gas trade movements (billion cubic meters) in 2016. Reproduced from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

commonly used for peak oil; however, gas, coal, and oil are all natural resources, and each would peak in production and be eventually depleted in a region, a country, or the world. In 1997, it was expressed that Hubbert's use of an exponential decline model was statistically adequate in explaining real world data [131]. However, longer-term experience has proved that the predictions were incorrect. Natural gas consumption has nearly doubled in the last 30 years. As expressed earlier, a number of energy agencies in the world are forecasting increases in natural gas demand in the next 20 years, having the largest increments from developing countries. Original peak theory of Hubbert forecasts that natural gas will experience three equally spaced events; first, the rate of discoveries will peak, then reserves will peak at sometime later, and finally, gas production will peak sometime after peak reserves at the same rate as the previous peak of discoveries. For example, Hubbert projected that the natural gas discovery rate was peaking for the United States in 1962 at about 20 trillion cubic feet per year. He forecasted that proved natural gas reserves would peak 8 years later (i.e., in 1970), and that production would peak after another 8 years (i.e., in 1978), at 20 trillion cubic feet per year, about the same rate as the previous peak of discoveries [132]. Among European countries, based on the 2016 data, Germany is the largest natural gas consumer followed by the United Kingdom and Italy. Natural gas reserves in Germany were 34 billion m3 at the end of 2016, the production (which has been falling

544

Fossil Fuels

drastically) was 6.6 billion m3, while the consumption was 80.5 billion m3 [62]. The United Kingdom was the second largest natural gas consumer in Europe with natural gas reserves of 206 billion m3 and production of 41.6 billion m3 at the end of 2016, while the consumption was 76.7 billion m3 [62]. The United Kingdom gets its natural gas almost entirely from the North Sea, and the North Sea gas field peaked in 2000; and its natural gas production has been falling since then. Italy is the third largest natural gas consumer after Germany and the United Kingdom. Natural gas reserves in Italy were 34 billion m3 at the end of 2016. Natural gas production (which has also been falling drastically) in 2016 was 5.3 billion m3, while consumption was 64.5 billion m3 [62]. The difference between the consumption and production in all three counties were imported. Iran holds 18.0% of the world's top gas reserves with proved reserves of 33.5 trillion m3 at the end of 2016 (see Table 12). Iran’s natural gas production has continuously been rising, and it produced 115.5 billion m3 in 2006, and 202.4 billion m3 in 2016 [62]. Russian Federation holds 17.3% of the world's gas reserves after Iran with proved reserves of 32.3 trillion m3 at the end of 2016 (see Table 12). Russian Federation’s natural gas production peaked in 2011, and is in decline since then. Russia produced 607 billion m3 in 2011 and 579.4 billion m3 in 2016 [62]. Qatar holds 13.0% of the world's gas reserves after Russian Federation with proved reserves of 24.3 trillion m3 at the end of 2016 (see Table 12). Qatar’s natural gas production has continuously been rising, and it produced 50.7 billion m3 in 2006, and 181.2 billion m3 in 2016 [62]. Hubbert, in 1956, employed an estimated ultimate recovery (EUR) of 24.1 trillion m3 to predict the United States natural gas production peak of about 396.4 billion m3 per year to happen approx. 1970 [133]. Pratt, in his EUR estimate (p. 96), explicitly included what he called the “phenomenal discovery rate” that the industry was then experiencing in the offshore Gulf of Mexico [134]. In 1962, Hubbert moved his predicted peak back a few years based on a relatively more optimistic estimation of 28.3 trillion m3 of total reserves. The new peak gas curve forecasted a peak in 1978 instead, at approx. 566.3 billion m3 per year [135]. US gas production reached a peak in 1973 at about 682.4 trillion m3, and declined for the next decade. But, new discoveries in the Gulf of Mexico even greater than anticipated, and development of unconventional reserves [136], proved Pratt's EUR estimate to be too low, and the US gas production went up again. Economist Reynolds predicted in 2005 that North American gas peak would happen in 2007 [137]. Reynolds revised his forecast in 2009 and included Southern Canada; and he predicted that the combined US (lower 48 states)-Southern Canadian gas production would peak in 2013 [138]; and based on BP Statistical Review of World Energy 2017 [62], it seems that the combined United States–Southern Canadian gas production reached a peak in 2015 with a production of 915.3 billion m3 per year. In 2005, Exxon informed that gas production peaked in North America [139]. North American natural gas production actually peaked in 2001 at 778.7 billion m3 per year, and declined to 739.1 billion m3 by 2005; but, then went up again in 2006 and 2007 to a new high of 790 billion m3 in 2007 [140], and to another new high of 969.4 billion m3 in 2015 [62]. The EIA in 2009 projected US marketed gas production will have reached a first peak at 583.3 billion m3 in 2009, decline to 535.2 billion m3 in 2013, then rise again to 658.9 billion m3 in 2035, the final year of its projection, for an average annual rate of increase of 0.47% per year during 2009–35 [141]. The EIA, in its Annual Energy Outlook 2010, forecasted a growth from 583.3 billion m3 in 2008 to 659.8 billion m3 in 2035. This represents productions of average annual growth rate 0.46% [142]. Moreover, BP Statistical Review of World Energy 2017 [62] reported that the US natural gas production rose with an annual growth rate of 4.1% between the years 2005 and 2015 with an annual decline of 2.5% in 2016 (749.2 billion m3) compared to the year 2015 (766.2 billion m3). Bentley ([143], p. 189) predicted a decline in global conventional gas production from about 2020. The EIA predicts that world gas production will continue to rise through 2030, with a total increase of almost 50%, and an average annual rate of increase of 1.6% per year, for the years between 2006 and 2030 [144]. In its March 2013 report, the Energy Watch Group predicted that global natural gas production would peak around or even before the year 2020 [145]. BP Statistical Review of World Energy 2017 [62], on the other hand, reported that a 68% increase in global natural gas supply took place for 1995–2015 period, and projects that a 35% increase will occur for 2015–35 period.

1.12.3.5

Environmental Impacts of Natural Gas

As mentioned earlier, natural gas is primarily composed of methane. After the release of methane to the atmosphere, it is removed by oxidation to CO2 and water gradually in the troposphere or stratosphere [146,147]. The lifetime of atmospheric methane is relatively short compared to that of CO2 [148], but methane, therefore natural gas, has higher global warming potential when compared to CO2. When natural gas is burned, it produces more water than CO2 by mole, compared to coal, which obviously produces primarily CO2. Natural gas produces only about half the CO2 per kilowatt-hour that coal produces. Also, natural gas produces much lower amounts of SO2, NOx, and PM emissions when compared to other fossil fuels [149], hence it is the cleanest fossil fuel. Natural gas releases almost 30% less CO2 than oil and 43% less than coal [110,150]. However, IEA in 2012 [77] reported that 20% of global CO2 emissions is produced from natural gas; therefore, it still requires close attention. Also, a large amount of produced water is generated from the extraction process, usually containing heavy metals, hydrocarbon residues and other chemicals. Clark and Veil [82] indicated that the amount of produced water is about six times gas production [151]. There was a study of water quality evaluation in drinking water wells, near natural gas extraction sites [152]. The study area was located in the Barnett Shale Formation of Texas, United States. Water samples were randomly collected from 100 different drinking water wells around the extraction sites and analyzed by analytical chemistry techniques. As compared with the EPA’s Drinking Water Maximum Contaminant Limit (MCL), Fontenot et al. [129] illustrated that water parameters, including arsenic,

Fossil Fuels

545

selenium, strontium and total dissolved solids (TDS), exceeded the drinkable standard in some wells. These wells were located within 3 km of the active natural gas extraction site, and averaged 585 mg L 1 [152]. A low concentration has also been detected in the drinking water wells located more than 3 km far from the gas extraction site. Moreover, high levels of methanol and ethanol were observed in about one-third of total drinking water wells. Fontenot et al. [129] concluded that the impact factors are complex, including hydro-geochemical changes, frequently drilling activities and industrial accidents, and other naturally occurs mobilization of constituents [152]. Since water quality became more dangerous in the study region, further research is suggested to test the long-term changes of these water parameters that are affected by natural gas extraction. Another research related to water quality was conducted in the Marcellus shale gas well in Pennsylvania, United States [153]. The analyses indicated that without any wastewater treatment, a high content of chemical oxygen demand (COD) from produced water led to eutrophication, and ecotoxicity was due to the presence of barium from produced water [153,154]. Other chemicals, such as zinc, methanol, lead, and acetone, were also detected in the samples, and there was higher potential toxicity from 2,4 D-eq, benzene-eq carcinogenic, and toluene-eq noncarcinogenic. Fortunately, a portion of produced water has been treated in Pennsylvania. The research reported that it required about $59,000 to $270,000 to treat wastewater by desalination process per shale well, which encourages future studies on reducing the treatment cost and maintain the shale gas productivity simultaneously [153,155].

1.12.4

Coal

Coal is a fossil fuel, which originates from a combustible sedimentary rock occurring in rock strata in layers or veins called coal beds or coal seams. Coal forms when dead plant matter is converted into peat, which is then converted into lignite, then subbituminous coal, after that bituminous coal, and finally anthracite. The whole process involves biological and geological processes that take place over geological time. The harder forms (e.g., anthracite coal) are regarded as metamorphic rock due to later exposure to high temperatures and pressures. Coal is primarily composed of carbon, along with variable quantities of other elements, mainly hydrogen, sulfur, oxygen, and nitrogen [156]. The history of coal goes back to thousands of years in China, and it was used as a solid fuel for cooking and heating purposes. Coal started to be used for electricity generation during the Industrial Revolution era and played an essential role in steam engines as well [157]. Nowadays, coal has developed more potential functions with innovative technologies. For instance, coal liquefaction and gasification technologies can convert coal into liquid and gas phases, thereby allowing it to be used as an alternative product to oil or applied in industries with multiple purposes as a combustible gas [158]. Coal is now primarily burned for the production of electricity and heat (was responsible for 39% of the electric power supply in the United States only in 2014 [110], and is also used for industrial purposes, such as refining metals, etc. Coal is the largest source of energy for the generation of electricity worldwide, as well as one of the largest anthropogenic sources of CO2 releases worldwide. The extraction of coal, its use in energy production, and its by-products are all have environmental and health effects including climate change [159]. Burning coal releases pollutants into the atmosphere, such as acid rain-inducing SO2, NOx, and mercury. The process of mining itself is also considered very damaging to the environment, resulting in the destruction of primarily vegetation and top-soil. Coal mine wastes can also destroy our rivers and streams. In order to express the extent, it should be noted that the combustion of coal is considered to be responsible for 32% of the greenhouse gas emissions in the United States only. Clean coal technologies have recently been promoted as a way to use this very valuable and abundant energy source without causing damage the environment. Carbon capture and storage (CCS) technologies – yet to be proven as a realistic or safe way, by which carbon is separated from coal and injected underground for long-term storage, could potentially be used to mitigate the greenhouse gas emissions from the coal industry. However, the environmental and health costs of mining still a remaining issue [110].

1.12.4.1

Sources of Coal

At a number of different times in the geologic past, the Earth had quite dense forests [160] in wetland areas. These forests were buried under the soil in time due to a number of natural processes including flooding. And they were compressed further as more soil was deposited over. As the dead plant material moved deeper in the Earth due to further deposition of soil over, the temperature and pressure also increased as a result. It is considered that the mud or acidic conditions preserved the deeply buried dead plant matter from biological degradation and oxidation. Eventually, the dead material was converted to coal through a slow process under high pressures and high temperatures. This conversion is called carbonization because coal contains primarily carbon [161]. Coal is known from most geological periods except for the Permian–Triassic extinction event, where coal is rare. However, the shallow seas of the Carboniferous Period provided the most ideal conditions for coal formation. Furthermore, coal is also known from Precambrian era, which actually predates land plants, and hence this coal is considered to have originated from algal remains [162,163]. Under proper conditions, as they are exposed to high temperatures and pressures over geological time, metamorphic grade of the dead material increases successively into:

• •

Peat: it is considered to be a precursor of coal, which has industrial importance as a fuel in some regions (e.g., Ireland and Finland). It is also used as a soil conditioner. Lignite: it is also called brown coal, which is the lowest rank of coal, and almost solely used for electric power generation.

546

• • • • •

Fossil Fuels

Subbituminous coal: its properties range between those of lignite and bituminous coal, and is used primarily as fuel for steamelectric power generation. Bituminous coal: it is a dense and usually black (sometimes dark brown) sedimentary rock, which is mainly used as fuel in steam-electric power generation and for heat in manufacturing. Steam coal: it is a grade between bituminous coal and anthracite. It was once commonly used as a fuel for steam locomotives, and also used for domestic water heating. Anthracite: this is the highest rank of coal, which is a harder and glossy black coal mainly used for residential and commercial space heating. It is further divided into metamorphically altered bituminous coal and petrified oil. Graphite: it is one of the more difficult types of coal to ignite, and is not generally used as fuel.

1.12.4.2

Coal Reserves

Coal, of the three fossil fuels, has the most widely distributed reserves. It is mined in many different countries (over 100) and on all continents except Antarctica. The 948 billion short tons of recoverable coal reserves estimated by the EIA are equal to about 4196 billion bbls of oil equivalent [164]. BP, in its 2017 report, estimated at 2016 end that there were 153 years R/P ratio based on proved coal reserves worldwide. Other researchers predicted that the deposits can last more than 250 years, which is considerably longer than those of oil and natural gas reserves [157]. This figure only includes reserves classified as proved; explorations by mining companies, specifically in under-explored areas, are providing new reserves of coal every passing year. The largest reserves are found in the United States, China, Russian Federation, Australia, and India (see Fig. 17 and Table 21). North America has the highest (4350 years, see Fig. 18) coal R/P ratio; however, the reserves are expected to expand further as coal resources in under-explored regions are taking part in the overall picture.

5.25 trillion BTUs

3.8 trillion BTUs 2.5 trillion BTUs 1.5 trillion BTUs 0.7 trillion BTUs 0.003 trillion BTUs

Fig. 17 Global Amap of coal reserves in 2007. Reproduced BP. BP statistical review of world energy. Avaialble from: https://commons.wikimedia. org/wiki/File:2007_Coal_Reserves_in_BTUs.png; 2010 [accesssed 28.09.10].

Table 21

Proved coal reserves in top five countries in 2016 (reserve levels are in million tonnes) Subbituminous and lignite

Anthracite and bituminous

United States China Russian Federation Australia India

221,400 230,004 69,634 68,310 89,782

30,182 14,006 90,730 76,508 4,987

251,582 244,010 160,364 144,818 94,769

22.1 21.4 14.1 12.7 8.3

381 72 417 294 137

Total world

816,214

323,117

1,139,331

100.0

153

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Total

Share of total (%)

Reserves-to-production (R/P) ratio

Countries

Fossil Fuels

547

600

North America S & C America Europe and Eurasia Middle East Asia Pacific World

400 350

500

300 400 250 200

300

150 200 100 100 50

North America

S&C America

Europe Middle East Asia and and Africa Pacific Eurasia

86

0

01

06

11

16

0

Fig. 18 2016 (left) and history (right) of regional coal reserves-to-production (R/P) ratios (years). Reproduced from BP. Available from: http://bp. com/statisticalreview [accessed 21.10.17].

Table 22

Coal production by region (million tonnes of oil equivalent)

Regions

Years 1995

2000

2005

2010

2015

2020

2025

2030

2035

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific

602.3 23.5 304.6 199.7 0.7 121.7 1009.8

614.6 34.1 241.7 191.4 0.7 130.5 1112.6

621.6 47.2 223.3 209.4 1.0 141.5 1789.5

594.0 52.9 197.2 232.0 0.7 146.8 2404.0

494.3 61.3 170.4 249.4 0.7 151.4 2702.6

463.2 65.6 145.3 257.0 0.7 153.2 2721.7

406.1 76.4 107.1 269.4 0.6 160.0 2932.8

347.0 80.5 84.6 280.7 0.6 170.2 3082.5

307.0 81.3 66.2 291.4 0.6 186.9 3217.5

Total

2262.2

2325.6

3033.6

3627.6

3830.1

3806.7

3952.4

4046.2

4150.9

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

1.12.4.3

Coal Production, Demand, and Trade

Following oil (32%), coal with a share of 29% is currently the world’s second largest source of primary energy (see Table 30). Currently, about 40% of global electricity production is contributed by coal, but this number is expected to decline due to increased shares from other renewable energy sources [165] and natural gas. Table 22 indicates that global coal production in 2015 increased by 25.1% compared to that in 1995, and is projected to increase further in the next 20 years (8.4% based on the 2015 production). The main changes have been and will be in Asia Pacific, the South and Central America, and Africa, while there is a major decline in coal production in Europe and North America. Table 23, on the other hand, shows the regional coal productions in 1995, 2015, and projected coal production in 2035, as well as the relevant changes in regional production. As mentioned above, the main changes have been and will be in Asia Pacific, the South and Central America, and Africa, while there is a major decline in coal production in Europe and North America. Coal production in the Middle East has always been negligible. Based on this report, the Asia Pacific, North America, and the CIS will continue to preserve their leading shares of global coal production having Asia Pacific and the CIS with further production increases through 2035, while North America decreasing its share with further reduction in coal production. The major decline took place in Europe and North America and will continue to drop further by 2035. Overall, there has been an annual increase (3.3%) with 69.3% total increase in global coal production in the period of 1995–2015, and the annual increase is expected to happen around 0.4% with 8.4% total change in the next 20 years.

548

Fossil Fuels

Table 23 equivalent)

Changes in regional coal production between 1995 and 2015 and 2015 and 2035 (production levels are in million tonnes of oil

Regions

1995

1995 Total 2015 share (%)

2015 Total 2035 share (%)

2035 Total 1995–2015 1995–2015 share (%) Change (%) Annual change (%)

2015–35 Change (%)

2015–35 Annual change (%)

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific

602.3 23.5 304.6 199.7

26.6 1.0 13.5 8.8

494.3 61.3 170.4 249.4

12.9 1.6 4.4 6.5

307.0 81.3 66.2 291.4

7.4 2.0 1.6 7.0

17.9 161.2 44.1 24.9

0.9 7.7 2.1 1.2

37.9 32.5 61.1 16.8

1.8 1.5 2.9 0.8

0.7 121.7 1009.8

0.0 5.4 44.6

0.7 151.4 2702.6

0.0 4.0 70.6

0.6 186.9 3217.5

0.0 4.5 77.5

0.2 24.4 167.6

0.0 1.2 8.0

18.2 23.4 19.1

0.9 1.1 0.9

Total

2262.2 100.0

4150.9 100.0

69.3

3.3

8.4

0.4

3830.1 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 24 Countries

Coal production in top five countries between 2006 and 2016 (production levels are in million tonnes of oil equivalent) 2006

2011

2016

Annual growth rate (%) 2016

2005–15

Share of 2016

China United States Australia India Indonesia

1329.4 595.1 220.4 198.2 114.2

1851.7 556.1 245.1 255.0 208.2

1685.7 364.8 299.3 280.9 255.7

7.9 19.0 2.4 2.4 6.2

3.9 2.5 3.6 4.0 11.7

46.1 10.0 8.2 7.9 7.0

Total world

3194.7

3897.3

3656.4

6.2

2.5

100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 24 presents the top coal producing nations in the past 10 years with their relevant growth rates and shares of global coal production. Based on this report, China and the United States have consistently been the top producers of coal. China alone, in 2016, produced 1685.7 million tonnes of oil equivalent coal, 44.1% of 3654.4 million tonnes of oil equivalent world coal production. Other major producers in the same year were the United States with 364.8 million tonnes of oil equivalent production (10.0% of the world’s total) – Wyoming, West Virginia, Kentucky, Pennsylvania, and Texas leading in production, Australia with 220.4 million tonnes of oil equivalent production (8.2% of the world’s total), India with 198.2 million tonnes of oil equivalent production (7.9% of the world’s total), and Indonesia with a production of 114.2 million tonnes of oil equivalent (7.0% of the world’s total). Furthermore, it is predicted that the use of coal will rise over 50% in 2030, with 97% contributed by developing countries. By contrast, the use of coal in Western Europe has reduced by 36% since 1990, and they switched to using natural gas in daily life. Table 25 too shows that, except in Europe and the United States, coal consumption continued to increase everywhere else between the years 1995 and 2015 with a 69.3% global increase compared to that in 1995, and is projected to increase further in the next 20 years (8.4% based on the 2015 consumption). Coal consumption in North America increased until 2005; however, it started to decrease thereafter, and is forecasted to maintain the decreasing trend further until 2035. The decrease in coal consumption in North America, primarily in the United States, has been compensated by other sources including natural gas, nuclear, and renewables, most of which are expected to continue to have higher shares in the mix in the next 20 years. The main increase in coal consumption has been and will continue to be in Asia Pacific. Table 26, on the other hand, reports the regional coal consumptions in 1995, 2015, and projected coal consumption in 2035, as well as the relevant changes in regional consumptions. Based on this report, as in the past 20 years, Asia Pacific, North America, and the CIS will continue to preserve their leading shares of global coal consumption with North America having some drop in consumption (26.6% in 1995 to 12.9% in 2015, and to 7.4% in 2035) and Asia Pacific, however, having a further consumption increase (total share of 77.5%) by 2035. The CIS has maintained its share and is expected to continue to do so in the next 20 years. Europe, on the other hand, had the third largest share (13.5%) in global coal consumption in 1995; however, the share dropped to 4.4% in 2015 moving it to the fourth place; and it is predicted to drop further in the period of 2015–35 reaching 1.6% only. Overall, there has been an annual increase (3.3%) with 69.3% total change in global coal consumption between the years 1995 and 2015, and the annual increase is expected to take place around 0.4% with 8.4% total change in the next 20 years.

Fossil Fuels

Table 25

549

Coal consumption by region (million tonnes of oil equivalent)

Regions

Years 1995

2000

2005

2010

2015

2020

2025

2030

2035

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific

602.3 23.5 304.6 199.7 0.7 121.7 1009.8

614.6 34.1 241.7 191.4 0.7 130.5 1112.6

621.6 47.2 223.3 209.4 1.0 141.5 1789.5

594.0 52.9 197.2 232.0 0.7 146.8 2404.0

494.3 61.3 170.4 249.4 0.7 151.4 2702.6

463.2 65.6 145.3 257.0 0.7 153.2 2721.7

406.1 76.4 107.1 269.4 0.6 160.0 2932.8

347.0 80.5 84.6 280.7 0.6 170.2 3082.5

307.0 81.3 66.2 291.4 0.6 186.9 3217.5

Total

2262.2

2325.6

3033.6

3627.6

3830.1

3806.7

3952.4

4046.2

4150.9

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 26 equivalent)

Changes in regional coal consumption between 1995 and 2015 and 2015 and 2035 (consumption levels are in million tonnes of oil

Regions

1995

1995 Total 2015 share (%)

2015 Total 2035 share (%)

2035 Total 1995–2015 1995–2015 share (%) Change (%) Annual change (%)

2015–35 Change (%)

2015–35 Annual change (%)

North America S & C America Europe Commonwealth of Independent States (CIS) Middle East Africa Asia Pacific

602.3 23.5 304.6 199.7

26.6 1.0 13.5 8.8

494.3 61.3 170.4 249.4

12.9 1.6 4.4 6.5

307.0 81.3 66.2 291.4

7.4 2.0 1.6 7.0

17.9 161.2 44.1 24.9

0.9 7.7 2.1 1.2

37.9 32.5 -61.1 16.8

1.8 1.5 2.9 0.8

0.7 121.7 1009.8

0.0 5.4 44.6

0.7 151.4 2702.6

0.0 4.0 70.6

0.6 186.9 3217.5

0.0 4.5 77.5

0.2 24.4 167.6

0.0 1.2 8.0

18.2 23.4 19.1

0.9 1.1 0.9

Total

2262.2 100.0

4150.9 100.0

69.3

3.3

8.4

0.4

3830.1 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 27

Coal consumption in top five countries between 2006 and 2016 (production levels are in million tonnes)

Countries

2006

2011

2016

Annual growth rate (%) 2016

2005–15

Share of 2016

China India United States Japan Russian Federation

1454.7 219.4 565.7 112.3 97.0

1903.9 304.8 495.4 109.6 94.0

1887.6 411.9 358.4 119.9 87.3

1.6 3.6 8.8 0.2 5.5

3.7 6.5 3.8 0.5 0.3

50.6 11.0 9.6 3.2 2.3

Total world

3293.9

3807.2

3732.0

1.7

1.9

100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 27 presents the top coal consuming nations in the past 10 years with their relevant growth rates and shares of global coal consumption. Based on this report, China has consistently been the top consumer of coal followed by India (recently changed the place with the United States) and the United States, with their shares of 2016 as 50.6%, 11.0%, and 9.6%, respectively. It should be noted that China is burning almost half of the global coal production (more than what it produces) and the trend is expected to continue due to the dramatic growth in energy demand. In many other Asian countries, the coal consumption is still increasing at high speeds to give access to urbanization and industrialization. As mentioned earlier, global energy consumption from coal occupied approx. 29% of total primary energy consumption, and we see that approx. 58.6% and 35.8% (almost 95% in total) of which were utilized for power generation and industrial use in 2015, respectively. Tables 28 and 29 show that except for the consumption in transportation and building sectors, the coal

550

Table 28

Fossil Fuels

Coal consumption by sector (million tonnes of oil equivalent)

Sectors

Years 1995

2000

2005

2010

2015

2020

2025

2030

2035

Transportation Power Industry Non-combusted use Buildings sector

6.7 1300.3 742.4 20.5 174.7

4.6 1523.3 704.1 24.6 122.6

4.6 1915.1 1022.8 36.2 151.9

3.4 2128.1 1301.4 42.6 158.9

2.7 2251.5 1374.0 56.3 155.3

2.5 2268.9 1404.5 64.8 156.2

2.4 2403.9 1444.9 70.5 145.3

2.2 2428.9 1441.2 73.0 126.9

2.1 2434.5 1421.4 73.4 101.0

Total

2244.6

2379.1

3130.6

3634.3

3839.9

3896.8

4067.0

4072.3

4032.5

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 29 equivalent) Regions

Changes in sectoral coal consumption between 1995 and 2015 and 2015 and 2035 (consumption levels are in million tonnes of oil

1995

1995 Total share (%)

Transportation 6.7 Power 1300.3 Industry 742.4 Non-com20.5 busted use Buildings 174.7 sector Total

2015

2015 Total share (%)

2035

2035 Total share (%)

1995–2015 Change (%)

1995–2015 Annual change (%)

2015–35 2015–35 Annual Change (%) change (%)

0.3 57.9 33.1 0.9

2.7 2251.5 1374.0 56.3

0.1 58.6 35.8 1.5

2.1 2434.5 1421.4 73.4

0.1 60.4 35.2 1.8

59.5 73.1 85.1 174.3

2.8 3.5 4.1 8.3

21.0 8.1 3.5 30.4

1.0 0.4 0.2 1.4

7.8

155.3

4.0

101.0

2.5

11.1

0.5

35.0

1.7

4032.5 100.0

71.1

3.4

5.0

0.2

2244.6 100.0

3839.9 100.0

Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

consumption in all other sectors has dramatically increased for the past 20 years; and having the highest percent change in noncombusted use, this trend is expected to continue until the year 2035. Due to the environmental concerns growing more every passing year, the increase in coal consumption in power generation and industrial use will slow down with further drops projected in transportation and buildings sectors by 2035. Although renewable energy sources have been exploited for the past few decades, the alternative products are not expected to grow with rapid rates to fill the needs in power and industry sectors in the short-term, and the majority of the coal market will continue to dominate in developing and emerging economic areas particularly in Asia. Fig. 19 shows the major coal trade movements (million tonnes) and the relevant projections in 2030. With respect to global coal trade, it was reported that the largest outflows in 2010 were from Australia with 328 million tonnes of coal (27% of global coal export) and Indonesia with 316 million tonnes (26%) [166], while the largest inflows were to Japan with 207 million tonnes of coal (18% of global coal import), China with 195 million tonnes (17%), and South Korea with 126 million tonnes (11%) [167].

1.12.4.4

Peak Coal

Coal is a finite resource and hence considered to be a nonrenewable energy source. Peak coal, based on the theory of M. King Hubbert, is defined as the point in time when the maximum production and consumption of coal is reached, and after that, it is assumed that production and consumption will decline steadily. The term of peak coal was initially used in connection with the finite nature of the resource; however, due to the expansion of renewable energy sources particularly in electricity generation, peak oil is now usually used with reference to a peak in coal demand specifically, which may already have occurred. The estimates for global peak coal extraction vary tremendously. Many coal organizations suggest that the peak could occur in 200 years or more, while scholarly estimates forecast that the peak could occur as soon as the near future. A 2007 study predicted that global peak coal extraction may happen around 2025 at 30% above the 2005 rate [168,169]. However, BP projects that coal production would go beyond this level even through 2035 [62]. Moreover, a 2009 research performed in Australia concluded that global coal extraction could peak sometime between the present and 2048 [170]. As discussed earlier, in 2016, the top coal-extracting countries were China (46.1% of world extraction), United States (10%), Australia (8.2%), India (7.9%), and Indonesia (7.0%) (Table 24). Except the United States, four out of these top five largest coalextracting countries had experienced significant increases in coal extraction over the previous decade. China is the world’s largest coal extractor and has the second largest reserves after the United States. The Energy Watch Group in their 2007 report predicted

Fossil Fuels

29 16

13

22 20

23

551

18

21

19

16 13 18

62

64

77

35

23 14 15

116 21

47 17

66

35

119

24 14 37

20 103

12

24

19

19 35

2002

51

2030

Fig. 19 Major coal trade movements (million metric tonnes). Reproduced from World Coal Institute. The coal resource: a comprehensive overview of coal. Available from: https://www.worldcoal.org; 2009 [accessed 21.10.17].

that the Chinese extraction would peak around 2015, and then later in their March 2013 report revised 2015 to 2020 [168,171]. Another study [172] places the peak at 2027, and the EIA forecasts that China coal extraction will continue to rise until 2030 [173]. Hubbert's analysis in 1956 originally projected that total extraction could peak in about 2150 [174], later records show that extraction already reached an energy content peak in 1998 and a tonnage peak in 2008 [175]. As well, according to the Energy Watch Group, Canadian coal extraction peaked in 1997 [168]. As discussed earlier, Australia has substantial coal resources, and is responsible for almost 40% of global coal exports worldwide. A 2009 research conducted in Australia concluded that Australian coal extraction could peak sometime after 2050 [170], while the Australian Coal Association estimates that Australia's identified black coal resources (which does not account for brown coal stocks) could last more than 200 years based on rate of extraction in 2007 [176]. Furthermore, BP Statistical Review of World Energy 2017 [62] reported that a 69% increase in global coal supply took place for 1995–2015 period, and projects that an 8% increase in global coal supply will occur for 2015–35 period.

1.12.4.5

Environmental Impacts of Coal

As discussed earlier, during the process of production and combustion of fossil fuels, pollutants, such as PM, SO2, and NOx, are released to the environment; at the same time, a significant amount of CO2 is also released, which is the main cause of greenhouse effect, hence global warming. The evaporation or incomplete combustion of fossil fuels release VOCs as well. In the United States alone, more than 90% of greenhouse gas emissions reported to come from the combustion of fossil fuels [78]. Combustion of fossil fuels also releases heavy metals, such as As, Cd, Cr, Ni, Mn, and Pb, that cause air pollution. Coal is primarily made up of carbon; therefore, it is a carbon-intensive energy source. Burning coal is the biggest single source of CO2 emissions from human activity. Coal combustion produces almost double the greenhouse gas emissions as burning gas, for the same amount of energy. Although coal generated less than 30% of the world’s energy supply in 2013, it produced 46% of global CO2 emissions [177]. Coal mining also releases the potent greenhouse gas methane. Moreover, water usage is tightly linked with coal mining, as it is used in extraction, processing, and transportation. Water quality issues frequently accompany mining activities [178]. A large volume of water is used to wash the coal to limit the undesirable chemical components, such as sulfur, mercury, and others. Then, the concentrations of these elements accumulate in wastewater, causing water pollution as they are discharged or leaked into aquatic systems [179]. A high load of these detrimental elements, especially heavy metals, persistently accumulate in the environment. Most seriously, heavy metals can incorporate into food chains, and the final

552

Fossil Fuels

victims could be humans [180]. In order to solve this problem and remediate water quality, many studies have investigated growing aquatic plants that have excellent heavy metals accumulation capacity from water bodies. This approach provides a promising and friendly option for wastewater treatment in coal mining industry [181,182]. On the other hand, coal spills during transportation can lead to indirect water contamination. In 2008, a coal ash spill caused terrible impacts on the Emory and Chinch River system in Harriman, Tennessee, United States [183]. Approximately 4.1 million m3 of fly and bottom coal ash was spilled and was responsible for high mercury concentrations in river sediments. The detection indicated that water quality was not significantly damaged by mercury; however, the total mercury concentration in sediment was three to four times higher than non-polluted areas [183]. Then, methylmercury may be produced in water by a bio-methylation process as coal ash is mixed with natural sediments [184–186]. Consequently, the coal ash spills increased the risk considerations due to neurotoxic organ mercury compound production in the river [184]. Furthermore, in some developing regions, people have to use coal contaminated water for daily requirements, such as drinking, cooking, and washing. Even worse, it could eventually force residents to leave their homes and relocate [187]. Hazardous chemicals that are released from coal-processing wastewater cause serious health risks in animals and humans.

1.12.4.5.1

Case Study: coal mining in China

Coal is still the most important and irreplaceable energy resource in China and it has been reported that it consumes over half of the world’s total coal consumption per year. According to the WEC, the proved recoverable reserves are about 114,500 million tons [7]. The coal deposits are broadly distributed in China, but it is mostly concentrated in north and northwest regions, especially in Shanxi, Henan, Heilongjiang, Shaanxi, and Inner Mongolia [188,189]. Moreover, coal power generation in China consumed about 50 billion m3 water in 2013, and it generally accounts for 92% of total thermal electricity generation in China [190,191]. A research investigated groundwater quality at the Huaibei Coalfield, which is located in the North China Plate [192]. In order to evaluate the water quality and other relevant environmental problems caused by coal mining activities in this region, the physical and chemical properties of water and concentration of trace elements and other components were analyzed. Groundwater samples were collected near the mining areas. The findings indicated that the pH, TDS, total phosphorous (TP), total nitrogen (TN), dissolved oxygen (DO), electrical conductivity, alkalinity, and hardness were higher in the shallow and confined groundwater [192]. Typically, the TDS (average at 1079 mg L 1) and electrical conductivities (average at 1327 ms cm 1) detected at the mining area exceeded the World Health Organization (WHO) permissible and recommended levels, which is 1000 mg L 1 and 400 ms cm 1, respectively [193]. These results indicated a large amount of mineral dissolutions and a high level of salinity. Also, a higher hardness might also be ascribed to a high degree of carbonate minerals. Elevated levels of TP and TN might be attributed to natural dissolutions and human activities. Hu et al. [191] reported that the evaluation of trace elements, such as As, Cd, Cr, Cu, Pb, and Zn, released from coal mining areas also showed a higher level than those in the management sites. Even though most of the concentrations of trace elements did not exceed the China groundwater quality standard, it raised the potential health risks in the adjacent communities. China is likely to continue subsidies to the coal mining industries and coal-based thermal power generators to stimulate economic development. Thus, more comprehensive studies on related environmental impacts should be undertaken to assist policymakers and local government [194].

1.12.5 1.12.5.1

Further Case Studies Case Study: Global Fossil Fuel Consumption and Supply

Table 30 below shows the global fossil fuel consumption and supply for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that, in 2015, oil, natural gas, and coal had total primary Table 30

Global fossil fuel consumption and supply (units in Mtoe unless otherwise noted) Levels

Shares (%)

Change (absolute)

Change (%)

Change (annual)a (%)

2015

2035

2015

2035

1995–2015

2015–35

1995–2015

2015–35

1995–2015

2015–35

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

93 336 3840

106 462 4032

32 24 29

29 25 24

23 129 1595

14 127 193

32 63 71

15 38 5

1.4 2.5 2.7

0.7 1.6 0.2

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

95 342 3830

107 462 4151

25 138 1568

12 120 321

37 68 69

12 35 8

1.6 2.6 2.7

0.6 1.5 0.4

a

Compound annual growth rate. Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

b

Fossil Fuels

Table 31

553

Fossil fuel consumption and supply in Africa (units in Mtoe unless otherwise noted) Levels

Shares (%)

Change (absolute)

Change (%) 1995–2015

Change (annuala) (%)

2015

2035

2015

2035

1995–2015

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

3.9 13 97

6.1 24 121

42 28 22

37 29 16

1.7 9 18

2.2 11 24

76 185 23

56 80 25

2.9 5.4 1.0

2.3 3.0 1.1

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

8.6 20 151

8.3 30 187

1.4 12 30

0.3 10 35

20 148 24

3 47 23

0.9 4.7 1.1

0.2 1.9 1.1

2015–35

2015–35

1995–2015

2015–35

a

Compound annual growth rate. Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

b

energy consumption shares of 32%, 24%, and 29% (85% in total), respectively; and it is predicted that, by 2035, the shares will be 29%, 25%, and 24% (78% in total), respectively, natural gas having the second place after oil, and that a 7% decrease in fossil fuels share in consumption will be observed in the global primary energy consumption. The highest changes in fossil fuel consumption occurred in coal with an increase of 71%, natural gas with a 63% increase, and having a 32% increase in oil consumption in 1995–2015 period; and the top changes are predicted to be in natural gas with a 38% increase, oil with a 15% more increase, and having 5% more increase in coal consumption in 2015–35 period. The highest changes in fossil fuel supply occurred in coal with an increase of 69%, natural gas with a 68% increase, and oil with a 37% increase in 1995–2015 period; and the top changes are predicted to be in natural gas with a 35% increase, oil with a 12% more increase, and coal with an 8% drop in 2015–35 period.

1.12.5.2

Case Study: Fossil Fuel Consumption and Supply in Africa

Table 31 below reports the fossil fuel consumption and supply in Africa for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that, in 2015, oil, natural gas, and coal had total primary energy consumption shares of 42%, 28%, and 22% (92% in total), respectively; and it is predicted that, by 2035, the shares will be 37%, 29%, and 16% (82% in total), respectively, natural gas increasing its share, while oil and coal reducing their shares, and that a 10% decrease in fossil fuels share in consumption is predicted in the continent’s primary energy consumption. The highest changes in fossil fuel consumption occurred in natural gas with an increase of 185%, oil with a 76% increase, and having a 23% increase in coal consumption in 1995–2015 period; and the top changes are predicted to continue to be in natural gas with a 80% increase, oil with a 56% more increase, and having 25% more increase in coal consumption in 2015–35 period. The highest change in fossil fuel supply occurred in natural gas with a 148% increase, followed by coal and oil with 24% and 20% increases, respectively, in 1995–2015 period; and the top changes are predicted to occur in natural gas with a 47% more increase, coal with a 23% more increase, and oil with a 3% decrease in 2015–35 period.

1.12.5.3

Case Study: Fossil Fuel Consumption and Supply in North America

Table 32 presents the fossil fuel consumption and supply in North America (United States-excluding US territories, Canada, and Mexico) for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that, in 2015, oil, natural gas, and coal had total primary energy consumption shares of 36%, 32%, and 15% (83% in total), respectively; and it is predicted that the shares, by 2035, will be 29%, 39%, and 7% (75% in total), respectively, natural gas increasing its share, while oil and particularly coal reducing their shares, and that an 8% decrease in fossil fuels share in consumption is predicted in North America’s primary energy consumption. The highest changes in fossil fuel consumption occurred in natural gas with an increase of 30%, coal with a 20% drop, and having an 11% increase in oil consumption in 1995–2015 period; and the top changes are predicted to be in coal with a further drop of 51%, natural gas with a 28% more increase, and having 13% drop in oil consumption in 2015–35 period. The highest change in fossil fuel supply occurred in oil and natural gas with 41% and 37% increases, respectively, while having an 18% decrease in coal supply in 1995–2015 period; and the top changes are predicted to be in natural gas with a 48% more increase, and coal with a 38% more decrease, while having a 17% increase in oil supply in 2015–35 period.

1.12.5.4

Case Study: Fossil Fuel Consumption and Supply in the Unites States

Table 33 below reports the fossil fuel consumption and supply in the United States for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that, in 2015, oil, natural gas, and coal had total primary energy consumption shares of 36%, 31%, and 17% (84% in total), respectively; and it is predicted that the

554

Fossil Fuels Fossil fuel consumption and supply in North Americaa (units in Mtoe unless otherwise noted)

Table 32

Levels

Shares

2015

2035

2015

2035

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

23 93 429

19 119 212

36 32 15

29 39 7

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

21 95 494

24 141 307

Change (absolute)

Change (%)

1995–2015

1995–2015

2015–35

Change (annual) (%)c 2015–35

1995–2015

2015–35

1 21 109

4 26 217

11 30 20

13 28 51

0.5 1.3 1.1

0.7 1.2 3.5

6 26 108

4 45 187

41 37 18

17 48 38

1.7 1.6 1.0

0.8 2.0 2.4

a

Compound annual growth rate. Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels.

b

c

United States (excluding US territories), Canada, and Mexico. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 33

Fossil fuel consumption and supply in the United States (units in Mtoe unless otherwise noted) Levels

Shares (%)

Change (absolute)

Change (%)

1995–2015

1995–2015

2015

2035

2015

2035

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

18 75 396

15 94 198

36 31 17

29 39 9

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

14 74 455

17 115 278

2015–35

Change (annual) (%)a 2015–35

1995–2015

2015–35

1 14 110

3 19 198

4 24 22

17 25 50

0.2 1.1 1.2

1.0 1.1 3.4

5 23 100

4 41 178

50 46 18

26 55 39

2.0 1.9 1.0

1.2 2.2 2.4

a

Compound annual growth rate. Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

b

shares, by 2035, will be 29%, 39%, and 9% (77% in total), respectively, natural gas increasing its share, while oil and particularly coal reducing their shares, and that an 7% decrease in fossil fuels share in consumption will be observed in the United States primary energy consumption. The highest changes in fossil fuel consumption occurred in natural gas with an increase of 24%, coal with a 22% drop, and having a 4% increase in oil consumption in 1995–2015 period; and the top changes are predicted to be in coal with a further drop of 50%, natural gas with a 25% more increase, and having further 17% drop in oil consumption in 2015–35 period. The highest change in fossil fuel supply occurred in oil and natural gas with 50% and 46% increases, respectively, while having an 18% decrease in coal supply in 1995–2015 period; and the top changes are predicted to be in natural gas with a 55% more increase, and coal with a 39% more decrease, while having a 26% increase in oil supply in 2015–35 period.

1.12.5.5

Case Study: Fossil Fuel Consumption and Supply in Brazil

Table 34 shows the fossil fuel consumption and supply in Brazil for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 41%, 13%, and 6% (60% in total), respectively; and it is predicted that the shares, by 2035, will be 34%, 13%, and 4% (51% in total), respectively, natural gas maintaining its share, while particularly oil and coal reducing their shares, and that a 9% decrease in fossil fuels share in consumption is predicted in Brazil’s primary energy consumption. The highest changes in fossil fuel consumption occurred in natural gas with an increase of 705%, oil with a 61% increase, and having a 47% increase in coal consumption in 1995–2015 period; and the top changes are predicted to be in natural gas with a further increase of 43%, coal with a 16% decrease, and having further 15% rise in oil consumption in 2015–35 period. The highest change in fossil fuel supply occurred in natural gas and oil with 351% and 246% increases, respectively, while having a 45% increase in coal supply in 1995–2015 period; and the top changes are predicted to be in oil with a 69% more increase, and natural gas with a 40% more increase, while having a 22% drop in coal supply in 2015–35 period.

Fossil Fuels

Table 34

555

Fossil fuel consumption and supply in Brazil (units in Mtoe unless otherwise noted) Levels

Shares (%)

Change (absolute)

Change (%) 1995–2015

Change (annual) (%a)

2015

2035

2015

2035

1995–2015

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

2.6 4 17

3 6 15

41 13 6

34 13 4

1 3 6

0.4 2 3

61 705 47

15 43 16

2.4 410 1.9

0.7 1.8 0.9

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

2.6 2 3

1.8 2 1

1.8 1 1

246 351 45

69 40 22

6.4 7.8 1.9

2.6 1.7 1.2

4.4 3 3

2015–35

2015–35

1995–2015

2015–35

a

Compound annual growth rate. Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

b

Fossil fuel consumption and supply in the European Uniona (units in Mtoe unless otherwise noted)

Table 35

Levels

Shares (%)

Change (absolute)

Change (%)

1995–2015

1995–2015

2015

2035

2015

2035

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

12 39 262

9 45 117

36 22 16

30 28 8

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

2 12 145

1 6 56

2 3 101 2 9 136

2015–35

3 6 145 0.8 6 89

Change (annual) (%)a 2015–35

1995–2015

2015–35

13 8 28

24 15 55

0.7 0.4 1.6

1.4 0.7 3.9

52 44 48

41 52 61

3.6 2.8 3.3

2.6 3.6 4.6

a

Member Countries: Austria, Belgium, Bulgaria, Croatia, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands, Poland, Portugal, Romania, Slovakia, Slovenia, Spain, Sweden, United Kingdom.

b

Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

1.12.5.6

Case Study: Fossil Fuel Consumption and Supply in the European Union

Table 35 reports the fossil fuel consumption and supply in the European Union for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 36%, 22%, and 16% (74% in total), respectively; and it is predicted that the shares, by 2035, will be 30%, 28%, and 8% (66% in total), respectively, natural gas increasing its share, while oil and particularly coal reducing their shares, and that an 8% decrease in fossil fuels share in consumption will be observed in the European Union’s primary energy consumption. The highest changes in fossil fuel consumption occurred in coal with a drop of 28%, oil with a 13% decrease, and having an 8% increase in natural gas consumption in 1995–2015 period; and the top changes are predicted to take place in coal with a further drop of 55%, oil with a 24% decrease, and having further 15% rise in natural gas consumption in 2015–35 period. The highest change in fossil fuel supply occurred in oil and coal with 52% and 48% decreases, respectively, while having a 44% decrease in natural gas supply in 1995–2015 period; and the top changes are predicted to be in coal and natural gas with a 61% and 52% more drops, respectively, and oil with a 41% more decrease in 2015–35 period.

1.12.5.7

Case Study: Fossil Fuel Consumption and Supply in the Middle East

Table 36 below presents the fossil fuel consumption and supply in the Middle East (Arabian Peninsula, Iran, Iraq, Israel, Jordan, Lebanon, and Syria) for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 48%, 50%, and 1% (99% in total), respectively; and it is predicted that the shares, by 2035, will be 42%, 52%, and 1% (95% in total), respectively, natural gas increasing its share, while oil reducing its shares, and that a 4% decrease in fossil fuels share in consumption will be observed in the Middle East’s primary energy consumption. The highest changes in fossil fuel consumption

556

Fossil Fuels Fossil fuel consumption and supply in the Middle Easta (units in Mtoe unless otherwise noted)

Table 36

Levels

Shares (%)

Change (absolute)

Change (%)

Change (annual) (%)a

2015

2035

2015

2035

1995–2015

2015–35

1995–2015

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

9 47 11

13 73 12

48 50 1

42 52 1

5 34 5

3 26 1

109 248 99

34 55 12

3.8 6.4 3.5

1.5 2.2 0.6

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

30 60 1

39 85 1

10 45 0

9 25 0

50 315 0

29 43 18

2.1 7.4 0.0

1.3 1.8 1.0

2015–35

1995–2015

2015–35

a

Arabian Peninsula, Iran, Iraq, Israel, Jordan, Lebanon, and Syria.

b

Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 37

Fossil fuel consumption and supply in Russian Federation (units in Mtoe unless otherwise noted) Levels 2015

2035

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

3.1 38 89

3.6 37 69

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

11.0 55 184

12.2 71 191

Change (annual) (%)a

Shares (%)

Change (absolute)

Change (%)

2015

2035

1995–2015

2015–35

1995–2015

21 53 13

24 51 10

0.1 2 31

0.5 1 19

2 7 26

15 2 22

0.1 0.3 1.5

0.7 0.1 1.2

4.8 4 60

1.2 16 6

77 8 48

11 28 3

2.9 0.4 2.0

0.5 1.2 0.2

2015–35

1995–2015

2015–35

a

Compound annual growth rate.

b

Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

occurred in natural gas and oil consumptions with increases of 248% and 109%, respectively, and having coal with a 99% increase in 1995–2015 period; and the top changes are predicted to take place in natural gas with a further increase of 55%, oil with a 34% increase, and having a 12% rise in coal consumption in 2015–35 period. The highest change in fossil fuel supply occurred in natural gas and oil with 315% and 50% increases, respectively, while having no changes in coal supply in 1995–2015 period; and the top changes are predicted to continue in natural gas and oil with further increases of 43% and 29%, respectively, having coal supply with an 18% drop in 2015–35 period.

1.12.5.8

Case Study: Fossil Fuel Consumption and Supply in Russian Federation

Table 37 shows the fossil fuel consumption and supply in Russian Federation for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 21%, 53%, and 13% (87% in total), respectively; and it is predicted that the shares, by 2035, will be 24%, 51%, and 10% (85% in total), respectively, oil increasing its share, while natural gas and coal reducing their shares, and that only a 2% decrease in fossil fuels share in consumption will be observed in Russia’s primary energy consumption. The highest changes in fossil fuel consumption occurred in coal consumption with a drop of 26%, and having natural gas and oil with a 7% and 2% increases in 1995–2015 period; and the top changes are predicted to occur in coal with a further drop of 22%, oil with a 15% increase, and having a 2% drop in natural gas consumption in 2015–35 period. The highest change in fossil fuel supply occurred in oil and coal with 77% and 48% increases, respectively, while having an 8% rise in natural gas supply in 1995–2015 period; and the top changes are predicted to be in natural gas and oil with further increases of 28% and 11%, respectively, having coal supply with a slight increase of 3% in 2015–35 period. Table 38 presents the fossil fuel consumption and supply in China for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 18%, 6%, and 64% (88% in total), respectively; and it is predicted that the shares, by 2035,

Fossil Fuels

Table 38

557

Fossil fuel consumption and supply in China (units in Mtoe unless otherwise noted) Levels

Change (annual) (%)a

Shares (%)

Change (absolute)

Change (%) 1995–2015

2015–35

1995–2015

2015

2035

2015

2035

1995–2015

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

12 19 1920

19 55 1876

18 6 64

20 11 42

9 17 1259

7 36 45

256 977 190

61 186 2

6.6 410 5.5

2.4 5.4 0.1

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

5 13 1827

5 33 1842

2 12 1147

0 20 15

60 644 169

0 146 1

2.4 410 5.1

0.0 4.6 0.0

2015–35

2015–35

a

Compound annual growth rate.

b

Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

Table 39

Fossil fuel consumption and supply in India (units in Mtoe unless otherwise noted) Levels

Shares (%)

Change (absolute)

Change (%)

Change (annual) (%)a

2015

2035

2015

2035

1995–2015

2015–35

1995–2015

2015–35

1995–2015

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

4.1 4.9 407

9.2 12.8 833

28 7 58

27 7 52

2.6 3 267

5 8 426

163 169 190

121 162 105

4.9 5.1 5.5

4.0 4.9 3.6

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

1.0 3 284

0.9 7 580

0.3 1 151

0.1 4 296

33 56 113

9 154 104

1.4 2.2 3.9

0.5 4.8 3.6

2015–35

a

Compound annual growth rate.

b

Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

will be 20%, 11%, and 42% (73% in total), respectively, oil and natural gas increasing their shares, while coal reducing its share, and that 15% decrease in fossil fuels share in consumption will be observed in China’s primary energy consumption. The highest changes in fossil fuel consumption occurred in natural gas consumption with a huge rise of 977%, and having oil and coal with 256% and 190% increases in 1995–2015 period; and the top changes are predicted to happen in natural gas with a further rise of 186%, oil with a 61% increase, and having a 2% drop in coal consumption in 2015–35 period. The highest change in fossil fuel supply occurred in natural gas and coal with 644% and 169% increases, respectively, while having a 60% rise in oil supply in 1995–2015 period; and the top change is predicted to be in natural gas with a further increase of 146%, having no oil and negligible coal supplies in 2015–35 period.

1.12.5.9

Case Study: Fossil Fuel Consumption and Supply in India

Table 39 reports the fossil fuel consumption and supply in India for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 28%, 7%, and 52% (91% in total), respectively; and it is predicted that the shares, by 2035, will be 27%, 7%, and 42% (86% in total), respectively, oil and natural gas maintaining their shares, while coal reducing its share, and that 5% decrease in fossil fuels share in consumption will be observed in India’s primary energy consumption. The highest change in fossil fuel consumption occurred in coal consumption with a rise of 190%, and having natural gas and oil with 169% and 163% increases in 1995–2015 period; and the top changes are predicted to occur in natural gas with a further rise of 162%, oil with a 121% increase, and having a 105% rise in coal consumption in 2015–35 period. The highest change in fossil fuel supply occurred in coal with 113% increase, while having 56% and 33% rises in natural gas and oil supplies in 1995–2015 period; and the top change is predicted to be in natural gas with a further increase of 154%, having coal with a 104% rise and oil with a drop of 9% in 2015–35 period.

558

Fossil Fuels Fossil fuel consumption and supply in Other Emerging Asiaa (units in Mtoe unless otherwise noted)

Table 40

Levels

Shares (%)

Change (absolute)

Change (%) 1995–2015

Change (annual) (%)a

2015

2035

2015

2035

1995–2015

Consumption Oilb (Mb/d) Gas (Bcf/d) Coal

8 25 219

11 32 467

43 26 24

35 20 32

4 17 155

3 7 248

82 206 243

33 27 113

3.0 5.8 6.4

1.4 1.2 3.9

Supply Oilb (Mb/d) Gas (Bcf/d) Coal

2.8 30 313

1.9 19 459

0.1 17 255

1 11 146

4 131 439

34 37 46

0.2 4.3 8.8

2.1 2.2 1.9

2015–35

2015–35

1995–2015

2015–35

a

Non-OECD Asia excluding China and India.

b

Oil supply includes crude oil, shale oil, oil sands, natural gas liquids, liquid fuels derived from coal and gas, and refinery gains, but excludes biofuels. Oil demand includes consumption of all liquid hydrocarbons, but excludes biofuels. Source: Data from BP. Available from: http://bp.com/statisticalreview [accessed 21.10.17].

1.12.5.10

Case Study: Fossil Fuel Consumption and Supply in Other Emerging Asia

Other emerging Asian countries include the non-OECD Asia excluding China and India. And Table 40 presents the fossil fuel consumption and supply in other emerging Asian countries for 2015, and the predicted numbers for 2035, as well as the relevant changes for the periods of 1995–2015 and 2015–35. It is observed that in 2015, oil, natural gas, and coal had total primary energy consumption shares of 43%, 26%, and 24% (93% in total), respectively; and it is predicted that the shares, by 2035, will be 35%, 20%, and 32% (87% in total), respectively, oil and natural gas decreasing their shares, while coal increasing its share to 32% taking the second place after oil, and that 7% decrease in fossil fuels share in consumption will be observed in the region’s primary energy consumption. The highest changes in fossil fuel consumption occurred in coal and natural gas consumption with rises of 243% and 206%, respectively, and having oil with an 82% increase in 1995–2015 period; and the top changes are predicted to happen in coal with a further rise of 113%, oil with a 33% increase, and natural gas with a 27% rise in 2015–35 period. The highest change in fossil fuel supply occurred in coal with 439%, while having a 131% rise in natural gas supply and a 4% drop in oil supply in 1995–2015 period; and the top change is predicted to be in coal with a further increase of 46%, having 37% and 34% drops in natural gas and oil supplies, respectively, in 2015–35 period.

1.12.6

•

Fossil fuels have always had the major share in the global primary energy consumption. The fossil fuel consumption increased 50.7% in the period of 1995–2015, and it is predicted that the consumption will increase 17.9% more in the period of 2015–35. It was observed that, in 1995, oil, natural gas, and coal had total primary energy consumption shares of 38%, 22%, and 26% (87% in total), respectively; that, in 2015, they had total primary energy consumption shares of 32%, 24%, and 29% (85% in total), respectively; and it is predicted that, by 2035, the shares will be 29%, 25%, and 24% (78% in total), respectively, natural gas having the second place after oil, and that a 7% decrease in fossil fuels share in consumption will be observed in the global primary energy consumption [62]. Even though the share of fossil fuels decreased and is predicted to decrease further through 2035, as mentioned above, the overall consumption of fossil fuels has grown and is expected to expand further through 2035. The highest changes in fossil fuel consumption are predicted to be in natural gas with 38% increase, oil with 15% more increase, and having 5% more increase in coal consumption in the period of 2015–35. Further future prospects of fossil fuels are provided below.

1.12.6.1

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Future Prospects

Oil

With the help of advanced technologies, more oil reserves have been discovered and became viable; as a result, the global oil reserves increased by 60% within 20 years with a 25% growth in oil production [7], now having the South and Central America the highest (120 years) oil R/P ratios rather than the Middle East. It is presently expected to expand further as unconventional oil sources are taken into account. Both oil sands and oil shale not only represent an increased oil reserve, but also an increased environmental burden. According to BP Energy Outlook 2017 [62], oil, coal, and natural gas provided 85.4% of primary energy production in 2015 (32.4% þ 29.2% þ 23.9%, respectively). Currently, oil is the world's largest primary source of energy. Global oil production in 2015 increased by 32.7% (with an annual increase of 1.6%) compared to that in 1995, and is projected to increase further (9.3% with an annual increase of 0.4%) in the period of 2015–35. The main increase has been and will be in the Middle East and North America, while a further decline in oil production is predicted in Europe, having almost a steady production in Africa and Asia Pacific. It is forecasted that the Middle East, North America and the CIS will continue to maintain their leading

Fossil Fuels

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shares of global oil production with further production increases through 2035, while the South and Central America sustaining its share with increased production and other regions observing a decline in oil production shares. Except in the CIS, oil consumption continued to increase everywhere else between the years 1995 and 2015 with a 31.4% global increase, and is predicted to increase further (15.9%) in the period of 2015–35. The main increase in oil consumption has been and will be in Asia Pacific and the Middle East. Oil consumption in Europe, along with the other forms of fossil fuels either sustained or decreased their levels until 2010; however, it started to decrease thereafter, and is forecasted to maintain the decreasing trend until 2035. The decrease in fossil fuel consumption in Europe has been compensated by the renewable energy sources, which are expected to have more shares in the mix with an exponential growth through 2035, benefiting from energy efficiency transition as well. Regionally, Asia Pacific and North America will continue to preserve their leading shares of global oil consumption with the United States having some drop in consumption (23.9% in 2015 to 17.8% in 2035) and Asia Pacific having a further consumption increase (42.6%) by 2035. The Middle East as well is expected to increase its consumption further through 2035 reaching a total share of 11% of the global consumption with a 29.2% change in between 2015 and 2035. As mentioned above, Europe’s share in global oil consumption is expected to drop further (17.9%) in 2015–35 period reaching the same level as that of the Middle East. It is forecasted that the CIS oil consumption will have a 20.1% increase in the period of 2015–35. Overall, an annual increase is expected to take place around 0.8% with a 15.9% total change in the period of 2015–35. The United States has consistently been the top consumer of oil followed by China and India (replaced Japan in 2016), with their shares of 2016 as 19.5%, 13.1%, and 4.8%, respectively. Japan, on the other hand, has experienced a major decrease (2.6%) in annual growth of oil consumption in the past 10 years, with an annual drop of 2.8% in 2016 alone. However, in many other Asian countries, the oil consumption is still rising at high speeds to give access to urbanization and industrialization. The reason that oil has remained the leading energy supplier is that the consumption growth in developing economies exceeds the declined demands in the OECD countries [6,63]. Transportation and industrial use of oil had their leading shares of total global oil consumption (47.3% and 18% in 1995, respectively; and 55.2% and 15.7% in 2015, respectively). In the period of 2015–35, transportation is forecasted to maintain its leading position with a projected share of 56.4%; however, it is expected to be followed by non-combusted use of oil with a share of 17.6% instead of industrial use with 14.5% share by 2035. Due to the environmental concerns growing more every passing year; less high-sulfur oil is used in power generators [21]. Except for the consumption in power and building sectors, the oil consumption in other sectors has increased since the 1990s and this trend is expected to continue through 2035. The share of transportation sector in oil consumption, however, is not projected to change much, and will maintain its share in the period of 2015–35. Although renewable energy sources have been exploited for the past few decades, the alternative products are not expected to grow with rapid rates in the short-term. These substitutions still need to experience a long-term evolution period to overcome the technology problems and market acceptance challenges. Consequently, the global oil demands are likely to remain at a higher level over the next decades [6,9,12]. The WEC also confirmed that the majority of the oil market switched to developing and emerging economic areas [7].

1.12.6.2

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559

Natural Gas

Major proven resources (in km³) at the end of 2016 are world 186,600, Iran 33,500 (18.0% of total world), Russian Federation 32,300 (17.3%), Qatar 24,300 (13.0%), Turkmenistan 17,500 (9.4%), and the United States 8,700 (4.7%). According to the report prepared by BP [62], with the development of exploitation technology, the natural gas reserves have intensively increased by 51.1% over the period of 1995–2015, and are presently expected to expand further as unconventional natural gas sources are taking part in the overall picture. It is estimated that there are about 900,000 km³ of unconventional natural gas, such as shale gas, of which 180,000 km³ may be recoverable [121]. After the success in the United States, shale gas exploration has begun in other countries, such as China, Poland, and South Africa [123–125]. Based on the report released by BP in 2017 [62], following oil (32%) and coal (29%), natural gas was the world’s third largest (24%) source of primary energy in 2015. However, the share of natural gas, with a projected change of approx. 38% in the period of 2015–35, is expected to make natural gas the world’s second largest source of primary energy by 2035. The United States, Russian Federation, Iran, Qatar, and Canada have consistently been the top producers of natural gas, and will continue to preserve their leading shares of global natural gas production, having Asia Pacific with further production increases through 2035, while Europe decreasing its share with major reductions in natural gas production. Overall, there has been an annual increase (3.3%) with 67.9% total increase in global natural gas production between the years 1995 and 2015, and the annual increase is expected to occur around 1.7% with 35.1% total change in the period of 2015–35. The International Energy Outlook in 2016 reported that global natural gas consumption is projected to increase from 3.4 to 5.8 trillion m3 during 2012 to 2040 [11]. Table 16 as well shows that the global consumption is projected to increase further in the period of 2015–35 with approx. 38% increase. The main increase in absolute natural gas consumption has been and will continue to be in Asia Pacific, the Middle East, and North America. Europe had the third largest share in global natural consumption in 1995; however, the share dropped in 2015 moving it to the fifth place; and it is expected to drop further in 2015–35 period reaching 11.4%. It is also expected that North America (with a total share of 26.0%) and Pacific Asia (with 25.9%) will maintain their leading consumptions, while the Middle East (with 15.8%) taking the third place and replacing the

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CIS (with 11.5%) by 2035. Overall, an annual increase in global natural gas consumption (3.0%) with a 63.0% total increase in consumption was observed in the period of 1995–2015, and the annual increase is expected to take place around 1.8% with a 37.7% total change in 2015–35 period. The United States has consistently been the top consumer of natural gas followed by Russian Federation, and China, with their shares of 2016 as 22.0%, 11.0%, and 5.9%, respectively. It should be noted that the United States is burning almost quarter of the global natural gas production (more than what it produces) and the trend is expected to continue due to its high energy demand. Global energy consumption from natural gas occupied approx. 23.9% of total primary energy consumption, and approx. 37.9% and 34.2% of which were utilized for power generation and industrial use in 2015, respectively. Natural gas consumption in all sectors has dramatically increased for the period of 1995–2015, having the highest percent changes in transportation and power sectors, and this trend is expected to continue through 2035. The increase in natural gas consumption in all sectors is expected to increase further through 2035 as it is considered a clean burning fossil fuel. Among European countries, the largest natural gas consumers are Germany, the United Kingdom and Italy. The production in all these three countries has been falling and is expected to fall further. The difference between the consumption and production in all three are imported and the gap is expected to grow further in time. Natural gas productions in Iran and Qatar have been rising, and they produced 115.5 and 50.7 billion m3, respectively, in 2006; and 202.4 and 181.2 billion m3, respectively, in 2016 [62]. Russian Federation’s natural gas production peaked in 2011, and is in decline since then. Russia produced 607 billion m3 in 2011 and 579.4 billion m3 in 2016 [62]. The EIA in 2009 projected US marketed gas production will have reached a first peak at 583.3 billion m3 in 2008, decline to 535.2 billion m3 in 2013, and then rise again to 658.9 billion m3 in 2035, the final year of its projection, for an average annual rate of increase of 0.47% per year during 2009–35 [141]. The EIA, in its Annual Energy Outlook 2010, forecasted growth from 583.3 billion m3 in 2008 to 659.8 billion m3 in 2035. This represents average annual production growth rate of 0.46% [142]. Bentley ([143], p. 189) predicted a decline in global conventional gas production from about 2020 [143]. The EIA predicts that world gas production will continue to rise through 2030, with a total increase of almost 50%, and an average annual rate of increase of 1.6% per year, for the period of 2006–30 [144]. The Energy Watch Group predicted that global natural gas production would peak around or even before the year 2020 [145]. BP Statistical Review of World Energy 2017 [62], on the other hand, projects that a 35% increase in global natural gas production will occur for 2015–35 period.

1.12.6.3

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Fossil Fuels

Coal

BP, in its 2017 report, estimated at the end of 2016 that there was 153 years R/P ratio based on proved coal reserves worldwide. Other researchers predicted that the deposits can last more than 250 years, which is considerably longer than those of oil and natural gas reserves [157]. This figure only includes reserves classified as proved; explorations by mining companies, specifically in under-explored areas, are providing new reserves of coal every passing year. Following oil, coal with a share of 29% is currently the world’s second largest source of primary energy. The main changes have been and will be in Asia Pacific, the South and Central America, and Africa, while there is a major decline in coal production in Europe and North America. Asia Pacific, North America, and the CIS are expected to continue to preserve their leading shares of global coal production having Asia Pacific and the CIS with further production increases by 2035, while North America decreasing its share with further reductions in coal production. The major decline took place in Europe and North America, and it will continue to drop further by 2035. China alone, in 2016, produced 1685.7 million tonnes of oil equivalent coal, which is 44.1% of 3654.4 million tonnes of oil equivalent world coal production. Other major producers in the same year were the United States with 364.8 million tonnes of oil equivalent production (10.0% of the world’s total), Australia with 220.4 million tonnes of oil equivalent production (8.2%), India with 198.2 million tonnes of oil equivalent production (7.9%), and Indonesia with a production of 114.2 million tonnes of oil equivalent (7.0%). Overall, there has been an annual increase (3.3%) with 69.3% total increase in global coal production between the years 1995 and 2015, and the annual increase is predicted to occur around 0.4% with 8.4% total change in the period of 2015–35. It is also predicted that the use of coal will rise over 50% in 2030, with 97% contributed by developing countries. By contrast, the use of coal in Western Europe has declined by 36% since 1990, and they switched to using natural gas in daily life. Europe had the third largest share (13.5%) in global coal consumption in 1995; however, the share dropped to 4.4% in 2015 moving it to the fourth place; and it is expected to drop further in the period of 2015–35 reaching 1.6% only. Except in Europe and the United States, coal consumption continued to increase everywhere else in the period of 1995–2015 with a 69.3% global increase, and is projected to increase 8.4% more in 2015–35 period. As in the past 20 years, Asia Pacific, North America, and the CIS will continue to preserve their leading shares of global coal consumption with North America having major drops in consumption (26.6% in 1995 to 12.9% in 2015, and to 7.4% in 2035), and Asia Pacific however having a further consumption increase (total share of 77.5%) by 2035. China is burning almost half of the global coal production (more than what it produces) and the trend is expected to continue due to the dramatic growth in energy demand. In many other Asian countries, the coal consumption is still increasing at high speeds to give access to urbanization and industrialization. The majority of the coal market will continue to dominate in developing and emerging economic areas particularly in Asia. The CIS has however maintained its share and is expected to continue to do so through 2035. Overall, there has been an annual increase (3.3%) with

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69.3% total change in global coal consumption between the years 1995 and 2015, and the annual increase is expected to take place around 0.4% with 8.4% total change in the period of 2015–35. Global consumption of coal occupied approx. 29% of total primary energy consumption, and approx. 58.6% and 35.8% of which were utilized for power generation and industrial use in 2015, respectively. Except for the consumption in transportation and building sectors, the coal consumption in all other sectors has dramatically increased for the past 20 years, and this trend is expected to continue through 2035. Due to the environmental concerns growing more every passing year, the increase in coal consumption in power generation and industrial use will slow down with further drops projected in buildings sectors by 2035. The alternative products are not expected to grow with rapid rates to fill the needs of power and industry sectors in the shortterm. The estimates for global peak coal extraction vary tremendously. A 2007 study predicted that global peak coal extraction may happen around 2025 at 30% above the 2005 rate [168,169]. However, BP projects that coal production would go beyond this level even beyond 2035 [62]. Moreover, a 2009 research performed in Australia concluded that global coal extraction could peak sometime between the present and 2048 [170]. Except the United States, four of the largest coal-extracting countries had experienced significant increases in coal extraction over the period of 1995–2015. The Energy Watch Group in their 2007 report predicted that the Chinese extraction would peak around 2015, and then later in their March 2013 report revised 2015–20 [168,171]. Another study [172] placed the peak at 2027, and the EIA forecasts that China coal extraction will continue to rise until 2030 [173]. Hubbert's analysis in 1956 originally projected that total coal extraction in the United States could peak in about 2150 [174], later records show that extraction already reached an energy content peak in 1998 and a tonnage peak in 2008 [175]. As well, according to the Energy Watch Group, Canadian coal extraction peaked in 1997 [168]. A 2009 research conducted in Australia concluded that Australian coal extraction could peak sometime after 2050 [170], while the Australian Coal Association estimates that Australia's identified black coal resources (which does not account for brown coal stocks) could last more than 200 years based on rate of extraction in 2007 [176]. Furthermore, BP reported a 69% increase in global coal supply for the period of 1995–2015, and projects an 8% more increase in global coal supply for the period of 2015–35 [62].

1.12.7

Concluding Remarks

Fossil fuels have always had the major share in the global primary energy consumption. The fossil fuel consumption increased 50.7% in the period of 1995–2015, and it is predicted that the consumption will increase 17.9% more in the period of 2015–35. It was observed that, in 1995, oil, natural gas, and coal had total primary energy consumption shares of 38%, 22%, and 26% (87% in total), respectively; that, in 2015, they had total primary energy consumption shares of 32%, 24%, and 29% (85% in total), respectively; and it is predicted that, by 2035, the shares will be 29%, 25%, and 24% (78% in total), respectively, natural gas having the second place after oil, and that a 7% decrease in fossil fuels share in consumption will be observed in the global primary energy consumption. Even though the share of fossil fuels has decreased and is predicted to decrease further through 2035, the overall consumption of fossil fuels has grown and is expected to expand further through 2035. The highest changes in fossil fuel consumption are predicted to be in natural gas with a 38% increase, oil with a 15% more increase, and having 5% more increase in coal consumption in 2015–35 period. From this review chapter, the following concluding remarks are made:

1.12.7.1

Oil

1. With the help of advanced technologies, more oil reserves have been discovered and became viable; as a result, the global oil reserves increased by 60% within the past 20 years. It is expected to expand further as unconventional oil sources are taken into account. Both oil sands and oil shale not only represent an increased oil reserve, but also an increased environmental burden. 2. Oil is the world's largest primary source of energy. Global oil production in 2015 increased compared to that in 1995, and is projected to increase further in the period of 2015–35. 3. The main increase in oil production has been and will be in the Middle East and North America, while a further decline in production is predicted in Europe, having almost a steady production in Africa and Asia Pacific. It is forecasted that the Middle East, North America, and the CIS will continue to maintain their leading shares of global oil production with further production increases by 2035, while the South and Central America sustaining its share with increased production and other regions observing a decline in oil production shares. 4. Oil consumption, except in the CIS, continued to increase everywhere else between the years 1995 and 2015, and is predicted to increase further in the period of 2015–35. 5. The United States has consistently been the top consumer of oil followed by China and India (replaced Japan in 2016). India is highly dependent on imported crude oil, which comes from overseas oil fields, such as the Middle East and South America. Asia Pacific and North America will continue to preserve their leading shares of global oil consumption with the United States having some drop in consumption and Asia Pacific having a further consumption increase by 2035. The Middle East as well is expected to increase its consumption further by 2035. It is forecasted that the CIS oil consumption as well will increase in the period of 2015–35. Europe’s share in global oil consumption is expected to drop further in 2015–35 period reaching the same level as that of the Middle East. Japan has experienced a major decrease in annual growth of oil consumption in the past 10

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years, with the highest annual drop in 2016 in recent years. However, in many other Asian countries, the oil consumption is still rising at high speeds to give access to urbanization and industrialization. The reason that oil has remained the leading energy supplier is that the consumption growth in developing economies exceeds the declined demands in the OECD countries. 6. Transportation and industrial use of oil had their leading shares of total global oil consumption in the period of 1995–2015. In the period of 2015–35, transportation is forecasted to maintain its leading position; however, it is expected to be followed by non-combusted use of oil instead of industrial use by 2035. 7. Due to the environmental concerns, less high-sulfur oil is used in power generators. Except for the consumption in power and building sectors, the oil consumption in other sectors has increased since the 1990s and this trend is expected to continue through 2035. The share of transportation in oil consumption, however, is not projected to change much, and will maintain its share in the period of 2015–35. Although renewable energy sources have been exploited for the past few decades, the alternative products are not expected to grow with rapid rates in the short-term. Consequently, the global oil demands are likely to remain at a higher level over the next decades. The majority of the oil market seems to have switched to developing and emerging economic areas. 8. At the end of 2016, the highest proved oil reserves (including nonconventional oil deposits) are reported to be in Venezuela, Saudi Arabia, Canada, Iran, and Iraq, with the highest R/P ratios belonging to Venezuela and Canada.

1.12.7.2

Natural Gas

1. Following oil and coal, natural gas is now the world’s third largest source of primary energy. However, the share of natural gas, with the projected change, is expected to rise, making natural gas the world’s second largest source of primary energy by 2035. 2. The United States, Russian Federation, Iran, Qatar, and Canada have consistently been the top producers of natural gas, and will continue to preserve their leading shares of global natural gas production, having Asia Pacific with further production increases by 2035, while Europe decreasing its share with major reductions in natural gas production. Overall, there has been an annual increase in global natural gas production between the years 1995 and 2015, and the annual increase is expected to have positive figures, however, drop in the period of 2015–35. 3. The global consumption increased in the period of 1995–2015, and is projected to have further increase in the period of 2015–35. The main increase in absolute natural gas consumption has been and will continue to be in Asia Pacific, the Middle East, and North America. Europe had the third largest share in global natural consumption in 1995; however, the share dropped in 2015 moving it to the fifth place; and it is expected to drop further in 2015–35 period. It is also predicted that North America and Pacific Asia will maintain their leading consumptions, while the Middle East taking the third place and replacing the CIS by 2035. 4. The United States has consistently been the top consumer of natural gas followed by Russian Federation, and China. It should be noted that the United States is burning almost quarter of the global natural gas production (more than what it produces) and the trend is expected to continue due to its high energy demand. 5. Global energy consumption from natural gas occupied approx. quarter of the total primary energy consumption, of which were mainly utilized for power generation and industrial use in 2015. Natural gas consumption in all sectors dramatically increased in the period of 1995–2015, having the highest percent changes in transportation and power sectors, and this trend is expected to continue through 2035. The increase in natural gas consumption in all sectors is expected to increase further through 2035 as it is considered a clean burning fossil fuel. 6. Among European countries, the largest natural gas consumers are Germany, the United Kingdom, and Italy. The productions in all these three countries have been falling and are expected to decline further. The difference between the consumption and production in all three are imported and the gap is expected to grow further in time. Natural gas productions in Iran and Qatar have been rising, and are predicted to rise further. Russian Federation’s natural gas production peaked in 2011, and is in decline since then. 7. It was projected that US marketed gas production will have reached a first peak in 2008, decline in 2013, and then rise again through 2035. It was further forecasted that a growth will occur from 2008 to 2035. 8. A decline in global conventional gas production was predicted at or even before 2020. However, further predictions report that world gas production will continue to rise through 2035. 9. The gas reserves are broadly however unevenly distributed around the world. And there is no agreement on which country has the largest proved natural gas reserves. However, major proven resources at the end of 2016 are reported to be in Iran, Russian Federation, Qatar, Turkmenistan, and the United States.

1.12.7.3

Coal

1. Following oil, coal is currently the world’s second largest source of primary energy. The main changes have been and will be in Asia Pacific, the South and Central America, and Africa, while there is a major decline in coal production in Europe and North America. Asia Pacific, North America, and the CIS are expected to preserve their leading shares of global coal production, having Asia Pacific and the CIS with further production increases by 2035, while North America decreasing its share with further reductions in coal production. The major decline took place in Europe and North America and is forecasted to drop further by 2035. China is the largest producer of coal. Other major producers are the United States, Australia, India, and Indonesia.

Fossil Fuels

2.

3. 4.

5.

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Overall, there was an annual and total increase in global coal production in the period of 1995–2015, and lower but positive figures for annual and total increases are predicted to occur in the period of 2015–35. It is also predicted that the use of coal will rise through 2030, with almost all contributions coming from developing countries. By contrast, the use of coal in Western Europe has declined, switching to using natural gas in daily life. Europe had the third largest share in global coal consumption in 1995; however, the share dropped considerably in 2015 moving it to the fourth place; and it is predicted to drop further in the period of 2015–35. Except in Europe and the United States, coal consumption continued to increase everywhere else in the period of 1995–2015, and is projected to increase more in 2015–35 period. As in the past 20 years, Asia Pacific, North America, and the CIS are expected to preserve their leading shares of global coal consumption with North America having major drops in consumption, and Asia Pacific however having a further consumption increase through 2035. China is burning almost half of the global coal production (more than what it produces) and the trend is expected to continue due to the dramatic growth in energy demand. In many other Asian countries, the coal consumption is still increasing at high speeds to give access to urbanization and industrialization. The majority of the coal market will continue to dominate in developing and emerging economic areas particularly in Asia. The CIS has however maintained its share and is expected to continue to do so through 2035. Overall, increases in annual and total changes were observed in global coal consumption in the period of 1995–2015, and lower but positive figures in the annual and total changes are expected to occur in the period of 2015–35. Almost 95% of the global coal consumption was utilized for power generation and industrial use, with individual shares of 59% and 36%, respectively, in 2015. Except for the consumption in transportation and building sectors, the coal consumption in all other sectors has dramatically increased for the past 20 years, and this trend is expected to continue through 2035. Due to the environmental concerns growing more every passing year, the increase in coal consumption in power generation and industrial use is predicted to slow down with further drops projected in buildings sectors by 2035. The estimates for global peak coal extraction vary tremendously. It was predicted that global peak coal extraction may happen around 2025; however, other estimates reported that peak coal would go beyond 2035 and even 2048. It was predicted that the Chinese extraction would peak around 2015, 2020, or at 2027; however, it is also forecasted that Chinese coal extraction will continue to rise through 2030. Hubbert's analysis in 1956 originally projected that total coal extraction in the United States could peak in about 2150; later records showed that extraction already reached an energy content peak in 1998 and a tonnage peak in 2008. Canadian coal extraction is considered already peaked in 1997. Furthermore, it was estimated that Australian coal extraction could peak sometime after 2050, however, further estimates reported that Australia's identified black coal resources (which does not account for brown coal stocks) could last more than 200 years based on rate of extraction in 2007.

As mentioned above, fossil fuels have always had the major share in the global primary energy consumption, and even though the share has decreased and is predicted to decrease further, they will continue to hold the major share in the primary energy mix in the foreseeable future as more unconventional fossil fuels are explored. The highest change in fossil fuel consumption has happened in natural gas and is predicted that it will continue because natural gas is a cleaner fossil fuel compared to oil and coal; however, extraction of and burning all fossil fuel forms have serious environmental consequences, which will require further and closer attention as more unconventional fossil fuel resources are explored and their overall consumption expand further.

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Further Reading Abbott M. The economics of the gas supply industry. Abingdon: Routledge; 2016. International Energy Agency. Oil market report 2016. Paris: OECD; 2016. King Hubbert M. Energy resources, national academy of sciences. Publication 1000-D; 1962. Olsson G. Water and energy: threats and opportunities. London; IWA Publishing; 2012. REN21 Renewable Energy Policy Network for the 21st Century. Renewables 2016 Global Status Report, Paris; 2016. United States Energy Information Administration. International energy outlook 2016, U.S. Department of Energy; Washington, DC; 2016. World Energy Council. Survey of world energy resources. London; 2016.

Relevant Websites http://www.energy.gov.ab.ca Alberta Department of Energy. http://www.aapg.org American Association of Petroleum Geologists. https://www.bp.com British Petroleum. http://www.eesi.org Environmental and Energy Study Institute. http://www.greenpeace.org Greenpeace International. http://www.naturalgas.org NaturalGas.org. http://www.opec.org Organization of the Petroleum Exporting Countries. https://www.cia.gov U.S. Central Intelligence Agency. http://www.eia.gov U.S. Energy Information Administration. http://oaspub.epa.gov U.S. Environmental Protection Agency. http://energy.er.usgs.gov U.S. Geological Survey. http://web.worldbank.org World Bank. https://www.worldcoal.org World Coal Institute.

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1.13 Hydrogen Energy Canan Acar, Bahcesehir University, Istanbul, Turkey Ibrahim Dincer, University of Ontario Institute of Technology, Oshawa, ON, Canada r 2018 Elsevier Inc. All rights reserved.

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1.13.1 Introduction 1.13.2 Why Hydrogen? 1.13.3 Basic Facts of Hydrogen 1.13.4 Applications Diversity of Hydrogen 1.13.5 The Role of Hydrogen as a Potential Fuel 1.13.6 Hydrogen Energy Systems 1.13.7 Hydrogen Energy Storage and Safety 1.13.8 Hydrogen Energy Market 1.13.9 Future Directions 1.13.10 Concluding Remarks References Futher Reading Relevant Websites

Nomenclature

R z

Universal gas constant (mL atm/g K) Compressibility factor

Subscript and Superscripts f Formation

p v

Constant pressure Constant volume

Abbreviations AC Alternating current AIChE American Institute of Chemical Engineers APU Auxiliary power unit BEV Battery electric vehicle CCHP Combined cooling, heating, and power CCS Carbon capture and sequestration CERL Clean energy research laboratory CHP Combined heat and power DC Direct current DoE United States of America’s Department of Energy EIF Environmental impact factor EL Electrolyzer EV Electric vehicle FCEV Fuel cell electric vehicle GF Greenization factor GHG Greenhouse gas HCF Hydrogen content factor HENG Hydrogen-enriched natural gas HFCEV Hydrogen fuel cell electric vehicles HHV Higher heating value

HICEV ICE IEA IGU IT LDV LHV LPG MC NBP NTP PEM PEMFC PNGV PtP PV SO SUV UKHFCA

Hydrogen internal combustion engine vehicles Internal combustion engine International Energy Agency International gas union Information technology Light duty vehicle Lower heating value Liquefied petroleum gas Molten carbonate Normal boiling point Normal temperature and pressure Proton exchange membrane Proton exchange membrane fuel cell Partnership for a new generation of vehicles Power-to-power Photovoltaic Solid oxide Sport utility vehicle United Kingdom Hydrogen and Fuel Cell Industry University of Ontario Institute of Technology Ultraviolet

C H

Specific heat (J/g K) Enthalpy (kJ)

Greek Symbols D Change

568

UOIT UV

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Introduction

Decreasing the dependency on fossil fuels and reducing potentially harmful emissions could be accomplished by using clean, vast, and sustainable energy sources. As a result of their low or zero end-use emissions and frequently reloaded sources, renewable energies (e.g., geothermal heat, sunlight, wind, waves, etc.) are respected as sustainable replacements to fossil fuels. However, their discontinuous and inconsistent characteristics cause the requirement for effective storing methods. Renewable energies can be stored in chemical (i.e., hydrogen) or electrical energy form. Electricity is generally exploited as an energy storing option and it is heavily used on a daily basis. Hydrogen has been receiving a growing amount of consideration as a result of its favorable characteristics as an energy transporter. To confirm sustainable advancement and tackle economic and environmental issues, both electricity and hydrogen ought to be produced from renewable energy resources [1]. Hydrogen is an essential energy carrier for the following reasons: (1) it possesses good energy exchange effectiveness; (2) it can be generated from water with zero emissions; (3) it is plentiful; (4) it can be stored in various arrangements (e.g., gaseous, liquid, or with metal hydrides); (5) it can be transferred across extended distances with minimal loss; (6) it can be transformed into additional energy forms by more methods than those of every other fuel; (7) it contains greater higher heating value (HHV) and lower heating value (LHV) than the majority of the traditional fossil fuels (Table 1); and (8) if it is generated from renewable energies and water, its production, storage, transportation, and final usage do not damage the environment. However, the majority of the hydrogen production methods are not well established, causing elevated production cost and/or low efficiencies [2]. Unlike hydrogen, electricity is not suitable to store energy for extended periods of time. As mentioned earlier, hydrogen is a chemical fuel and it can be stored and transported by using the existing infrastructures. Electricity, on the other hand, has a transient nature. Therefore, the existing chemical energy storage and transport infrastructures cannot be employed for electricity. An additional drawback of electricity is the transmission losses due to the electrical resistance of system constituents. Because of its clear advantages over electricity, hydrogen has turned out to be an alternative solution to energy supply, storage, and transport [2]. Hydrogen manufactured from indigenous fossil fuels, such as coal, oil, and natural gas (with postcombustion carbon capture and sequestration (CCS)), may well become a reliable, affordable, and clean alternative to electricity as an energy carrier. What is more, hydrogen-fed fuel cell vehicles are already in the establishment phase; some examples of these vehicles are at highly progressive phases and they may possibly become a superior alternative to electric vehicles (EVs) not only from the cost perspective but also from an end-user standpoint [3]. Besides, it is becoming clear that hydrogen as another possible energy storage medium to electricity could possibly allow us to utilize the extensive variety of primary energy resources in a much cleaner manner. This is a clear advantage over and above the fact that hydrogen gives the opportunity to both enable a shift to the transportation sector that relies on electricity and foster the chances for hydrogen utilization and consumer demand in the market [4]. Here, we proceed further to compare hydrogen with other conventional fuels in terms of environmental impact factor (EIF), greenization factor (GF), and hydrogen content factor (HCF) to emphasize the importance of hydrogen as a unique energy storage option, through the following equations: EIF ¼

kg CO2 product of combustion reaction kg fuel

ð1Þ

EIFmax EIF EIFmax

ð2Þ

GF ¼ HCF ¼

kg of H2 in the fuel kg fuel

ð3Þ

where EIFmax is the maximum value of EIF among the evaluated options. In this specific case with 3.6, coal is selected as the EIFmax. As can be seen in Fig. 1, with increasing HCF, the energy sources become greener (increasing GF) and the EIF decreases. This is a clear advantage of hydrogen in terms of reducing carbon-related emissions. In order to take full advantage of hydrogen, it needs to be generated from clean or renewable sources in reliable, affordable, and carbon-free ways, as mentioned earlier [5]. It is important to highlight the fact that one of the major tasks to address worldwide energy issues and problems is to provide energy in a manner that it is safe, clean, reliable, and affordable. This task is becoming more and more challenging as fossil fuel (coal, oil, and gas) supplies diminish and many more nations become ever more reliant on energy sources imported from other Table 1 Higher heating value (HHV) and lower heating value (LHV) of hydrogen and common fossil fuels at 251C and 1 atm Fuel

HHV (kJ/g)

LHV (kJ/g)

Hydrogen Methane Gasoline Diesel Methanol

141.9 55.5 47.5 44.8 20.0

119.9 50.0 44.5 42.5 18.1

Source: Reproduced from Dincer I. Green methods for hydrogen production. Int J Hydrogen Energy 2012;37(2):1954–71.

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1

4.0 3.5

0.8

3.0 2.5

0.6

GF

0.4

EIF

2.0

EIF

HCF or GF

HCF

1.5 1.0

0.2

0.5 0 Coal

0.0 Oil

Natural gas

Hydrogen

Fig. 1 Hydrogen content factor (HCF), greenization factor (GF), and environmental impact factor (EIF) of hydrogen and other fossil fuels. Reproduced from Dincer I, Acar C. Review and evaluation of hydrogen production methods for better sustainability. Int J Hydrog Energy 2015;40 (34):11094–111.

countries, and in most cases, overseas. For example, after many decades of being a net exporter of both oil and gas, the United Kingdom became a net importer of natural gas and crude oil in 2004 and 2005, respectively. In the United Kingdom, oil and gas processing hit the highest point in the late 1990s and has only gradually decreased ever since. The main reason for this is the fact that the rate of fresh reserve discovery has not kept up with the rate of increase in oil and gas consumption. In addition, being a net importer of oil and gas has constituted a major impact on the United Kingdom’s energy economy [6]. Additionally, in the longer term, many countries expect coal, oil, and gas to continue being an essential but weakening contributor to their overall energy resources. The utilization of fossil fuels, especially for electricity and heat production and in the transportation sector, is expected to drop in support of renewable energy resources. Furthermore, fossil fuel depletion is highly likely to decrease as a consequence of the enhancements in energy efficiency and the improvement of innovative vehicles to operate efficiently, cleanly, and in an affordable manner. In addition, the white paper on energy [7] proposes that the possible permanent options for scaled-up substitutes to natural gas for heat production might be via the fabrication and utilization of hydrogen and electricity with low (or zero) emissions. On the other hand, by means of the numerous existing storage and end-use alternatives, such as microgeneration and combined heat and power (CHP), and the option to blend small amounts of hydrogen with natural gas in the distribution network, hydrogen can possibly become a part of a diverse energy supply portfolio of near to medium period solutions in order to tackle the issues related to fossil fuel dependence for heating, cooling, and oil transportation purposes. The hydrogen energy system is considered with the following components:

• • •

Production: from various energy and material resources, such as from fossil fuels with carbon capture and storage, biomass, nuclear energy, or renewable energies and water. Storing and delivery: this could be the linkage between the production and end-user sites or it could be used in order to bridge the gap between the supply and demand. Final end use: there are many end-use applications of hydrogen, such as electricity generation through fuel cells, or heat from internal combustion engines (ICEs), etc.

While hydrogen is the most plentiful element on Earth, it does not exist freely in its molecular (or functional) form; rather, it exists in other compounds (such as water, fossil fuels, ammonia, biomass, etc.). Therefore, it needs to be produced by utilizing a variety of energy and material resources, such as fossil fuels with CCS biomass, nuclear energy, or renewable energies and water. In contrast to the general idea, the whole idea of hydrogen energy and its utilization is not very new. Up until 1977, synthetic gas consisting of methane, carbon dioxide, carbon monoxide, and about 50 vol% hydrogen had been supplied to United Kingdom households. This manufactured gas mixture had been utilized for cooking purposes and as well as for delivering heat and lighting, before the interest had moved toward the much more inexpensive and clean natural gas [8]. Global hydrogen production from different energy sources in 2012 is presented in Fig. 2. In the coming decades, innovative energy supplies, advanced energy systems, and upgraded infrastructure are going to be needed to sustainably meet increasing energy demands. Hydrogen can provide enhanced efficiency and reliability, be generated from a wide range of locally available sources, and its use causes zero or low emissions of pollutants including greenhouse gases (GHGs). As a result, hydrogen has the capacity to support a nonpolluting, trustworthy, and inexpensive energy system, which can enrich the economy without damaging the environment or energy security. Hence, this chapter delivers the necessary information to understand hydrogen energy, from its characteristics and use as a fuel and energy carrier to comparison with other existing fuels and the energetic, environmental, and economic aspects of hydrogen energy.

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571

Electricity 4%

Coal 18%

Natural gas 48%

Oil 30%

Fig. 2 Global hydrogen production by different energy sources in 2012. Modified from International Energy Agency Technology Essentials. Hydrogen production and distribution. Available from: https://www.iea.org/publications/freepublications/publication/essentials5.pdf; 2012 [accessed 15.11.16].

1.13.2

Why Hydrogen?

Sustaining life in a high-quality manner without damaging future generations’ basic supplies is the main driving force to provide environmentally benign, safe, dependable, affordable, and continuous energy to the world, as mentioned earlier. To guarantee a viable financial background, new energy systems have to address the subsequent public requirements at reasonable costs:

• • •

diminish the negative impacts on climate change; lessen contaminated emissions; and find alternatives to decreasing fossil fuel sources.

Currently, it is commonly understood that not meeting these requirements could have potential negative influences on the economy, energy security, environmental and public health, and so on. Therefore, this confirms the importance of innovative approaches that should be developed in order to stimulate more effective utilization of energy supplies in clean, affordable, and reliable ways [9]. Furthermore, the possible impacts of climate change can be quite severe, and most importantly, usually irreversible. No country can afford to delay any counteractive actions. The goal, as discussed earlier, should be clean, reliable, affordable, and efficient energy systems for a sustainable future. When used together, electricity and hydrogen can potentially accomplish this goal [10]. Unlike fossil fuels, hydrogen is not a primary energy resource but rather an energy carrier. Therefore, hydrogen first needs to be extracted from its material source and a primary energy source. Renewable energy sources are seen as the most promising clean and replenishing primary energy sources to produce hydrogen. In addition to renewable hydrogen, nuclear and biomass-based hydrogen production are showing great promise. Fossil fuel-based sources can also be used to produce hydrogen together with carbon capture and storage (sequestration). These alternative pathways are more or less emission-free alternatives compared to today’s existing energy systems [11]. Furthermore, Table 2 compares the versatility of hydrogen to fossil fuels in terms of their ability to be converted to other energy forms for end-use purposes. Hydrogen is the only fuel in Table 2 that can take advantage of other processes in addition to combustion. Some of these processes are flame combustion, direct steam generation, catalytic combustion, chemical conversion, and electrochemical processes [12]. Hence, compared to the existing fuels, hydrogen is the most resourceful one. Large-scale hydrogen production is required for stationary and transportation-related applications. This is especially a challenging task considering the fact that there are not many existing large-scale hydrogen production facilities. Currently, fossil fuelbased hydrogen production with CCS is considered as the most promising option for large-scale hydrogen production due to the cost and supply security advantages of fossil fuels. With the help of supportive policies and incentives, novel hydrogen production methods from renewable sources are expected to become more and more viable. These renewable sources should be selected by considering local conditions, such as climatic and geographical constraints.

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Table 2

Versatility (convertibility) comparison of hydrogen and fossil fuels

Type of conversion

Hydrogen

Fossil fuels

Flame combustion Direct steam production Catalytic combustion Chemical (e.g., hydriding) Electrochemical (e.g., fuel cells)

Yes Yes Yes Yes Yes

Yes No No No No

Concentrated solar thermal energy is a promising, reasonably priced, and reliable energy source for large-scale hydrogen production, particularly for the sunny parts of the world, such as southern Europe, northern Africa, etc. In any case, there is a comprehensive variety of technologies, conversion processes, and end-use options for hydrogen energy systems. The variability of hydrogen production, conversion, transportation, delivery, and end-use options illustrate the flexibility of hydrogen energy systems [13]. For instance, fuel cells are expected to be utilized in a variety of applications, such as microscale fuel cells in portable devices (e.g., mobile phones, laptops, game consoles, etc.); transportation applications (e.g., buses, cars, ships, trucks, etc.); and small- and large-scale electricity and heat production for residential and industrial units. Forthcoming energy systems are expected to consist of better quality and highly efficient hydrogen energy systems (e.g., ICEs, stirling engines, turbines, etc.) in addition to other novel systems (e.g., renewable-based heat and electricity production, innovative fuels for transportation, etc.). In summary, the advantages of hydrogen energy systems are wide-ranging; however, in order to take full advantage of these systems, they have to be socially acceptable and utilized widely. Utilization of hydrogen energy systems have the major benefit of minimum (or sometimes even zero) GHG emissions including carbon dioxide, carbon monoxide, nitrogen dioxide, sulfur dioxide, etc. For example, fuel cells operate very quietly and efficiently, and their efficiency is not dependent on their size. Therefore, fuel cells are perfect for hospitals, IT centers, or for a variety of portable end-use applications. Fuel cell-based transportation can significantly reduce the sectoral energy consumption and resulting emissions. In addition, fuel cells could be utilized as auxiliary power units (APU) together with ICEs. As a result, fuel cells save energy and reduce pollutant emissions. Together, hydrogen and electricity characterize a very promising way toward sustainable energy systems, as fuel cells are one of the most efficient systems for conversion of hydrogen to electricity. Hydrogen energy systems can concurrently tackle all of the main energy and environmental issues. In addition, hydrogen energy systems are flexible enough to be adjusted to various renewable energy resources. Since renewable resources have an intermittent nature, the ability to flexibly switch between different sources without any problem is one of the vital requirements for the transition to clean energy systems for a sustainable future. A realistic investigation of alternative energy systems should be undertaken in order to demonstrate the advantages of extensive utilization of hydrogen energy systems. Cost-effective solutions should be developed in order to tackle the following crucial requirements, which are the major expectations from future energy systems: (1) secure and reliable energy supply; (2) economic competitiveness; (3) air, land, and water quality; (4) health improvements; and (5) GHG emissions reduction. Societies currently heavily rely on the constant accessibility of inexpensive fossil fuel resources. However, in the future, these fossil fuel resources are expected to be more and more concentrated in a smaller number of reserves. This is expected to create the possibility of geographical, political, and price instabilities. Hydrogen, on the other hand, unlocks access to a wide range of primary energy resources from fossil fuels to nuclear energy and biomass, and increasing amounts of renewable energy resources (e.g., hydro, ocean, solar, wind, etc.). As renewable energy sources get more reliable and easier to access, the accessibility and affordability of hydrogen as an energy carrier will escalate, which increases the favorability of hydrogen compared to the other available energy sources and carriers. The establishment of hydrogen as an energy carrier, together with or without electricity, would allow the current and future populations to utilize sources that are custom and suitable for different local conditions (e.g., climatic). In addition to the aforementioned advantages, hydrogen and electricity provide flexibility in matching centralized and decentralized power distribution via efficient and intelligent grid design, and energy supply for areas that are currently not (or are weakly) connected to the traditional grid (e.g., islands, remote villages, etc.). Decentralized electricity generation is advantageous both to confirm quality of supply to meet particular end-user requirements and to reduce any interruptions between central production and distributed end-use points. Hydrogen can be stored and transported easier than that of electricity, and this can help in supply and demand load tuning and offsetting the sporadic characteristics of renewable energy resources. Moreover, hydrogen is one of the unique energy carriers, which allows renewable energy resources to be brought into the transportation sector’s use. Ever since the initial oil crisis in the 1970s, economic development has directly been affected by access to secure energy sources, especially in the industry. For example, the transportation sector’s energy consumption has increased steadily due to greater mobility requirements of the 21st century. Energy requirements for sustainable economic growth should be lowered. In the meantime, as discussed previously, innovative energy systems are needed to provide reliable, affordable, and clean supply. Such energy systems are essential for sustainable economic growth, from new employment and export opportunities to other industrialization benefits. Global leadership in hydrogen energy systems can potentially have a significant role in creating better job prospects, from innovative research and development to maintenance and operation.

Hydrogen Energy

Table 3

573

Effect of zero-carbon hydrogen cars on average CO2 emissions from passenger car fleet

Year

Percentage of new carsa fueled by zero-carbon H2

Percentage of fleet fueled by zero-carbon H2

Average CO2 reduction (all cars)b (g/km)

CO2 prevented per year, MtCO2

2020 2030 2040

2 25 35

2 15 32

2.8 21.0 44.8

15 112 240

a

Based on the assumption of a passenger car fleet of 175 million vehicles. Calculation is not dependent of total number of cars. Source: Carslaw DC, Williams ML, Tate JE, Beevers SD. The importance of high vehicle power for passenger car emissions. Atmos Environ 2013;68:8–16.

b

In recent years, hydrogen and fuel cells have been respected as the essential technologies for the 21st century because of their importance for economic prosperity and energy security. There is strong interest, investment, and activity in the hydrogen and fuel cell research areas supported by many governments, research institutions, universities, and industries in order to drive the transition to hydrogen. Innovative technologies and postcombustion procedures for traditional fossil fuel-based energy systems are gradually lowering harmful emissions. On the other hand, nitrogen oxide and particulate matter emissions are still causing problems. The global movement toward urbanization requires clean energy systems for industrial development and better-quality and clean public transportation. Hydrogen-based transportation and power production support devices with zero emissions at the end-use point and subsequently improve public health and the environment. Hydrogen can be generated from carbon-free or carbon-neutral resources or from fossil fuels with carbon capture and storage (sequestration). Therefore, hydrogen utilization can ultimately reduce the GHG emissions of the energy sector. Hydrogen energy systems can enable effective electricity production in an environmentally benign way. Hydrogen energy systems near end-use points would make CHP generation possible. Table 3 shows how, in an established hydrogen economy, the launch of zero-carbon hydrogen vehicles can lower average CO2 emissions in the transportation sector. The data are based on the average emissions of 140 g CO2/km driven in 2008 [14]. The last column in Table 3 indicates the amounts of CO2 emissions that can be prevented by switching to zero-carbon hydrogen. The number of H2-fueled cars are an approximation based on an assessment of experts for traditional and hydrogenbased cars, which should not be taken as a forecast of prospective automobile production or sales. GHG emissions could be reduced by about 140 MtCO2 per year, which is 14% of the current levels of CO2 emissions from electricity production only. This can possibly be accomplished if approximately 17% of the total electricity demand (which is presently being met by fossil fuel-based centralized power stations) is substituted by more effective distributed power plants, integrating stationary high-temperature fuel cell systems to the hydrogen energy systems. The fuel cell units are expected to be utilized as base load in the prospective decentralized energy systems. Seventeen percent fuel cell replacement example is not planned as a target, however, it is provided as a simple illustration of the CO2 emissions savings, which would be accomplished with fairly reasonable penetrations of hydrogen-fueled vehicles and fuel cell-powered stationary electricity production. When 17% of current electricity demand is met by fuel cells together with the 15% hydrogen vehicle replacement in the current car fleet, CO2 emissions can be lowered by about 250 MtCO2 per year. This is about 6% of the energy production and utilization-based CO2 emissions prediction in 2030. Innovative and integrated systems, such as the ones mentioned here, can possibly help the world to reduce emissions in amounts larger than the requirements stated in the Kyoto Protocol.

1.13.3

Basic Facts of Hydrogen

Hydrogen is an element, which means that it cannot be broken down into different substances via any chemical reactions. What makes hydrogen unique is that it is the simplest and most abundant existing element in the periodic table. The symbol for the element hydrogen is H. Hydrogen is chemically very active; it is so active, in fact, that it more or less all the time occurs as a component (substance) combined together with other elements. When hydrogen bonds with other elements, it forms a compound, a substance that combines two or more of the same or different elements. A detailed list of key properties of hydrogen is presented in Table 4. Most of the hydrogen in the universe is found as hydrogen gas, which is symbolized as H2. Hydrogen gas is the most plentiful gas in the universe. By some estimates, it accounts for 75% of the universe’s mass [15] and it is colorless, odorless, and tasteless. Despite its abundance in the universe, hydrogen is not found as a free element, or in gas form, in nature. Instead, in nature at least, it exists in compounds with other elements. The most common hydrogen-containing compound found on Earth is water. Another compound containing hydrogen is methane. There are many other compounds containing hydrogen as well. For instance, hydrogen can be found in every living organism on Earth. The fact that earthbound hydrogen only exists in compounds bonded to other elements presents a problem for utilizing hydrogen as an energy carrier. For hydrogen to be a useful source of energy, it must be separated from its feedstock. Two of the most conventional hydrogen generation processes currently in use are natural gas steam reforming and water electrolysis.

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Table 4

Detailed properties of hydrogen

Properties

Value

Units

Molecular weight Triple point pressure Triple point temperature Normal boiling point (NBP) Critical pressure Critical temperature Density at critical point Density of liquid at triple point Density of solid at triple point Density of vapor at triple point Density of liquid at normal boiling point Density of vapor at normal boiling point Density of gas at normal temperature and pressure (NTP) Density ratio: NBP liquid to NTP gas Heat of fusion Heat of vaporization Heat of sublimation Heat of combustion (to steam at 1001C) Heat of combustion (to water at 01C) Specific heat (Cp) of NTP gas Specific heat (Cp) of NBP liquid Specific heat ratio (Cp/Cv) of NTP gas Specific heat ratio (Cp/Cv) of NBP liquid Viscosity of NTP gas Viscosity of NBP liquid Thermal conductivity of NTP gas Thermal conductivity of NBP liquid Surface tension of NBP liquid Dielectric constant of NTP gas Dielectric constant of NBP liquid Index of refraction of NTP gas Index of refraction of NBP liquid Adiabatic sound velocity of NTP gas Adiabatic sound velocity of NBP liquid Compressibility factor (z) of NTP gas Compressibility factor (z) of NBP liquid Gas constant (R) Isothermal bulk modules of NBP liquid Volume expansivity of NBP liquid Limits of flammability in air Limits of detonability in air Stoichiometric composition in air Minimum energy for ignition in air Auto ignition temperature in air Hot air jet ignition temperature Flame temperature in air Thermal energy radiated from flame Burning velocity in NTP air Detonation velocity in NTP air Diffusion coefficient in NTP air Diffusion velocity in NTP air Buoyant velocity in NTP air Maximum experimental safe gap in NTP air Quenching gap in NTP air Detonation induction distance in NTP air Limiting oxygen index Vaporization rate of liquid pools Burning rate of spilled liquid pools

2.0159 0.0965 13.803 20.268 12.795 32.976 0.0324 0.077 0.0865 0.0001256 0.0708 0.000134 0.000083746 845 58.23 445.59 507.39 119.93 141.86 14.89 9.69 1.383 1.688 8.75  10 5 1.33  10 4 1.897 1 1.93  10 3 1.00026 1.233 1.00012 1.11 1294 1093 1.0006 1.712  10 2 40.7037 50.13 1.658  10 2 4–75 18.3–59 29.53 0.02 858 943 2318 17–25 265–325 1.48–2.15 0.61 2 1.2–9 8  10 3 4.6  10 3 100 5 2.5–5 3.0–6.6

amu atm K K atm K g/mL g/mL g/mL g/mL g/mL g/mL g/mL – J/g J/g J/g MJ/kg MJ/kg J/g K J/g K – – g/cm s g/cm s mW/cm K mW/cm K N/m – – – – m/s m/s – – mL atm/g K MN/m3 vol% vol% vol% MJ K K K % cm/s km/s cm2/s cm/s m/s cm cm cm vol% cm/min cm/min

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575

Power supply

Cathode (–)

Anode (+)

H2

O2 3

6

H2O

H 2O

2

5

H 2O

H2O

H+

4

1

Heat

Cation exchange membrane

Heat

Fig. 3 Schematic description of continuous hydrogen production via electrolysis.

Presently, the most widespread way of taking hydrogen out of hydrogen-comprising compounds is via a method commonly referred as steam reforming. This method is comparatively cheaper compared to the other available hydrogen production methods. Steam reforming occurs in two simple stages. First, natural gas is mixed with steam that is at least at 2001C. Then, a chemical reaction takes place between the steam (containing hydrogen and oxygen) and natural gas. This process generates hydrogen in addition to carbon monoxide and carbon dioxide. In the second step, further hydrogen is generated as carbon monoxide is mixed with additional steam. The final product is what the process name suggests: the steam is reformed, the hydrogen and oxygen molecules are separated and removed from each other, and additional hydrogen is generated at the end of the process. The other major hydrogen extraction method currently in use is known as water electrolysis. In water electrolysis, electricity is utilized to divide water into gaseous hydrogen and oxygen. In this process, electric current is applied to water. This current causes separation on the bonds among the oxygen and hydrogen molecules, and as a result, these bonds are broken. The oxygens bond together to form oxygen gas and the hydrogens are collected as a product. Fig. 3 schematically illustrates the electrolysis of water where the current from the power supply splits the water molecules into their component parts, and hydrogen and oxygen, which are collected in cathode and anode sides, respectively. A major effect to the cost, emissions, and efficiency of electrolysis is the source and the cost of the electricity used for the splitting process. Despite the fact that there are many energy resources that could be utilized to supply the electricity for electrolysis, fossil fuel (such as coal, natural gas, etc.) combustion to generate electricity, and hence feed the electrolysis, damages the environment. For that matter, clean, renewable, and affordable energy sources should be used to produce the electricity used in electrolysis. Renewable sources are seen as key to sustainable hydrogen production for future hydrogen energy systems. One of the most interesting and important things about hydrogen is that once it is produced, it can be stored and transported from where it is produced to the point of end use. Compressed gas (e.g., in cylindrical or quasi conformable tanks), liquid hydrogen (e.g., in cylindrical, elliptical, high pressure, or cryogenic tanks), solid state conformable storage (e.g., hydride materials or carbon adsorption), and chemical hydrides are some of the hydrogen storage options. Presently, the most commonly used hydrogen storage method involves the compressed gas state. Gas phase hydrogen storage needs less energy than liquid phase storage. But, hydrogen gas has a very low volumetric energy density, causing the requirement of high volumes to contain a significant amount of hydrogen energy. Therefore, in order to store hydrogen in a limited space, it has to be highly pressurized (compressed). The high-pressure gas can then be stored in durable, rigid, and pressure-resistant (mostly metal) pressurized storage tanks. In the future, large quantities of gas could be stored in specifically designed storage areas, such as caverns, mines, etc. The stored hydrogen can then be directed through a piping system into homes and buildings where it is needed for energy, much in the same way natural gas is transported to multiple end-use locations today. Compressed hydrogen gas tends to require a lot of storage space. On the other hand, liquid hydrogen has far more volumetric energy density than the gas phase. As a result, with liquid hydrogen, more hydrogen (and more energy) can be stored in a given

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space compared to the compressed gas option. By using special cooling techniques to convert hydrogen gas into liquid phase, it is possible to store and transport much more of the hydrogen. Liquid phase hydrogen storage is usually considered to be tricky and inefficient. One reason for this is the requirement to cool hydrogen down to about 2531C, which requires quite a large amount of energy. In addition, it is very difficult to keep the pressure and temperature at a level to maintain hydrogen in the liquid phase. A common problem with liquid hydrogen is the “liquid boil off,” which is the evaporation of liquid hydrogen, resulting in a large amount of energy loss. Nevertheless, liquid hydrogen may be the choice for future airplane fleets, as its compactness could make it possible for transportation via aircrafts with limited space. Hydrides are chemical compounds consisting of hydrogen and certain metals like magnesium, nickel, copper, or iron. When hydrides are heated, they decompose and the bounded hydrogen is released. One problem with hydrides, however, is that they weigh a lot in comparison to the amount of energy they carry. Scientists are trying to develop hydrides that carry more hydrogen and hence more energy. Once hydrogen is split off from its original compound and stored, it is ready to provide energy. The energy that goes into the splitting process is carried in the bonds of the stored hydrogen. In order to get to this energy, the single bonds between hydrogen molecules must be broken. There are two ways this can be done. The first option is through the controlled burning of the hydrogen as a fuel. Hydrogen fuel can be burned as either liquid or as a gas. The burning fuel generates heat, which can be used to run a furnace, boiler, or to power several end-use options, such as cars, airplanes, etc. An engine that burns hydrogen during operation produces virtually no pollution. The second way is to get the energy through a fuel cell, which can generate electricity as a result of the recombination of hydrogen and oxygen, as opposed to electrolysis. When oxygen and hydrogen are combined, they produce electricity, heat, and clean water. Even though fuel cells are considered to be quite similar to batteries, they are quite different compared to traditional engines. First of all, they are completely stationary, which means that they have no moving parts. As a result, they are quiet during operation and very efficient. Most importantly, fuel cells produce no pollution during operation. Fuel cells can be utilized for a variety of different end-use options. The electrical energy they produce is good for anything, which can work with electricity. Recently, fuel cell-powered cars have been closely investigated by many researchers and people from the industry. An advantage of fuel cells compared to batteries is that the energy stored inside the fuel cell remains with minimal loss until it is needed. Unlike a regular battery, as long as there is hydrogen gas supplied to a fuel cell, it does not need to be recharged.

1.13.4

Applications Diversity of Hydrogen

Hydrogen is a basic substance that is utilized greatly in the industry, especially in the production and processing of chemicals (such as ammonia and methanol production) and petrochemical refining (such as hydrotreatments, hydrogenation of unsaturated hydrocarbons, hydrosulfuration, etc.). There exist additional industries and end-use options where hydrogen can be employed, such as the electronic, metal/glass, and aerospace industries, food production and processing, semiconductor industry, etc. (Fig. 4).

Electronic industry 6%

Metal/glass industry 3%

Chemical industry/refine ries 35%

Food industry 2%

Ammonia production 54%

Fig. 4 Global hydrogen consumers by industry. Data from Stiller C, Hochrinner H. Use of conventional and green hydrogen in the chemical industry. In: Topler J, Lehmann J, editors. Hydrogen and fuel cell. Berlin; Heidelberg: Springer-Verlag; 2016. p. 173–86.

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Production Storage

Delivery Conversion

Applications Fig. 5 Illustration of interactions between the components of hydrogen energy systems and applications.

Hydrogen can be utilized to produce electricity and heat via fuel cells or ICEs. Fuel cells produce electricity via an electrochemical reaction, which combines oxygen and hydrogen and produces water. The electricity generated from this reaction can possibly be utilized in a variety of portable and stationary end-use options including the transportation industry. In addition, the byproduct heat generated as a result of this electrochemical reaction can be utilized for heating and cooling purposes [16]. Fuel cells can also be added up together to produce power in larger scales dependent on the requirements of the end-use system. On the other hand, the manufacturing cost of fuel cells is still somewhat more expensive than the cost of an ICE. Additional actions to enhance the fuel cell stability and decrease the associated costs are in the research and development phase [17]. Some examples of hydrogen in fuel cell applications involve in stationary CHP units, which can be utilized either for large centralized energy generation or microgeneration of heat and power. Areas that are rich with renewable energy resources but have limited access to produce or export electricity (i.e., the ones that are disconnected from the electricity grid) can especially become the possible beneficiaries of CHP applications. Hydrogen can be utilized in hydrogen internal combustion engine vehicles (HICEVs) and hydrogen fuel cell electric vehicles (HFCEVs) as a transportation fuel. Hydrogen utilization in ICEs is more or less similar to the traditional fossil fuel-based engines currently used in the transportation industry, except with minor alterations. The literature has indicated that hydrogen combustion is a lot cleaner with enhanced efficiency by about 20% compared to the combustion of fossil fuels [18]. As a result, HICEVs could be considered as a realistic near-term option during the transition to HFCEVs. In the longer term, hydrogen fuel cells and EVs are expected to be the more widely held end-use technology for transportation, primarily due to the fact that fuel cells can produce electricity onboard the vehicle. Current hybrid EVs necessitate plug-in systems to connect them to the electricity grid. This may possibly have long-term consequences in the electricity grid [19]. Many key automotive companies have fuel cell EV models in the research and development phase. Some of these car producers, such as Chrysler, Ford, Honda, General Motors, Hyundai, Mercedes-Benz, Nissan, Toyota, etc. [18], already lease out automobiles to the public in many parts of the world. Hydrogen can be utilized in traditional power production systems as well, such as the engines used in the transportation industry and power plant turbines. Hydrogen can also be used in fuel cells that are reasonably cleaner and more effective compared to the conventional combustion technologies. Fuel cells have extensive end-use possibilities in both transportation and power generation industries, such as on-site use for different households and office buildings. Interactions between the components of hydrogen energy systems and applications are shown in Fig. 5. The applications of hydrogen energy are countless, and it is expected to have many more novel applications with the advances in material science, hydrogen production, conversion, and end-use technologies. Some of the applications of hydrogen energy include:

•

•

Transportation applications: aircrafts, automobiles, buses, ships, trucks, and trains are some of the examples of hydrogen use in the transportation industry. Fuel cell and ICE technologies are currently getting more and more advanced to effectively utilize hydrogen (and methanol) in transportation applications. Currently, almost every company in the transportation sector is investing in research and development activities to effectively use hydrogen in a variety of vehicles, such as via fuel cells. There are many examples of successful fuel cell use for transportation applications. There are already some developments of smallscale fleets consisting of between 10 and 150 vehicles. The early fuel cell transportation applications are expected to be set up in small fleets with either central or shared fueling stations to minimize the capital investment requirements. The early fuel cell vehicle fleets can be utilized to decide how and when to expand the existing infrastructure to larger production scales. Hydrogen-fed ICE-based vehicles are usually seen as cheaper and shorter-term solutions during the advancement of the required hydrogen infrastructure and technologies. A major benefit of ICEs is that they can easily be scaled up. Stationary power applications: backup power systems, grid management, supply to areas without grid access, district heat and power systems, and multigeneration (such as CHP; combined heating, cooling, and power, etc.) are some examples of stationary power applications. Even though commercial fuel cell systems are currently being used, they are still in the early stages of research and development. Many current fuel cell technologies are utilized in commercial end-use systems and work on reformate from natural gas. Extensive obtainability of hydrogen can possibly help the establishment of direct hydrogen energy systems, which are less complicated with reduced costs and enhanced reliability, availability, and affordability. As a general rule, combustion-based practices – for example, gas turbines and reciprocating engines – can possibly be redesigned to utilize hydrogen either alone or together with natural gas. These combustion systems have a tendency to support end-use

578

Hydrogen Energy

Table 5

Characteristic requirements of transportation and stationary applications for hydrogen energy

Characteristics

Transportation

Stationary

Max power Design life Cost Electrical output Efficiency Power range Power density (volume) Specific power (weight) Operation Energy storage Transient response Short-term fuel Long-term fuel

50–100 kW 5000 h $50–100/kW High voltage AC or DC Very high 20 to 1 Very high Very high Intermittent Possibly 1/10 of seconds Gasoline and diesel Hydrogen

2–200 kWa 50,000 h $300–1000/kW 220 V AC or 48 V DC Very high 10 to 1 Moderate Moderate Continuous (24/7) Possibly 1/1000 of seconds Natural gas/propane Hydrogen

a

Multiunit housing. Source: Partnership Plan. FreedomCAR Fuel Partnership. Available from: https://www.hydrogen.energy.gov/pdfs/fc_fuel_ partnership_plan.pdf; 2016 [accessed 01.12.16].

•

•

options in the greater power requirement ranges of stationary energy processing. Characteristic requirements of transportation and stationary applications are presented in Table 5. Portable power applications: handheld devices and portable electronics, as well as small industrial, office, and household equipment, and so on can be provided as examples of portable applications for fuel cell utilization. Numerous members of the fuel cell research and development community are focusing on forming small-scale units for a number of portable and novel power uses alternating from 25-W systems for portable electronics to 10-kW ones for essential commercial and medical purposes. A large amount of these portable applications are expected to utilize methanol or hydrogen as the fuel. Along with the end users’ small devices, portable fuel cells might be a good fit for APU in niche applications, such as portable fuel cell use in the military. Hydrogen applications in future energy systems: hydrogen is accessible for daily end users’ energy demand in the market, involving transportation, power supply, industrial processes, and portable energy systems. Hydrogen is expected to be the principal fuel for public and private transportation systems. Hydrogen can be utilized in a great segment of passenger cars and light duty vehicles (LDVs). It can be combusted alone or mixed with natural gas in turbines and reciprocating engines to produce electricity and heating or cooling for households, workplaces, and industrial units. Hydrogen fuel cells can be used for both portable and stationary applications. Some examples of hydrogen-powered portable devices are computers, mobile phones, Internet providers, and a wide variety of other electronic equipment. In order to accomplish the vision of hydrogen applications, the subsequent issues are needed to be overcome:

•

•

Stationary and portable applications (including transportation) need innovative and novel technological systems. For example, end users of the transportation industry require clean, feasible, and reliable hydrogen storage with satisfactory volumetric and gravimetric energy capacities. The lack of such a storage system harshly delays the expansion of hydrogen energy systems’ infrastructure. Moreover, different storage methods might require significantly different infrastructure schemes. In addition, there is a need for reliable, affordable, and effective fuel reformation technologies. Customers have to accept hydrogen energy systems including fuel cell-powered vehicles. Currently, fuel cell-powered vehicles are in the initial stages of research and development. The earlier fuel cell-powered vehicles are not expected to fully meet the end-user requirements (e.g., driving range, effective operation in very hot or cold climates). In contrast, traditional ICE-powered vehicles hold the advantage of more than 100 years of technical improvement in addition to fairly reliable and low-cost gasoline to power them. Car manufacturers move on to produce traditional vehicles, which are increasingly more affordable, efficient, environmentally benign, and reliable.

The hydrogen energy systems’ infrastructure for fuel cell vehicles (with no onboard reformation) can be set up slowly in a stepby-step manner. However, this infrastructure is expected to be very limited in the early stages of the development. In the first phases of commercialization, car manufacturers are also expected to provide a limited number of fuel cell vehicle types in the market, which would restrict the alternatives for the consumers. The majority of the advantages offered by hydrogen-fueled vehicles compared to conventional fossil fuel-powered ones are characteristically more societal (e.g., reduced carbon dioxide and GHG emissions, enhanced energy security, etc.). These benefits cannot be completely understood until many years after their market introduction. Besides this, hybrid electric and traditional vehicles are expected to exist in the market in the near term, and may possibly become strong competitors to hydrogen-powered vehicles. Even though traditional systems with modifications can possibly support early market entrance of hydrogen energy systems, these technologies are expected to keep up holding the main market advantage in terms of vehicle driving range, at least in the

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579

short term. With their low energy densities, current hydrogen-powered vehicles have driving ranges from 300 to 400 km, which is a lot less than the 550 to 650 km ranges provided by modern fossil fuel-based vehicles. Optimized hydrogen-powered traditional systems have confirmed that they may possibly attain efficiencies similar to the expected amounts of fuel cells, with zero or nearzero emissions. Vehicles must be restructured for uniformity in driving range, and the public should be informed of the advantages of hydrogen-powered vehicles to enhance their distinguished worth. These challenges can be overcome by (1) conducting research and development to tackle the essential requirements of hydrogen energy systems; (2) increasing hydrogen energy systems’ demonstrations significantly; (3) instituting protocols, rules, and principles to raise public recognition of hydrogen energy systems; and (4) developing public policies that promote utilization of hydrogen as a fuel in different applications. Portable (including transportation) and stationary (both small- and large-scale) applications need development of reliable, affordable, and durable fuel cell stacks and systems. Some of the fuel cell improvement requirements include high-temperature membrane fabrication and testing; affordable sensors and controls with fast response and low power consumption; reliable and affordable system components including compressors, heaters, power supplies, pumps, valves, etc.; and inexpensive but reliable hybrid components, such as ultracapacitors. In transportation end-use options, reformer investigation ought to be focused on allowing short-term utilization of hydrogen before expanding the hydrogen distribution systems to an entire region or country (or even worldwide networks). Hydrogen storage investigation for transportation applications have to concentrate on methods and technologies that have the capacity to keep up with the driving ranges of similar fossil fuel-powered vehicles. This research should also aim for systems that are secure, are of low weight and small size, and are affordable and reliable. Storage systems must be able to operate with the fueling infrastructure, and the safety of storage system components must be guaranteed via the introduction of protocols, rules, and principles. In hydrogen-fueled ICEs, new combustion techniques and postcombustion treatments should be utilized to take full advantage of enhanced power densities and system efficiencies and minimize end-use emissions. Development of flow control and monitoring and engine management systems for commercially ready vehicles is very challenging from an engineering design point of view. When monitoring and controlling emissions in stationary turbines, lean combustion is generally the desired strategy. Lean combustion makes the combustion process control much more manageable. However, lean combustion commonly causes acoustic instabilities. Therefore, research and development is required to improve control strategies to make hydrogen and hydrogen-enriched fuels achieve broader public acceptance levels. The near-term research and development needs of fuel cells include stability, price of the fuel cell systems, integration with innovative energy systems, and development of system architecture and reformers. At both the local and global levels, governments need to establish leading fuel cell and hydrogen energy systems laboratories to address the research and development needs in a concentrated manner with broader availability and applicability. These leading laboratories are expected to design and test novel technologies and innovative systems that are widely applicable to all fuel cell systems. These laboratories are also expected to provide suitable locations for designing and testing more robust hydrogen-based products. For both ICEs and fuel cells, new technological developments should demonstrate the short-term availability of numerous alternative systems for central and distributed heat and power generation. The efforts to develop new hydrogen-based energy systems would also include the development of mini economies around hydrogen infrastructures. Traditional energy conversion systems should be established and validated in stationary, transportation, hybrid, and mobile applications. These energy conversion systems also need to be planned to endorse the extensive utilization of existing and future hydrogen clusters. As a result, the design, development, building, and utilization of the existing and future hydrogen infrastructures would make both stationary and transportation applications of hydrogen energy systems possible. Research and development on hydrogen energy systems must be extended beyond present technological accomplishments. Governments should encourage the use of stationary fuel cells in public buildings. Several partnerships, for example, the US Department of Energy’s FreedomCAR platform [20] and the California Fuel Cell Partnership [21], have proven the benefits of academic, government, and industrial partnerships for better, cleaner, and more efficient transportation with hydrogen energy systems. Public and private sector collaboration shows that early hydrogen-fueled vehicles and their fueling infrastructure should be developed together in order to reduce any economic risks during transition to a hydrogen economy. Note that traditional local and global interconnection contracts are required to facilitate assembly to the present electricity grid with no penal costs, procedures, or activities. These contracts and instructive resources need to be arranged for by fire, insurance, and building code officials. Convincing the general public to utilize hydrogen energy systems will necessitate incentives – for example, cost-sharing procedures, price uniformity policies, and “rights-of-way” for hydrogen energy systems – that are analogous to the ones used in the natural gas infrastructure. The governments should implement local and global level standards, and utility companies need to treat stationary hydrogen customers similarly compared to the other customers using the same rate class. Distributed production options should be evaluated based on their ability to recover waste heat and enhance overall system efficiencies. There are some sample strategies, such as the design and development of emissions trading, carbon taxation to minimize emissions, etc. In addition, the governments should support innovative hydrogen energy systems for a sustainable future in a variety of ways by offering incentives for scientific and technological investments. Some examples of governmental support for scientific and technological advancements can be listed as tax credits for cleaner and more efficient transportation options

580

Table 6

Hydrogen Energy

Brief summary of needs and activities for hydrogen energy applications

Needs

Activities

Consensus on technically based codes and standards Public–private partnerships for demonstrations Government as early adopter Short-term hydrogen and end-use technologies to stimulate infrastructure and market readiness Research and development for onboard storage

Consortium of agencies to set codes and standards Benchmark programs for zero-emission vehicles Begin demonstration programs Generate the market with the purchase of fleets

Community-based applications and installations

Include demos for onboard storage tanks that can achieve 6, 7, and 8 wt% of stored hydrogen per weight of tank Issue competitions, select winners, commence building, complete installations

and financial support for the development of large- and small-scale, stationary, or portable hydrogen infrastructure development. The fundamental purpose of hydrogen energy systems is to allow consumers to utilize hydrogen energy for a variety of end-use applications, such as transportation, residential and commercial electricity production, and portable devices including calculators, flashlights, mobile phones, global positioning system (GPS) devices, and laptop computers. When the cost, stability, and efficiency problems related to hydrogen energy systems are successfully solved, the following challenges are expected to include public awareness and approval. Energy security, accessibility, reliability, financial viability, and reduced negative environmental impacts are some of the important demands of the end users. Various industries have to focus on comprehending end-user preferences and directing the end-user interest to various forms and stages of hydrogen energy systems. The governments have to recognize prospects that allow the utilization of hydrogen energy systems in centralized and/or distributed heat and power generation facilities and vehicle fleets. A brief summary of needs and activities for hydrogen energy applications is presented in Table 6. Based on the status of the current hydrogen market at the local and global levels, further research and development activities are needed for efficient, clean, affordable, and reliable operation of a widely accepted hydrogen economy. Based on the latest studies from the literature focusing on the local and global state of hydrogen energy systems and fuel cell know-how [22–27], further research and development is recommended in many fields; for example, the types of fuel cell systems and their application in transportation and heat and power generation applications.

1.13.5

The Role of Hydrogen as a Potential Fuel

Hydrogen can be used for a variety of end-use purposes, such as an energy carrier or as a clean, efficient, abundant, and reliable fuel. Before discussing the use of hydrogen as a fuel, it is essential to fully understand its fundamental characteristics including its physical and chemical properties. Hydrogen is a colorless, fragrance- and taste-free, nontoxic gas in atmospheric conditions. Hydrogen is the lightest existing molecule, with molecular weight of 2.016 g/mol. Hydrogen has a very low density, which is around 0.0899 kg/m3 at normal temperature (273.15K) and pressure (101.325 kPa). This is about 7% of the density of air. Even liquid hydrogen has very low density, which is about 70.8 kg/m3 (7% of the density of water). The boiling point of liquid hydrogen is very low, at about 2531C (20.3K). Therefore, liquefaction of hydrogen necessitates quite a complicated apparatus to condense hydrogen and keep it in liquid state. Hydrogen has a remarkably low density, as mentioned earlier. And as a result, it has the highest energy-to-weight (i.e., heating value) and lowest energy-to-volume ratios compared to those of the fuels presented in Table 7.
The thermodynamic heat of combustion of hydrogen (i.e., its heating value) is equal to the standard heat of formation DHfo of the product water: 1 H2 ðgasÞ þ O2 ðgasÞ-H2 OðliquidÞ 2

DHfo ¼

285:83 kJ=mol

ð4Þ

The standard heat of formation of hydrogen can be shown in an alternative way as 141.78 MJ/kg H2. Standard heat of formation of hydrogen is the highest quantity of heat that can be extracted from hydrogen combustion if the resulting steam is condensed to 298.15K. This amount is also called the HHV of hydrogen. In general, the water produced during hydrogen combustion is discharged as steam. In these systems, the calorific value of steam with the latent heat of condensation is wasted. In a combustion process, when the steam is discharged at 1501C, the actual heat of combustion is about 120 MJ/kg. This amount is a practical value called the LHV. Hydrogen burns cleanly in air; water is the only product apart from traces of nitrogen oxides at high combustion temperatures. It has a wide range of flammability (lower flammability limit is 4 vol%, higher flammability limit is 75 vol%). Since the lower explosive limit of hydrogen in air (13 vol%) is higher than the lower flammability limit, hydrogen generally burns rather than exploding. The rate of propagation of the wave front (which is also known as the flame velocity) is controlled by diffusion through the nitrogen in the air. Hydrogen is exceptional compared to other fuels for holding such a large difference (18%) between its higher and LHVs. When estimating the overall theoretical efficiency of hydrogen energy systems (such as fuel cells), it is essential to take the HHV into account. However, when comparatively assessing the actual or relative efficiencies of energy systems’ components (such as boilers),

Hydrogen Energy

Table 7

581

Technical comparison of hydrogen with other fuels

Boiling point (K) Liquid density (kg/m3)a Gas density (kg/m3)a Heat of vaporization (kJ/kg) Higher heating value (HHV)b (MJ/kg) Lower heating value (LHV)b (MJ/kg) LHVb (MJ/m3) Diffusivity in air (cm2/s) Lower flammability limit (vol%) Upper flammability limit (vol%) Ignition temperature in air (1C) Ignition energy (mJ) Flame velocity (cm/s)

Hydrogen

Petroleum

Methanol

Methane

Propane

Ammonia

20.3 70.8 0.0899 444 141.9 120.0 8,520 0.63 4 75 585 0.02 270

350–400 702 – 302 46.7 44.38 31,170 0.08 1 6 222 0.25 30

337 797 – 1168 23.3 20.1 16,020 0.16 7 36 585 – –

111.7 425 0.718 577 55.5 50.0 21,250 0.20 5 15 534 0.30 34

230.8 507 2.01 388 48.9 46.4 23,520 0.10 2 10 466 0.25 38

240 771 0.77 1377 22.5 18.6 14,350 0.20 15 28 651 – –

a

At normal temperature and pressure (NTP) of 273.15K and 101.325 kPa, respectively. These values are slightly different in different sources provided by different authors. Source: Reproduced from Rand DAJ, Dell R. Hydrogen energy: challenges and prospects, vol. 1. Cambridge: Royal Society of Chemistry.

b

it is generally appropriate to choose the LHVs. However, it should also be taken into account that the technologically advanced condensing boilers retrieve some portion of the waste heat. As a result, these devices have efficiencies between higher and LHVs. Hydrogen exhibits a great diffusivity in air, and its flame velocity is a lot higher compared to those of traditional fuels in gas phase. When combined with pure O2 in a 2:1 M ratio of H2 to O2 and kindled, hydrogen explodes aggressively as there is no inert gas to reduce the velocity of the wave front. Energy requirement of hydrogen ignition is remarkably low (0.02 mJ as shown in Table 7). This energy requirement is less than 10% of the ignition energy requirement of natural gas. Altogether, physical characteristics of hydrogen, such as its low density, low boiling point, wide range of flammability, low ignition energy, high diffusivity in air, and high flame velocity make it very unique compared to other existing fuels (see Table 7). It should be noted that this combination certainly makes it challenging to utilize hydrogen in large scale. From the optimistic point of view, the low density of the gaseous hydrogen and its high diffusivity in air make outdoor hydrogen leaks quickly and securely disperse. On the other hand, most of the existing liquid fuels stay on the floor and vaporize slowly after a leakage and this causes a serious fire hazard. During a spillage, even liquid hydrogen vaporizes nearly immediately because of its very low boiling point. After vaporization, gaseous hydrogen diffuses away quickly, minimizing the risk of any fire hazard. However, the situation is not the same in closed areas. A comparison of the volumetric energy densities of compressed hydrogen gas, liquid hydrogen, and other fuels is shown in Fig. 6; methane represents natural gas and octane represents petroleum. From Fig. 6, it can be seen that highly compressed methane and other liquid fuels (i.e., methanol, ethanol, propane, and octane) are quite superior to hydrogen in terms of volumetric HHV energy density. Fig. 7 comparatively assesses the safety of gasoline, methane, and hydrogen. For each of the toxicity indicators and fire risk properties, the fuels are ranked within a range from 1 to 3, with 3 indicating the safest option and 1 indicating the least safe fuel in each category. The rankings presented here are taken from Ref. [24]. The safety rankings data have been shown for each selected fuel, and the total and average rankings are also taken into account. The overall rankings have been summed up to obtain the safety factors, defined as the ratio of the total ranking for hydrogen to that of a given fuel. The data show that hydrogen is the safest fuel, with an average ranking of 2.50; white gasoline is the least safe, with an average ranking of 1.38; and methane is in between the two, with an average ranking of 1.38 out of 3. The wide-ranging flammability and explosive ranges of gaseous hydrogen in air make any leak very likely to increase the fire or explosion risks. Since hydrogen does not contain any carbon molecules, it combusts with a nonluminous flare, which does not radiate heat. As a result, passersby are not exposed to the risk of heat burns via radiation. However, the nonluminous heat has a negative impact: since it is nearly imperceptible and it does not radiate heat, there is generally a risk of unintentionally drifting into the flare and getting severely hurt. In addition, due to the low ignition energy of hydrogen in contrast to other traditional fuels, serious safety measures must be used to eliminate static electricity when handling hydrogen in large amounts. The precautions might be wearing cotton or wool clothes instead of synthetic clothes and grounding all tools, which may possibly cause risks of a spark. Clearly, the characteristic properties of hydrogen make it an exceptional fuel to handle. As a result, the operators should be very competent and proficient in order to work with hydrogen. For instance, the skilled operators who work in the large-scale use of hydrogen have stated their doubts about letting inexperienced people work in the refueling stations for hydrogen vehicles. Leakage of hydrogen in enclosed spaces, such as garages, tunnels, subways, etc. would especially cause a serious public risk. The safety of hydrogen should be ensured from both the scientific and social perspectives. The safety aspect is one of the major issues for hydrogen energy systems to be taken forward to future generations.

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Higher heating value (GJ m−3)

40

30

20

10

0 Hydrogen (20 MPa)

Hydrogen (80 MPa)

Liquid hydrogen

Methane (20 MPa)

Methane (80 MPa)

Liquid methanol

Liquid ethanol

Liquid propane

Liquid octane

Fig. 6 Higher heating value (HHV) per unit volume for various fuels. Modified from Winter CJ, Nitsch J. Hydrogen as an energy carrier: technologies, systems, economy. Dordrecht: Springer Science and Business Media; 2012.

Gasoline Fuel toxicity 3 Flame emissivity

2

Combustion toxicity Methane

1 Explosion energy

0

Ignition limit Hydrogen

Flame temperature

Ignition energy Ideal lgnition temperature

Fig. 7 Safety comparison of hydrogen, methane, and gasoline. Data from Sheffield JW, Sheffield C. Assessment of hydrogen energy for sustainable development. Dordrecht: Springer Science and Business Media; 2007.

Liquid hydrogen as a fuel presents its own handling problems. Due to its exceptionally low boiling point, all hydrogencontaining vessels and transmission networks have to be specifically designed based on strict codes and regulations. This normally implies a high-vacuum enclosure with multilayer insulation and heat reflection surfaces arranged alternately. Often there is a surrounding vessel containing liquid nitrogen (boiling point 79K) as an additional barrier between the hydrogen at 20K and the air at ambient temperature. Care must also be taken to ensure that ice condensation does not lead to blockages in the storage and dispensing system. Custom-designed connectors are needed when pumping liquid hydrogen from cryostat to cryostat. A further complication with liquid hydrogen arises from the fact that the hydrogen molecule exists in two forms, namely, orthohydrogen (the ortho isomer), in which the nuclear spins of the two atoms are aligned parallel, and parahydrogen (the para isomer), in which the nuclear spins are antiparallel. At ambient temperatures, the equilibrium mixture contains around 75% ortho isomer and 25% para isomer. On cooling, the ortho isomer converts progressively to the para counterpart; practically, all the hydrogen goes through transformation at 20K. The ortho–para conversion releases heat (703 J/g of orthohydrogen) in excess of the heat of evaporation of hydrogen (446 J/g). The consequence is loss of liquid by boil-off and the need for greater energy to be expended in the liquefaction process.

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Widespread knowledge and skills have been achieved on safety when handling liquid hydrogen, both in laboratory-scale and large-scale systems. The use of liquid hydrogen in the space industry as a rocket fuel is a great example of these accomplishments. So far, no undefeatable technical issues have been faced. However, the specialized equipment required for liquid hydrogen is very expensive. This is the major reason why liquid hydrogen is not seriously considered as a fuel alternative except in the space industry. In the space industry, the low density of liquid hydrogen is principally a very valuable advantage. In the lab scale, liquid hydrogen has been used as a fuel in transportation end-use applications and there has been some initial attention paid to utilizing liquid hydrogen as an aircraft fuel only for now [28]. By virtue of its physical and chemical properties, it is clear that hydrogen has the potential to occupy a unique position in the future world energy scene. Not only can it become ultimately a universal means of conveying and storing energy – especially if renewable energies become dominant in the market – but also an entirely novel fuel with properties that are distinct from those of other fuels. Hydrogen is the obvious choice for a low-carbon economy in that it would release no pollutants to the atmosphere, and, when coupled to carbon sequestration or derived from nonfossil fuel-based primary energy sources, little or no GHG emissions would contribute to climate change. Before becoming too enchanted by this vision, it is important to realize that the hydrogen economy is a complex concept that holds a wide variety of opportunities. Therefore, it is essential to differentiate between:

• • • •

Hydrogen as a chemical fuel or an energy carrier: it is primarily to understand the difference between these two different enduse options because the financial characteristics of these two are not the same. Hydrogen production from fossil fuel or nonfossil fuel-based sources: biomass, hydro, nuclear, solar, wind, etc. can be named as nonfossil fuel-based sources and the sustainability of a process completely depends on the selection of the source. Hydrogen used in ICEs or fuel cells: the selection of the end-use option also strongly affects the sustainability of the designed hydrogen energy system. Hydrogen for stationary or mobile applications: different end-use requirements would completely change system design requirements, costs, emissions, etc.

There is a broad range of detailed hydrogen production routes starting from primary energy resources, which can include both fossil fuel and non-fossil fuel-based sources. In addition, various options should be evaluated, with their distinct practical and financial characteristics. Hydrogen is expected to play an important role in future energy systems. This can only be determined when all the research and development is accomplished. Scaled-up projects and demonstrations should also be conducted. In addition, full thermodynamic, financial, and environmental assessments should be conducted as well [29].

1.13.6

Hydrogen Energy Systems

With scientific and technological advancements in the fields of sustainability, it is becoming obvious that it would be advantageous to produce hydrogen by taking advantage of any and all primary existing energy resources, with the aim of making up for their weaknesses. When a strong infrastructure is developed by taking advantage of all resources in a clean, reliable, efficient, and affordable manner, a successful hydrogen energy system can be built for future generations. Fig. 8 shows a graphic illustration of a hydrogen energy system from hydrogen production to the end of its life cycle. In a successful hydrogen energy system, hydrogen (and oxygen) is manufactured in big industrial processes. In these processes, the primary energy source should preferably be renewable, such as hydro, solar, wind, etc. and/or non-carbon based, such as nuclear, and even fossil fuels. The best (and most renewable) material source to produce hydrogen is water (H2O). Both the material and energy resources should be abundant, affordable, and available. When large-scale storage is needed, hydrogen can be deposited underground in old mines, caverns, and/or aquifers. Hydrogen is delivered via pipelines or supertankers to the locations of end use. Consequently, it can be utilized in electricity production, or for transportation applications, or served to industrial, residential, and commercial sectors as a fuel and/or an energy carrier. In this process, the side product is either water or steam. If flame combustion of hydrogen is used, then some NOx might be emitted. Water and steam are recycled back as raw material, through rain, rivers, lakes, and oceans, to replace the water utilized initially for hydrogen production. The byproduct oxygen generated during hydrogen production process can either be discharged to the atmosphere, or delivered to industrial and residential end-use locations to be used in fuel cells for electricity generation. Currently, in fuel cells, hydrogen is mixed with air instead of oxygen. Therefore, using pure oxygen instead of air could have the benefit of enhanced system efficiencies. In addition, the byproduct oxygen can be utilized by many industrial processes for nonenergy-related end-use purposes. Furthermore, this oxygen can also be used to rejuvenate the contaminated water reserves (e.g., lakes, rivers, etc.), or to accelerate sewage treatment. It should not be forgotten that in a hydrogen energy system, hydrogen is not the primary source of energy. It is an intermediary or secondary form of energy or an energy carrier. Hydrogen supplements the existing primary energy sources, and delivers these sources to different end-user types in an appropriate form at the desired location and time. Hydrogen is used in many industries as a chemical raw material, especially in the production of fertilizers, but also in making dyes, drugs, and plastics. It is used in the treatment of oils and fats, as a fuel for welding, to make gasoline from coal, and to produce methanol. In its super cold liquid form, in combination with liquid oxygen, it is a powerful fuel for space shuttles and other rockets.

584

Hydrogen Energy

Energy carrier

Material source: Water

Emissions: water Transportation

Residential/ commercial/ industry

Electricity generation

Primary energy sources Fig. 8 Illustration of a clean hydrogen energy system. Modified from Acar C, Dincer I. Comparative environmental impact evaluation of hydrogen production methods from renewable and nonrenewable sources. In: Dincer I, Colpan CO, Kadioglu F, editors. Causes, impacts and solutions to global warming. New York, NY: Springer; 2013. p. 493–514.

Hydrogen is produced commercially in almost a dozen processes. Most of them involve the extraction of the “hydro” part from hydrocarbons. The most widely used and least costly process is “steam reforming,” in which natural gas is made to react with steam, releasing hydrogen. Water electrolysis, in which water is broken down into hydrogen and oxygen by running an electrical current through it, is used where electricity is cheap and high purity is required. Hydrogen can be stored as a high-pressure gas or as an integral component in certain alloys known as hydrides, but also in and on microscopic carbon fibers (a recent development). As a cryogenic liquid fuel, it promises to lead to better, faster, more efficient, environmentally “clean” airplane designs. Metallic hydrogen, a laboratory curiosity so far, holds promise as an ultraenergetic fuel and as a zero-resistance electrical conductor in all sorts of electrical and electronic technologies. Since the 1930s, environmentally oriented scientists, academics, and energy planners (inside and outside government), industrial executives, and even some farsighted politicians have been thinking of and supporting the concept of hydrogen as an almost ideal chemical fuel, energy carrier, and storage medium. As a fuel, hydrogen does not pollute. As an energy storage medium, it would store energy when it is available for use and the energy sources are not available or not sufficient. Hydrogen is not an energy “source,” a mistake still made fairly often by otherwise sophisticated, well-informed people. That is, it is not a primary energy source (like natural gas or crude oil), existing freely in nature. It is an energy carrier, which means that it is a secondary form of energy, which must first be produced from a primary energy source similar to electricity. Electricity does not exist freely in useful form either. Hydrogen could be produced from many primary energy sources, and this is very beneficial to begin with. This advantage reduces the risk of causing a hydrogen cartel similar to Organization of the Petroleum Exporting Countries (OPEC) (which, for a while at least, was able to dictate global energy prices). Hydrogen is currently produced (or extracted) typically from fossil fuels. However, there are increasing efforts to replace these fuels with cleaner alternatives. This is usually known as decarbonizing hydrogen energy sources, which has been common jargon among energy researchers since the beginning of the 1990s. In reality, decarbonizing means modification of the existing technologies that have long existed in the chemical, petroleum, and natural gas industries in order to minimize or completely eliminate the carbon and/or CO2 emissions, while producing hydrogen. In the future, hydrogen is expected to be made from clean and abundant material and energy resources, such as water and renewables (e.g., geothermal, hydro, ocean, solar, wind, etc.). Nuclear is also considered as a carbon-free energy source of hydrogen, and biological (including biomass based) hydrogen production methods are being investigated for more sustainable hydrogen routes. Since hydrogen can be made from both nonrenewable and renewable resources, it can be phased into the overall energy structure by whatever method is most convenient and least wrenching to a given country, state, region, or economy. Coal gasification could be utilized in areas where coal reserves are rich and easily reachable, and solar-based hydrogen production can be especially effective in desert regions with plenty of available solar energy, such as the Middle East or the southwestern part of the United States. Recently, there have been many studies focusing on direct solar water splitting, in which the sun’s concentrated heat [2,30] or photonic energy [31–35] would directly break up water molecules into hydrogen and oxygen. In addition, water could be electrolyzed with electricity produced by geothermal resources in some areas, and perhaps also from the oldest form of renewable energy, hydropower. In the simplest terms, the broad outlines of a future hydrogen energy system run something like this:

Hydrogen Energy

•

•

•

• •

585

Clean primary energy: probably solar energy in its many variations; possibly an advanced, environmentally more benign version of nuclear energy, or other renewable energy resources. These resources would either produce electricity to be used to split water into hydrogen or directly used to produce hydrogen without an intermediate electricity generation. Alternatively, heat produced by solar or nuclear power plants would be used to crack water molecules thermochemically in processes now under development. More novel methods, in which hydrogen is produced from genetically engineered microbes, from algae for instance, and from other biological processes are likely candidates further down the road. Hydrogen would be used as an energy storage medium: as a gas under pressure, in hydrogen-absorbing alloys (which are generally known as hydrides), as a cryogenic liquid, or in activated-carbon materials and carbon nanostructures; but also in the form of relatively conventional fuels, such as methanol. Hydrogen would fulfill the indispensable storage function of smoothing the daily and seasonal fluctuations of solar power. Hydrogen could be burned in modified ICEs: jets, turbines, four-strokes, two-strokes, Wankels, and diesels. This was the vision, conviction, and message of hydrogen’s supporters from the 1970s through the mid-1990s. Since then, with sudden and rapid advances in fuel cell technology, the emphasis has shifted dramatically toward fuel cells as the future engines of choice for transportation [36] and also as clean, efficient, decentralized sources of electricity for buildings. Fuel cells running on reformed gasoline [37] or methanol [38] would produce trace amounts of carbon emissions, which would be much less than ICEs of comparable power; plus, perhaps, small amounts of nitrogen oxides from fuel processors that generate hydrogen from these carbonaceous fuels. Ultimately, fuel cells operating on pure hydrogen would be quintessentially clean, producing no nitrogen oxides and no hydrocarbons. The only thing coming out an exhaust pipe would be harmless water vapor (steam), which would immediately return to nature’s cycle of fog, clouds, rain, snow, groundwater, rivers, lakes, and oceans. That water could then be split again for more fuel. As a gas, hydrogen can transport energy over long distances, in pipelines, as cheap as electricity (under some circumstances, perhaps even more efficiently), driving fuel cells or other power-generating machinery at the consumer end to make electricity and water. As a chemical fuel, hydrogen can be used in a much wider range of energy applications than electricity. For example, it is difficult to envision a large commercial airliner powered by electric motors of any conceivable type. In addition, hydrogen does double duty as a chemical raw material in myriad uses. And unlike other chemical fuels, it does not release pollutants commonly known as GHG emissions.

Two major goals of international hydrogen research for hydrogen energy systems have been to find economical ways of making the fuel and find out how to store it efficiently onboard a space-constrained car, bus, or truck. During the 1970s and the 1980s, much if not most of the hydrogen production research was aimed at splitting large volumes of water molecules. This was perceived as the crucial prerequisite to using hydrogen as a fuel. In the 1990s, the emphasis shifted to making hydrogen energy, which was not necessarily ultrapure hydrogen, an industrial and commercial reality. Thus much more attention was paid to improving the steam reforming of natural gas. The efforts of carmakers to use methanol as a sort of hydrogen carrier for fuel cell vehicles are another example. Today, methanol is produced industrially from natural gas; therefore, it can also be made without any major impact on the atmosphere (it should be noted that “carbon or carbon dioxide-neutral” is the catchphrase here) from green plants (biomass) that, in their growth phase, absorb CO2 [39]. A second approach is exemplified by the US Department of Energy (DoE)’s logistics-driven strategy of developing, in cooperation with major carmakers, onboard fuel processors that would extract hydrogen from gasoline and other fossil fuels. The managers of the DoE’s partnership for a new generation of vehicles (PNGV) [40] argue that this approach would spur a shift toward cleaner energy by using the existing fuel infrastructure as a transitional alternative long before an efficient, widespread hydrogen infrastructure can be put in place. In past decades, hydrogen advocates believed that a global “hydrogen economy” would begin to take shape near the end of the 20th century, and that pure hydrogen would be the universal energy carrier by the middle of the 21st century. Hydrogen may not completely attain that lofty status in that time frame, but it is certain to play a much larger role, directly as a fuel for fuel cells, and indirectly as an increasingly large component of carbon-based fuels, such as methanol, and other conventional fuels, in the decades ahead. Many see hydrogen as an increasingly important complement to electricity; electricity and electrolysis can break water down into hydrogen and oxygen, and hydrogen recombined with oxygen can produce electricity and water again. Each of them is used in areas where it serves best; and for a long time to come, it will have to compete with, and in fact, be dependent on, conventional fossil fuels as its source. If hydrogen’s benefits as a fuel are so great, the average person might reasonably ask, why did not hydrogen make significant inroads into our energy systems years or even decades ago? There is no single, or simple answer to that question; rather, there is a complex array of interlocking factors. For one, there was no real use for hydrogen as long as there were ample supplies of oil and natural gas, and environmental worries were the concerns of a tiny minority. Hydrogen’s principal advantage over conventional fuels is that it is emission-free. That, by itself, was not considered to merit a society-wide switch to alternatives of any sort. Fossil fuels have been cheap, and hydrogen has been as much as several times more expensive. Liquid hydrogen, the cold and highly pressurized cryogenic liquid that powers the space shuttles [41] and experimental BMW sedans today [42], was a laboratory curiosity four or five decades ago. Technologically, the level of development had been such that producing, handling, and storing hydrogen were quite complex, difficult, and perhaps beyond the abilities of a routine consumer, and it still is. Even today, some of the major players in the

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Table 8

Summary of hydrogen energy system components and their status in the transportation sector

Component

System capacity

Energy efficiencya

Investment costb

Lifetime

Maturity

c

Fuel cell vehicles

80–120 kW

43–60%

$60,000–100,000

150,000 km

Hydrogen retail stations Tube trailer for gaseous hydrogen delivery Tanks for liquid hydrogen distribution

200 kg/day

B80%d

$1.5

–

o1000 kg/day

B100%e

$1,000,000 ($1000/kg payload)

–

Early market introduction Early market introduction Mature

o4000 kg/day

0.3 vol% loss per dayf

$750,000

–

Mature

2.5 million

a

If not specified otherwise, efficiencies are calculated based on the lower heating values (LHV). All power-specific investment prices are based on the energy output. c Tank-to-wheel fuel cell efficiency is based on the higher heating value (HHV). d Including compression to 70 MPa. e Does not include compression. f Boil-off steam. Sources: Gao D, Jiang D, Liu P, et al. An integrated energy storage system based on hydrogen storage: process configuration and case studies with wind power. Energy 2014;66:332–41; The United States National Renewable Energy Laboratory. National fuel cell electric vehicle and hydrogen fueling station scenarios. Available from: https://www. hydrogen.energy.gov/pdfs/review16/sa061_melaina_2016_o.pdf; 2016 [accessed 12.12.16]; International Energy Agency. Technology roadmap for hydrogen and fuel cells. Technical annex. Available from: https://www.iea.org/media/freepublications/technologyroadmaps/TechnologyRoadmapHydrogen_Annex.pdf; 2015 [accessed 04.05.16]; Iiyama A, Tabuchi Y, Ohma A, Sugawara S, Shinohara K. (Plenary) FCEV development at Nissan. ECS Trans 2014;64(3):11–7; Parks G, Boyd R, Cornish J, Remick R. Hydrogen station compression, storage, and dispensing technical status and costs: systems integration: Report No. NREL/BK-6A10-58564). Golden, CO: National Renewable Energy Laboratory (NREL); 2014; Wipke K, Sprik S, Kurtz J, et al. National fuel cell electric vehicle learning demonstration final report: Technical report NREL/TP-5600-54860. Contract No. DE-AC36-08GO28308; 2012; Katikaneni SP, Al-Muhaish F, Harale A, Pham TV. On-site hydrogen production from transportation fuels: an overview and techno-economic assessment. Int J Hydrog Energy 2014;39 (9):4331–50. b

accelerating “hydrogen sweepstakes,” including DaimlerChrysler, argue that hydrogen may have to be made available in some forms, such as liquid methanol, to be user-friendly [43]. The technology is not perfect, and is still evolving. Bringing a technology to maturity takes time. For instance, we have only recently become able to operate really well with natural gas. Automobiles have been around for more than a century, yet even the best-engineered examples have their occasional glitches and breakdowns. Perhaps most importantly, societal issues have prevented major progress. For one, replacing an entire technologically advanced energy system with something else is a huge undertaking, spanning decades. It is like trying to change the course of a supertanker with kayak paddles. The hydrogen energy system consists of an immense infrastructure consisting of enormous physical and human capital, with not only tanks and pipelines and motors, but also people (e.g., bankers, auto mechanics, drillers, educators, politicians, students, end users, etc.); hence, it evolves slowly [44]. Phasing in hydrogen would require “innumerable replacements”; for instance, substituting fuel cells for internal combustion engines is only one small aspect. Perhaps the biggest impediment to change for the better is our value system, or in other words, what we are willing to pay for. By and large, environmental health is not high on the list. Hence, hydrogen has not taken off because society does not yet place value on sustainability: in economic terms, the cost of fuels does not include the externalities of health effects due to urban air pollution, oil spills, groundwater contamination, military cost of defending oil, and most importantly, the potential risks of major climate change. Put another way, society has a very high discount rate; we discount any adverse effects that occur in the future. If the price of coal, oil, and natural gas included a full accounting of externalities, then hydrogen would look much more promising overnight. If people had to pay $3 per liter for gasoline to cover fossil fuel damages to our health and environment, then suddenly hydrogen fuel cell vehicles and hydrogen produced by wind, solar, or biomass would look like a bargain. Investors would flock to hydrogen equipment manufacturers. People would convert their sport utility vehicles (SUVs) to run on clean-burning hydrogen derived from solar energy at only $0.66 per liter of gasoline equivalent. A truly sustainable energy future has two attributes: no pollution or GHG emissions, and no consumption of nonrenewable resources. Hydrogen has a great potential to meet these goals, if produced from renewable or clean energy sources. Table 8 shows a summary of the components of hydrogen energy systems in the transportation sector and their energetic, economic, and technological status. Even though there are many other feasible options to utilize hydrogen as a fuel in the transportation sector, such as synthetic methane, use in compressed natural gas (CNG) vehicles or methanol conversion, this chapter focuses on hydrogen energy systems and the employment of pure hydrogen. Infrastructure development is needed to deliver hydrogen from the production site to the hydrogen retail stations or other enduse points. Advantages and disadvantages of hydrogen delivery options from central, semicentral, and distributed production sites to the various end-use points are complex. For instance, the selected hydrogen production method also significantly affects the hydrogen delivery method and cost.

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587

Centralized hydrogen production facilities are usually much larger and their hydrogen production costs are relatively lower because of the advantages of large-scale production; however, these facilities suffer from high delivery costs because of the fact that the production and end-use points are generally far away from each other. In contrast, distributed hydrogen production options have comparatively lower delivery costs, although distributed hydrogen production is likely to be more expensive as distributed production is generally in lower amounts, which increases the costs per unit of hydrogen production. Hydrogen has been utilized in a variety of industrial applications for decades. However, current hydrogen delivery infrastructure and available technologies are not advanced enough to sustain extensive public utilization of hydrogen. This is because hydrogen has a moderately low volumetric energy density; the transportation, storage, delivery, and end use of hydrogen are significantly expensive. Furthermore, these activities cause some losses and system inefficiencies. Hydrogen delivery is associated with some major challenges, such as high delivery costs, low energy efficiencies, maintaining a level of hydrogen purity during delivery, and hydrogen leakages. Additional research and development are required to examine the advantages and disadvantages of hydrogen production and delivery options together. It is very well known that development of local and global hydrogen delivery infrastructures is a significantly challenging task. This task is expected to take time, and development of safe, reliable, affordable, clean, and efficient hydrogen production and delivery infrastructures at the local and global levels is expected to comprise combinations of numerous technologies. Hydrogen delivery infrastructure requirements and existing energy and material sources differ as a function of local conditions and market types (e.g., urban, interstate, or rural). Infrastructure possibilities are also expected to advance as the hydrogen demand propagates and as new delivery methods are developed and the existing ones are improved. An option to quickly expand the hydrogen delivery infrastructure is to use some parts of the existing natural gas delivery infrastructure. Transforming existing natural gas pipelines to deliver a mixture of natural gas and hydrogen (which would be up to about 20 vol% hydrogen) might necessitate simple adjustments in the pipelines. However, transforming existing natural gas pipelines to distribute pure hydrogen would possibly need more significant alterations. An alternative potential hydrogen delivery solution is to produce a liquid hydrogen carrier, like ethanol or ammonia, at a central production site, and pump the liquid carrier via pipelines to many end-use locations. At the end-use location, the liquid hydrogen carrier can be processed further to recover hydrogen to be used in a variety of applications. Liquid hydrogen carriers provide the possibility of utilizing current pipelines and delivery infrastructure technologies for hydrogen distribution. There are many options to deliver hydrogen, such as trucks, railcars, ships, barges, etc. These options can be utilized to deliver hydrogen in compressed gas or cryogenic liquid phases. There are also some novel hydrogen delivery options via liquid or solid carriers. Nowadays, compressed hydrogen can be delivered via tube trailers at pressures up to 200 bar (around 3000 psi). Hydrogen delivery by using compressed gas is an expensive method. Nevertheless, this method gets less expensive when the delivery distances are longer than 160 km. Scientists are exploring technologies that could allow tube trailers to function at pressures up to 700 bar (about 10,000 psi), to decrease costs and extend the range of hydrogen delivery. Hydrogen is currently delivered over longer distances as a cryogenic liquid in well-insulated, cryogenic tank trucks. In this option, gaseous hydrogen is cooled to below 2531C ( 4231F), liquefied, and stored at the liquid state in large and wellinsulated containers. Then, liquid hydrogen is distributed to delivery trucks and transferred to end-use points. At end-use points, it is vaporized and compressed in high-pressure gas tanks. When delivering hydrogen over long distances, liquid hydrogen becomes a cheaper option compared to gaseous hydrogen since liquid hydrogen has a much larger energy density. However, hydrogen liquefaction is a very energy-intensive process. With current technology levels, liquefaction requires 30% more energy than the energy content of the liquefied hydrogen itself, so this process is not very efficient or cheap. Furthermore, a considerable amount of the liquefied hydrogen gets lost during the liquid state storage period as a result of vaporization; this is known as “boil-off.” This becomes especially problematic when small tanks are used with large surface-tovolume ratios. Research is needed to make liquefaction processes cheaper, more efficient, and reliable. Also, large-scale hydrogen production and delivery technologies together can potentially reduce the associated costs. Current liquefaction plants are very small, and their operations are expensive. Larger-scale liquefaction facilities close to the point of hydrogen production can also lower the cost of the production and delivery steps of the hydrogen energy systems. In the future, hydrogen is expected to be delivered as cryogenic liquid in trucks with small tanks or in ships with large tanks. In larger tanks, the “boil-off” rate is lower, which means that less hydrogen is lost due to rapid vaporization. In any case, future cryogenic hydrogen delivery options should have better insulation to keep the hydrogen in liquid state as long as possible by minimizing “boil-off” losses due to vaporization over both short and long delivery distances. Scientific and engineering challenges related to hydrogen delivery can be summarized as follows:

• • • • •

Currently, there is no large-scale cost-effective hydrogen production method. Hydrogen delivery technologies are not capable of providing safe, affordable, reliable, and clean hydrogen to end-use locations. Copyrighted data of design materials used in hydrogen energy systems are not available to the public. There is a lack of agreement on the hydrogen purity requirements needed in fuel cells. There is a lack of design criteria for large-scale hydrogen delivery.

In addition, there are some environmental and institutional challenges related to hydrogen transmission and delivery. Some of these challenges can be listed as follows:

588

• • • • • • • •

Hydrogen Energy

Most of the codes and standards do not take hydrogen into account. National and international codes and standards are not harmonized well. Social costing for carbon emissions is not defined as a common global level agreement. Full life cycle environmental impact assessments of all components of hydrogen energy systems do not exist. Liquefaction process has high energy input requirements, and emits high levels of GHG. Conflicting local, state/provincial, national, and/or global interests is a barrier to public acceptance of hydrogen energy systems. There are serious concerns related to the potential environmental damages of fossil fuel-based hydrogen production options. The experience and knowledge required for safe and reliable operation and maintenance of hydrogen energy systems do not exist. Lastly, there are some market challenges related to hydrogen delivery and transmission as well, some of which are listed below:

• • • • •

Currently, there is no fully developed economic strategy for successful transition from traditional fuels to hydrogen energy systems. Hydrogen energy systems are more expensive compared to the energy systems based on traditional fuels. Existing hydrogen delivery infrastructure does not provide affordable, reliable, convenient, and clean hydrogen. Current hydrogen storage capacities do not meet consumer expectations. Delivering hydrogen over long distances (especially in gas phase) is expensive. In order to address the challenges mentioned above, the following action items can be taken:

• • • • • •

Codes and equipment standards are needed to be built with the industry and support and funding from the governmental agencies. Intercity delivery demonstrations and showcases should be conducted via industry-directed cost-sharing partnerships with local and state-level governments. Consensus should be reached on total costs of fuel alternatives via government-directed and subsidized initiatives with support from national labs, research centers, and universities. Financial incentives should be improved for delivering hydrogen to markets via local and state-level government leadership. Hydrogen economy evolution strategy should be supported with measurable and controllable milestones and goals via leadership from the industry and local, state/provincial, and national governments and support from national labs, research centers, and universities. Further research, development, and advanced investigations are required to explore innovative liquid or solid hydrogen storage mediums to keep hydrogen in a different chemical state, not as free molecules, which cause considerable amounts of system losses and inefficiencies. Potential novel chemical hydrogen storage mediums are ammonia, metal hydrides, carbon, or other nanostructures, etc.

Table 9 presents the current energetic and exergetic performance of hydrogen energy systems for large-scale energy storage applications. The incorporation of large-scale hydrogen into the existing or future energy systems is expected to enhance the operative flexibility of these energy systems. A broad variety of methods and schemes exist to incorporate high percentages of flexible energy generation (which should be around 30%–45% of the annual electricity production) in a cost-effective manner without using large-scale seasonal energy storage [45]. On the other hand, all local conditions including the governmental and industrial, current and future grid infrastructures, and current investments should be taken into account when exploring possible strategies for the extensive use of novel energy storage technologies. When looking at Table 9, it should be noted that hydrogen energy systems in integrated systems are not based only on electricity storage. Large-scale hydrogen energy systems are still at early stages in research and development, and the expectation is that there would be additional alternatives to the options in Table 9. As discussed in earlier sections, energy storage systems can take full advantage of hydrogen when using the excess electricity from a variety of different energy sectors. For instance, hydrogen produced from this surplus electricity can be used as a fuel in the transportation sector or as a chemical material feedstock in the industry. The following are some examples of the surplus electricity usage:

• • • •

Power-to-power (PtP): hydrogen is produced via electrolysis, stored for a desired amount time, and used to produce electricity again when required via fuel cells or gas turbines. Power-to-gas: hydrogen is produced via electrolysis then mixed in the existing natural gas grid as hydrogen-enriched natural gas (HENG) or used to produce synthetic methane using a cheap CO2 resource. Power-to-fuel: hydrogen is produced via electrolysis and then utilized in fuel cells as a fuel. Power-to-feedstock: hydrogen is produced via electrolysis and then used as a chemical feedstock in the industry, such as in refining.

A thorough summary and discussion of novel hydrogen energy systems that have been actively investigated both theoretically and experimentally at the University of Ontario Institute of Technology’s (UOIT) Clean Energy Research Laboratory (CERL) and some recent findings through experimental measurements and analyses can be found in Ref. [46].

Table 9

Summary of the performance of hydrogen energy systems for large-scale energy storage applications

Application

Power or energy capacity

Energy efficiencya

Investment costb

Lifetime

Maturity

Power-to-power (PtP) (including underground storage) Underground storage Power-to-gas (hydrogenenriched natural gas (HENG))

Gigawatt hour (GWh) to terawatt hour (TWh)

29% (higher heating value (HHV), with alkaline electrolyzer (EL)) to 33% (HHV, with proton exchange membrane (PEM) EL) 90%–95% including compression B73% excluding gas turbine (HHV)

1900 (with alkaline EL) to $6300/kW (with PEM EL) plus B$8/kWh for storage

20,000 to 60,000 h (stack lifetime EL)

Demonstration

30 years 20,000 to 60,000 h (stack lifetime EL)

Demonstration Demonstration

Power-to-gas (methanation)

GWh to TWh

B$8/kWh 1500 (with alkaline EL) to $3000/kW (with PEM EL), excluding gas turbine 2400 (with alkaline EL) to $4000/kW (with PEM EL), including gas turbine (PtP) 2600 (with alkaline EL) to $4100/kW (with PEM EL), excluding gas turbine 3500 (with alkaline EL) to $5000/kW (with PEM EL), including gas turbine (PtP)

20,000 to 60,000 h (stack lifetime EL)

Demonstration

GWh to TWh GWh to TWh

B26% including gas turbine (PtP) B58% excluding gas turbine (HHV) B21% including gas turbine (PtP)

a

Unless otherwise stated, efficiencies are based on the lower heating values (LHV). All power-specific investment costs refer to the energy output. Sources: Gao D, Jiang D, Liu P, et al. An integrated energy storage system based on hydrogen storage: process configuration and case studies with wind power. Energy 2014;66:332–41; The United States National Renewable Energy Laboratory. National fuel cell electric vehicle and hydrogen fueling station scenarios. Available from: https://www.hydrogen.energy.gov/pdfs/review16/sa061_melaina_2016_o.pdf; 2016 [accessed 12.12.16]; International Energy Agency. Technology roadmap for hydrogen and fuel cells. Technical annex. Available from: https://www.iea.org/media/freepublications/technologyroadmaps/TechnologyRoadmapHydrogen_Annex.pdf; 2015 [accessed 04.05.16]; Iiyama A, Tabuchi Y, Ohma A, Sugawara S, Shinohara K. (Plenary) FCEV development at Nissan. ECS Trans 2014;64(3):11–7; Parks G, Boyd R, Cornish J, Remick R. Hydrogen station compression, storage, and dispensing technical status and costs: systems integration: Report No. NREL/BK-6A10-58564). Golden, CO: National Renewable Energy Laboratory (NREL); 2014; Wipke K, Sprik S, Kurtz J, et al. National fuel cell electric vehicle learning demonstration final report: Technical report NREL/TP-5600-54860. Contract No. DE-AC36-08GO28308; 2012; Katikaneni SP, AlMuhaish F, Harale A, Pham TV. On-site hydrogen production from transportation fuels: an overview and techno-economic assessment. Int J Hydrog Energy 2014;39(9):4331–50. b

Hydrogen Energy 589

590

Hydrogen Energy

1.13.7

Hydrogen Energy Storage and Safety

Viable hydrogen storage is considered by many as one of the most crucial and technically challenging barriers to the widespread use of hydrogen as an effective energy carrier [47,48]. Hydrogen contains more energy on a weight-for-weight basis than does any other substance. Unfortunately, since it is the lightest chemical element of the periodic table, it also has a very low energy density per unit volume (Fig. 9). A widely used and successful hydrogen infrastructure would possibly need some sort of large-scale storage (which could be underground) to operate with variable demand and energy sources. In some areas, natural structures, such as salt caverns, can be utilized as underground hydrogen storage mediums. In areas where there are no natural structures, engineered underground storage mediums, such as rock caverns, can be used for hydrogen storage. Large-scale underground storage is commonly used for natural gas storage. However, hydrogen has quite different characteristics compared to natural gas. For example, hydrogen molecules are much smaller compared to natural gas. Additional research is required to assess the suitability of large-scale underground hydrogen storage and to confirm appropriate engineering of the storage location. The hydrogen economy (and hydrogen energy systems) would possibly need two forms of hydrogen storage systems. One form would be used for transportation applications and the other one should be suitable for stationary use. Both transportation and stationary applications have specific necessities and restraints. The transportation industry is expected to become the first largescale end user of the innovative hydrogen energy systems. The hydrogen storage necessities for the transportation industry are a lot more rigorous compared to the stationary end-use requirements. Operating necessities for the ideal hydrogen storage system for the transportation industry can be summarized as follows:

• • • • • • • • •

Reversibility of hydrogen uptake and release with a lifetime of at least 500 cycles. Operating pressure of less than 4 bar. Operating temperature in the range from 50 to 15081C. Fast kinetics of hydrogen uptake and release. Gravimetric storage density should not be less than 9 wt% of the storage system. Volumetric storage density should not be less than 70 g of H2/L of the storage system. Safe operation. Public acceptance. System cost should be cheaper than $20/kg H2.

Operating necessities for the ideal hydrogen storage solution for the transportation industry are strict and coupled with each other. These necessities represent fundamental scientific challenges during the transition to a transportation sector fully supported by reliable, viable, affordable, and clean hydrogen storage systems. Currently, there are basically no hydrogen storage systems capable of meeting all these necessities together.

12

35 kWh/kg

kWh/L 10

25 8 20 6 15 4 10

Specific energy (kWh L−1)

Specific energy (kWh/kg)

30

2

5

0

0 Liquid Hydrogen hydrogen (200 bar)

Liquid Natural gas natural (200 bar) gas

Petrol

Diesel

Coal

Methanol

Wood

Electricity (Li-ion battery)

Fig. 9 Energy density of selected fuels and hydrogen storage options (note: storage container weight and volume are not included). Data from Andrews J, Shabani B. Re-envisioning the role of hydrogen in a sustainable energy economy. Int J Hydrog Energy 2012;37(2):1184–1203.

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Size (both weight and volume) constraints of hydrogen storage systems for stationary applications are less severe compared to the transportation sector’s requirements. Stationary hydrogen storage systems might occupy big spaces, work at high temperatures and pressures, and compensate their slow uptake and release cycles with additional energy storage capacities. However, hydrogen storage systems for stationary applications have some key scientific and technical challenges as well, especially when it comes to the selection of hydrogen storage mediums. Hydrogen storage can theoretically be in three forms: solid, liquid, and gas. Solid phase hydrogen storage is usually within the chemical structure of hydrides (e.g., metal hydrides) or porous materials (e.g., carbon nanotubes). In liquid phase storage, hydrogen is usually retained at cryogenic temperatures around 2531C in very well-insulated containers. In gas phase storage, hydrogen is kept as a compressed gas at pressures around 150 bar. Gas phase hydrogen storage is without a doubt the simplest and most commonly used method for both small- and large-scale hydrogen storage applications. Currently, there are two key options for large-scale gaseous hydrogen storage and these options are either salt cavities or deep aquifer layers [49]. At present, there are some facilities using large-scale gaseous hydrogen storage, some of which are:

• • •

ConocoPhillips (TX, United States): storage capacity of 580,000 m3. Praxair (TX, United States): storage capacity of 566,000 m3. Sabic Petrochemicals (Teesside, United Kingdom): storage capacity of 210,000 m3.

For transportation applications, onboard and small-scale hydrogen storage is required, which has some characteristically different requirements. Small-scale gas phase hydrogen storage is commonly used for transportation applications, which use commercial steel cylinders or composite material tanks. In small-scale gas phase hydrogen storage, the storage tanks can hold hydrogen at pressures up to 700 bar. Some of the gas phase hydrogen storage system requirements include quite expensive and rare materials for tank construction, which can increase the cost of hydrogen storage. Currently, research on hydrogen storage systems mainly focus on high-pressure gas phase or cryogenic liquid phase storage. Commercial steel cylinders are capable of storing hydrogen at pressures up to 200 bar, and they have a hydrogen storage capacity of about 1 wt%, which is equal to 186 Wh/kg of storage medium. There are some novel composite high-grade carbon fiber cylinders (ultrahigh density) that can store gaseous hydrogen at pressures from 700 to 1000 bar. This increases the hydrogen storage capacity of the system up to 10 wt% (1860 Wh/kg of storage medium). Unfortunately, these innovative cylinders are not cheap and they require complex and expensive equipment to operate. Hydrogen storage in cryogenic form has the advantage of considerably greater gravimetric energy density compared to the compressed gas. It should be noted that the density of the liquid hydrogen is 70.8 g/L at 252.881C and 1 bar. On the other hand, this amount is still 14 times less than the density of water (1 kg/L). In addition, cryogenic liquid tanks need extremely good insulation to avoid the loss of hydrogen by evaporation (“boil-off”). Currently, even the best available insulation material cannot avoid the loss of hydrogen in liquid phase and the boil-off rates are higher than 1% per day for small cryogenic tanks used for transportation applications. Compressed gas and cryogenic liquid phase hydrogen storage options have advanced quite well in recent years; however, they are still not capable of meeting the transportation applications’ requirements simultaneously. These options also cannot meet the early, midlevel, and long-term goals of hydrogen storage systems for transportation applications [50]. Another significant disadvantage of these methods is their inefficiency in energy use and storage. For example, almost 20% of the energy stored in hydrogen is needed to pressurize it to desired pressures for gas phase storage. In the liquefaction process, about 30% of the energy content of hydrogen is needed to liquefy it. One more critical problem is the fact that the use of high pressures and very low temperatures raises some concerns related to public health and safety, which has direct negative impacts on public awareness and acceptance. The recent research and development make it obvious that hydrogen storage systems require a major scientific innovation. This breakthrough is almost certainly going to happen as the most feasible substitute to compressed gas and cryogenic hydrogen. An example innovation is hydrogen storage in solid or liquid carriers. The advancement of novel solid state hydrogen storage mediums can indicate a transition toward innovative technologies for hydrogen storage. Novel solid state hydrogen storage options can also have a significant effect on the successful evolution to hydrogen energy systems [51,52]. In transportation applications, a proper solid state storing medium has to be selected to store hydrogen in high weight percentage and volume densities. There are other expectations from the solid state storage medium, such as rapid absorption and desorption of hydrogen at around room temperature and pressure. Preferably, the solid state storage medium should be made by using inexpensive raw materials via energy-efficient processing techniques. The hydrogen storage medium should be stable, resistant to poisoning and trace impurities, and have decent thermal conductivity during absorption and desorption. In addition, the medium should be safe and recyclable when exposed to air, and able to be restored and reused. Obviously, these requirements represent a predominantly challenging list of necessities for the ideal hydrogen-storing medium. Hence, currently, there is no solid state hydrogen storage medium that can meet all of these requirements simultaneously. The basic characteristics and performance of hydrogen-storing materials are strongly affected by the specific nature of the interactions between hydrogen and the storage medium. The interactions between the hydrogen molecules and the storage medium can be summarized as follows:

• • •

Physical attachment of hydrogen molecules on the external or internal surface of the storage medium. Chemical bonding of hydrogen molecules with the storage medium. Chemical hydride formation.

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Globally, there is a considerable amount of effort focusing on a thorough comprehension of the physical and chemical procedures affecting the nature of hydrogen and storage medium interactions. This is especially important when developing novel solid state hydrogen storage mediums to be used in transportation applications. Physical attachment is the least strong of the hydrogen and storage medium interactions listed above. In physical attachment, hydrogen molecules generally form a single layer on the storage medium’s internal or external surface. This means that it is preferable for the hydrogen storage material to have a large surface area. In the literature, a variety of high surface area hydrogen storage materials have been investigated, such as zeolites, metal-organic frameworks (MOFs), and numerous carbon-based structures (e.g., carbon nanotubes). The literature suggests that the highest hydrogen storage capacity reached with physical attachment is 8 wt%. This amount is accomplished in carbon-based structures. Nonetheless, this option requires quite low temperatures ( 19681C) and high pressures (up to 50 bar) for efficient hydrogen storage in carbon. Besides, the preparation process of the carbon-based storage medium is very complex and energy consuming, which requires longer preparation times and decreases overall efficiencies. In many metal hydrides, such as LaNi5H6, FeTiH1.7, and MgNiH4, the maximum hydrogen-storing capacity is about 4 wt%. These conventional metal hydrides are capable of safely and efficiently storing hydrogen inside their crystal structures. First, hydrogen is “sucked” inside the storage medium and then it is discharged during gradual heating of the metal hydride. The volumetric hydrogen storage density of metal hydrides is higher compared to that of cryogenic liquid hydrogen. However, because of the weight of the metal hydrides, they are generally considered as not practical for hydrogen storage systems in transportation applications. For both higher gravimetric and volumetric hydrogen storage densities, light elements of the periodic table should be used. When it comes to solid state hydrogen storage materials, the most promising ones are light elements’ hydrides with ionic covalent bonds, for example, lithium, boron, sodium, magnesium, and aluminum. Hydrogen absorption and desorption in solid state hydrogen storage materials typically require high operating temperatures. Lately, new solid state hydrogen storage materials have been designed for efficient hydrogen charging and discharging in mild operating temperatures and pressures [53]. In addition, innovative and promising solid state hydrogen storage materials have been identified [54]. On the other hand, a lot more fundamental research and development activities are required to comprehend the chemical and physical phenomena affecting the hydrogen charging and discharging cycles. More research is still needed to enhance the hydrogen uptake and release kinetics and properties of solid state hydrogen storage materials to meet the requirements of hydrogen storage systems especially for transportation applications. Hydrogen storage is a commonly used process in many industrial applications. Industrial hydrogen storage operates safely and meets the end-user requirements. In addition, hydrogen could simply be stored at large scales in durable tanks or in underground storage areas. On the other hand, for mobile end-use needs, such as to accomplish a driving range closer to current diesel or gasoline cars, an innovation in onboard hydrogen storage technologies is a serious requirement. Innovative designs for transportation applications can assist in tackling present disadvantages of storage systems. Significant research and development activities are currently taking place in novel storage systems, showing promising results. Conventional storage, such as compressed gas cylinders and liquid tanks, can be made stronger, lighter, and cheaper. Novel methods, including hydrogen absorption using metal hydrides, chemical hydrides, and carbon systems, require further development and evaluation. A summary of major advantages and disadvantages of main hydrogen storage technologies is provided in Table 10. Onboard hydrogen storage technologies for transportation applications influence the design of the entire hydrogen energy system and selection of materials as well as the system infrastructure. In order to enhance overall energy efficiencies, preventable high energy-consuming processes, such as liquefaction and compression, must be avoided. A potential solution is to offer already compressed hydrogen gas directly from hydrogen dispensing points and refueling stations to the end users. Another major challenge during transition to fully developed and efficient hydrogen energy systems is delivering hydrogen to the end-use locations. Large petrochemical plants have been working with hydrogen for a long time and they use pipelines for hydrogen distribution. Because of the efforts of these petrochemical companies, there are already existing long-distance hydrogen pipelines. The longest hydrogen delivery pipeline in Europe is between France and Belgium and it is 400-km long [55]. Another example from Europe is the United Kingdom, which has about 25 km of hydrogen pipeline. Utilizing the existing natural gas infrastructure for hydrogen delivery is often suggested for at least during the transition to a fully developed hydrogen economy. However, hydrogen is a much smaller molecule compared to that of natural gas; therefore, most of the natural gas delivery pipelines cannot protect against hydrogen leakages during hydrogen transmission. Nevertheless, it should be noted that existing mechanically suitable steel and plastic natural gas pipelines can be used to deliver hydrogen at pressures up to 20 bar. System gravimetric and volumetric hydrogen capacities and costs of these hydrogen storage options are presented in Table 11. Above 20 bar, especially above 40 bar, there is a serious risk of hydrogen absorption into the pipe material, which causes hydrogen embrittlement. As a result of this process, most of the metals become brittle when contacted with hydrogen [56]. Another issue is the fact that high carbon-containing plastics are too porous for transmitting hydrogen [57]. For this reason, cylinders and tube trailers are generally utilized for small- to midsize cryogenic liquid and compressed gas phase hydrogen delivery [58].

Hydrogen Energy

Table 10

593

Summary of major benefits and drawbacks of main hydrogen storage options

Hydrogen storage option

Advantages

Disadvantages

Compressed gas

Well understood up to pressures of 200 bar; generally available; can be low cost

Liquid tanks

Well understood technology; good storage density possible

Metal hydrides

Some technology available; solid-state storage; can be made into different shapes; thermal effects can be used in subsystems; very safe Well-known reversible hydride formation reactions, for example, NaBH; compact May allow high storage density; light; may be cheap

Only relatively small amounts of H2 are stored at 200 bar; fuel and storage energy densities at high pressure (700 bar) are comparable to liquid hydrogen, but still lower than for gasoline and diesel; high-pressure storage still under development Very low temperatures require super insulation; cost can be high; some hydrogen is lost through evaporation; energy intensity of liquid hydrogen production; energy stored still not comparable to liquid fossil fuels Heavy; can degrade with time; currently expensive; filling requires cooling circuit

Chemical hydrides Carbon structures

Table 11

Challenges in the logistics of handling of waste products and in infrastructure requirements Not fully understood or developed; early promise remains unfulfilled

System gravimetric and volumetric hydrogen capacities and costs of selected hydrogen storage options

Type of storage

System gravimetric capacity (wt%)

System volumetric capacity (g H2/L)

System cost ($/kWh)

Compressed hydrogen (350 bar) Compressed hydrogen (700 bar) Cryogenic compressed hydrogen (5.6 kg) Cryogenic compressed hydrogen (10.4 kg) Liquid hydrogen (5.6 kg) Liquid hydrogen (10.1 kg) Activated carbon Metal organic framework (MOF-177) Sodium alanate

4.0 4.8 4.0 7.1 5.6 6.5 4.8 4.0 2.3

17.2 25.6 28.0 44.5 23.5 33.0 28.0 34.6 24

16.9 19.2 20.0 8.0 8.0 8.0 15.6 18.0 18.5

Sources: Hull JF, Himeda Y, Wang WH, et al. Reversible hydrogen storage using CO2 and a proton-switchable iridium catalyst in aqueous media under mild temperatures and pressures. Nat Chem 2012;4(5):383–8; Sevilla M, Mokaya R. Energy storage applications of activated carbons: supercapacitors and hydrogen storage. Energy Environ Sci 2014;7 (4):1250–80; Ley MB, Jepsen LH, Lee YS, et al. Complex hydrides for hydrogen storage – new perspectives. Mater Today 2014;17(3):122–8; Yang SJ, Kim T, Im JH, et al. MOFderived hierarchically porous carbon with exceptional porosity and hydrogen storage capacity. Chem Mater 2012;24(3):464; Yan Y, Yang S, Blake AJ, Schroder M. Studies on metalorganic frameworks of Cu (II) with isophthalate linkers for hydrogen Storage. Acc Chem Res 2013;47(2):296–307; Dalebrook AF, Gan W, Grasemann M, Moret S, Laurenczy G. Hydrogen storage: beyond conventional methods. Chem Commun 2013;49(78):8735–51; Jepsen LH, Ley MB, Lee YS, et al. Boron–nitrogen based hydrides and reactive composites for hydrogen storage. Mater Today 2014;17(3):129–35.

The extensive utilization of hydrogen as an energy carrier depends considerably on the convenience of effective, clean, reliable, and affordable hydrogen utilization technologies including hydrogen to electricity and/or heat conversion. The synergistic complementarity of hydrogen and electricity signifies one of the most attractive paths to a truly sustainable future. As an example, fuel cells possibly offer the one of the most effective ways to convert hydrogen and other hydrogen-based fuels into electricity. A fuel cell is an apparatus similar to a continuously charging/recharging battery. A fuel cell produces electricity via the electrochemical reaction between hydrogen and oxygen (the oxygen is generally supplied as fresh air to fuel cells). The main difference between batteries and fuel cells is the fact that batteries store electricity and fuel cells generate electricity continuously as long as there is continuous hydrogen and oxygen supply. There are numerous types of fuel cells, which operate with different fuels. These different fuel cells can be used for different end-use needs. However, almost all fuel cells have the common basic design. The common basic design of fuel cells consists of two electrodes as anode and cathode, which are separated by an electrolyte (solid or liquid) or membrane. Hydrogen (or a hydrogen-based fuel) and oxygen are supplied to the anode and cathode compartments of the fuel cell. Then, the catalyst-supported electrochemical reaction between hydrogen and oxygen occur at the electrodes. The electrolyte or membrane allows the transportation of ions amid the electrodes and in the meantime, surplus electrons move away via an external circuit to harvest the product as electricity. Fuel cells are not subject to the fundamental restrictions of the Carnot cycle; therefore, they can convert hydrogen to electricity at efficiencies higher than the double amount of ICEs. In transportation applications, hydrogen fuel cell vehicles work at efficiencies up to 65%. This amount is 25% for current car engines powered by fossil fuel-based ICEs. If the heat released during fuel cell operation is recovered in CHP systems, overall efficiencies over 85% could easily be attained [59].

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Table 12

Comparison of hydrogen-fueled internal combustion vehicles and fuel cell vehicles

Vehicle type

Advantages

Hydrogen internal combustion engine vehicle (HICEV)

• • • •

Well understood technology Existing engine hardware/technology Thermal management Better power density

• • • •

Hydrogen fuel cell vehicle

•

Substantial fuel economy benefit over H2 internal combustion engine (ICE) Zero tailpipe emissions Quiet operation Availability of power for electric systems and auxiliary units

• • • • • •

• • •

Disadvantages

•

NOx control and after treatment Lower efficiency Backfiring and safety issues Engine modification and durability of operation Vehicle weight and cost Thermal and power management Higher startup time Operation in hot and cold climates Precious metal supply and cost Servicing cost, complexity, and infrastructure System life

Another significant advantage of fuel cells, in contrast to ICEs or turbines, is that fuel cells establish high operating efficiencies regardless of their product power range. Since fuel cells have no scale issues, they are ideal for a wide range of end-use options. Some examples are cell phone batteries, cars, buses, ferries, planes, large-scale central or small-scale distributed power generation, and other stationary applications. Fuel cells are nowadays evolving as one of the most important technologies to substitute highly polluting ICEs in transportation, centralized and decentralized, small- and large-scale energy systems. During operation, hydrogen-based fuel cells discharge water only and have practically no other pollutant emissions, such as carbon dioxide, nitrogen oxides, etc. Fuel cells can work at much lower operating temperatures compared to ICEs. In theory, hydrogen-based fuel cell transportation applications offer a pathway to real zero-life cycle emissions on the condition that the hydrogen must be produced from renewable energy sources with zero emissions. In addition, hydrogen-based fuel cell transportation applications are progressively considered as promising alternatives to other zero-emission options (e.g., electric battery vehicles) since hydrogen’s chemical energy density is considerably higher than the energy density of electric batteries [60]. In addition, hydrogen fuel cells can simultaneously offer a lot longer operating lifetimes compared to electric batteries. Fuel cells also have similar high specific energy outputs compared to conventional ICEs. Table 12 shows the comparison of hydrogen-fueled internal combustion-based and fuel cell-based vehicles. The ICEs have welldeveloped structures and use established technologies, as well as large infrastructures and production units. In the literature, hydrogen-fueled ICEs are seen as strong participants in the transportation applications and they expected to gain significant importance and value in the market. In addition to hydrogen, any fuel that is rich in hydrogen content could be used in fuel cells. Of course, different fuels would require different types of fuel cells. Some of these fuel cells can employ an external or internal fuel reformer. However, it should be noted that utilizing traditional fossil fuel-based resources in fuel cells unavoidably causes GHG (especially CO2) emissions. Since fuel cells have a lot higher efficiencies compared to those of ICEs, they can produce more energy from the same amount of fossil fuel with less emissions compared to the ICEs. Consequently, even fossil fuel-based fuel cells do have the prospect to produce energy in a lot more effective, clean, affordable, reliable, and quiet manner. Use of fuel cells instead of ICEs could significantly reduce the GHG emissions and local pollution, while keeping efficiencies higher and operation costs lower. Fuel cells are very promising when it comes to their ability to substitute for the significant parts of the traditional energy systems. Fuel cells also provide very promising technological solutions to deliver energy with significantly high efficiencies, which are considerably higher than current fossil fuel-fed ICEs. On the other hand, a number of main technical difficulties have to be overcome in order to make fuel cells successfully and efficiently replace traditional energy systems. Some major technical and scientific difficulties related to the use of fuel cells in hydrogen energy systems are manufacturing and operating costs, durability, reliability, and availability. These challenges require rigorous research and development to improve, design, build, and test novel materials to support commercial sustainability of fuel cells for stationary, mobile, small, and large-scale applications. Currently, hydrogen-based fuel cell vehicles are the focus of concentrated global research and development activities. However, fuel cells are not anticipated to hit the global mass markets before 2020, or maybe even later. Safety issues are expected to cause a possible obstacle during the initial implementation of hydrogen energy systems. In spite of its commonly accepted negative image, hydrogen is not any less safe compared to other fuels. As a chemical feedstock used in the industry, hydrogen has an amazingly positive safety history throughout numerous decades of utilization in industrial applications. Hydrogen does not have any more safety risks than traditional fossil fuels, such as petroleum or natural gas. It should be noted that, similar to other existing fuels, hydrogen should be utilized safely with proper system design, operation, and handling. In addition to its flammability, there are other safety concerns related to hydrogen use for various applications, such as considerably high-pressure requirements of compressed gas storage tanks and low-temperature requirements of cryogenic hydrogen storage options. Compared to compressed gas and cryogenic liquid phase hydrogen storage options, many solid state hydrogen storage mediums, such as metal hydrides, are characteristically a lot safer.

Hydrogen Energy

595

When assessing the safety of hydrogen energy systems, it should be remembered that hydrogen safety requires more than a scientific and technical approach. There are also some key economical, psychological, and sociological issues that might slow down the transition to successful hydrogen energy systems. In order for hydrogen energy systems to gain public acceptance, hydrogen has to be considered as safe during production, delivery, handling, and end use. With no doubt, end users have multiple worries regarding the safety and reliability of hydrogen and hydrogen energy systems, such as fuel cells, hydrogen production, storage, and delivery technologies, etc. However, it should be noted that the consumers had similar concerns about other devices that are currently being used on a daily basis before these devices had been introduced to the market. In order to gain public acceptance for industrial, residential, transportation, stationary, portable, small- and large-scale applications; customers should interact directly with hydrogen and hydrogen energy systems on a daily basis. Developing universally acknowledged codes and principles is another important requirement to promote public acceptance of hydrogen and hydrogen energy systems. Facilitating a successful transition to hydrogen energy systems for a sustainable future could be accomplished via the collaboration of educational and research institutions, private and government laboratories, universities, communities, and politicians to promote innovative projects for design, development, testing, marketing, and promotion of hydrogen as an alternative fuel [61]. There is still a lot more to investigate and understand when it comes to the environmental impact emissions related to increasing hydrogen use. The extensive utilization of hydrogen could certainly have some negative environmental effects as a result of the increased anthropogenic emissions of hydrogen energy systems [62]. In the literature, it is very well understood that hydrogen contributes to stratospheric chemical cycles of water vapor and several other GHG. A significant escalation in the concentrations of GHG could seriously impact the balance and equilibrium concentrations of these components in the stratosphere. Further precise modeling of the chemical processes affecting the stratosphere, in addition to enhanced comprehension of all other factors impacting the environment, are needed. For instance, hydrogen absorption in the ground and its effects on the soil habitat should be investigated and assessed in terms of possible negative impacts of hydrogen energy systems. Despite the promising results presented in the literature and tremendous research and development activities, still, at least 10–20 more years are needed to make hydrogen extensively accepted and utilized as an energy carrier. In addition, crucial actions need to be taken in order to comprehend, predict, and eliminate the potential negative environmental impacts of hydrogen energy systems.

1.13.8

Hydrogen Energy Market

In order to develop a fully functional hydrogen energy system, first, potential hydrogen energy markets for all related technologies should be identified. This task is not always very easy, specifically because of the fact that most of the technologies used in hydrogen energy systems are still in their early stages of market introduction. Nevertheless, hydrogen’s resourcefulness and viability in many applications, such as in fuel cells, show that hydrogen is safe and appropriate in a broad range of end-use applications. In addition, the versatility of hydrogen offers a foundation for the valuation of the hydrogen energy market requirements. Hydrogen energy markets serve a broad range of end-use applications from fuel cell markets for portable consumer electronics to micro-CHP systems for heat and power production and transportation. The American Institute of Chemical Engineers (AIChE) [63] has presented that the main areas for future hydrogen energy markets are expected to mainly depend on the following four elements:

• • • •

Current and future costs of hydrogen energy systems. Advancement rate of various hydrogen energy system technologies. Current and future costs of alternative energy systems. Current and future rules and regulations on GHG emissions.

Hydrogen has the capacity to grow into a very essential fuel for the transportation industry. On the other hand, in order to have a stable and long-term hydrogen energy market capable of meeting the demands of the transportation industry, numerous technological elements influencing the vehicle and fuel costs are needed to be addressed first. Fuel cell electric vehicles’ (FCEVs) costs are influenced by the costs of onboard fuel cell components, such as the onboard hydrogen storage system, the fuel cell stack, the auxiliary electric motors, etc. Even though the fuel cells’ costs have decreased considerably especially during the last couple of years, their economic performance also depends on the economic performance of the existing or future alternative solutions including battery electric vehicles (BEVs), which is a significant driver for hydrogen energy markets. If BEVs operate efficiently at low costs, then the end users will start preferring to purchase BEVs over hydrogen-powered alternatives. As a result, the incentives supporting the transition toward hydrogen-fueled vehicles are expected to diminish. Present research and development studies in the literature suggest that BEVs are not expected to reach the levels of energy densities for adequate driving ranges at reasonable weights and costs. Crucial elements and drivers of a transition to a successful hydrogen energy market are presented in Fig. 10 along with some suggestions for interrelated research activities to focus on related to hydrogen energy systems. Along with the economic, environmental, and energetic performance of the alternative technologies, there are sociological (e.g., behavioral) uncertainties about the widespread utilization of hydrogen-fueled vehicles. An example of these uncertainties is the

596

Hydrogen Energy

Interrelated research should be focused on: • Cost reduction. • Materials choice and utilization. • Design and manufacturing. • System integration. • Balance of system components. • Fuels, fuel quality and fuel processing. • Hydrogen production, distribution and storage. • System performance (durability, efficiency). • Testing, evaluation, characterization, product. • Standardization. • Socio-economic research.

Market mechanism

Regulatory system

Society

Hydrogen energy market Fig. 10 Crucial elements, drivers, and interrelated research activity suggestions for a transition to a successful hydrogen energy market.

consumer acceptance of new technologies. For instance, when it comes to BEVs, there are a couple of important behavioral questions to ask, such as whether or not the vehicle owners would accept low-driving vehicles, how often vehicle owners would be willing to charge their vehicles, etc. Driving range is especially a critical issue when developing alternative transportation vehicles. With the current available technologies, ICE-powered vehicles offer durable, reliable, affordable, safe, and long-range driving to drivers that hydrogen-fueled vehicles or BEVs cannot compete with. Another example of vehicle charging concerns is related to BEVs; in the long-term, it is expected that severe problems will surface related to BEV charging and its impacts on the local, national, and global electricity grid. The reason for these concerns is the fact that most owners are expected to charge their vehicles during peak consumption periods, which generally means after business hours, which end around 6 p.m. or so. In addition, currently, there are not many studies on potential BEV owners’ charging preferences and behaviors. The University of Birmingham Fuel Cell Group has conducted different simulations and modeling studies on BEV drivers in England and so far, they have concluded that the majority of owners and drivers prefer charging their vehicles during peak times in contrast with the recommended use during off-peak times [64]. An additional and much more important element that affects the hydrogen energy market in the transportation sector is the GHG emissions reduction that could be achieved with hydrogen compared to other alternative fuel options with low emissions, such as biobased fuels. In the transportation sector, biobased fuels can potentially become the most cost-effective, clean, reliable, and efficient alternative to traditional fossil fuel-based transportation fuels, which poses a threat to hydrogen energy market expansion. The reason for the potential success of biobased fuels is their ease of production, delivery, and end use. In addition, biobased fuels may not necessitate a drastic infrastructure renovation. As mentioned earlier, biobased fuels have several advantages as transportation fuels. However, in spite of their substantial potentials, biobased fuel sources cause a lot of polemics. An important concern about biobased fuels is related to the conservation of agricultural lands. Unless biobased fuels are derived from industrial, agricultural, or municipal waste, there will always be a “food versus fuel” debate on biobased sources. In addition, in order to be considered as truly renewable, the biobased fuels should be replenished at a higher (or equal) rate compared to their rate of consumption. Furthermore, a thorough well-to-wheel analysis should be conducted to evaluate the net GHG emissions related to biobased fuel use. Over and above the issues highlighted here so far, there are some political aspects and policy-related issues that significantly affect the expansion of the hydrogen energy market, especially hydrogen in the transportation sector. There needs to be specific consumer-driven demand for the successful growth of the hydrogen energy market and extensive use of hydrogen as a transportation fuel. Until now, there has been no significant demand from key consumer groups on the use of hydrogen as a transportation fuel [65]. Transition to hydrogen use in the current transportation industry requires substantial policy changes. This is a unique situation because there have been no major energy system shifts in history with such policy change requirements. In the late 19th century, the main reason for the evolution from horse-driven transportation to ICE-driven vehicles was the demand coming from vehicle users to be able to travel longer distances [66]. Since there has been no major consumer demand for hydrogen-powered vehicles, the responsibility for a successful transition to a hydrogen economy is on local and state-level

Hydrogen Energy

Table 13

597

Energy consumption of road transportation comparison of hydrogen with respect to propane and gasoline

Parameter

H2 (gas)

H2 (liquid)

Propane

Gasoline

Operating pressure (MPa) Weight to customer (kg) Weight from customer (kg) Delivered weight (kg) Lower heating value (LHV) of delivered fuel (MJ/kg) LHV of energy per truck (GJ) Diesel consumed (kg) Diesel LHV energy (GJ) Energy consumed relative to gasoline (dimensionless)

20 40,000 39,600 400 120 48 79.6 3.38 35.77

0.1 30,000 27,000 2,100 120 252 57.9 2.46 4.96

0.5 40,000 20,000 20,000 46.3 926 60 2.55 1.40

0.1 40,000 14,000 26,000 44.8 1,164.8 54 2.30 1.00

Source: Wang D, Jia W, Olsen SC, et al. Impact of a future H2-based road transportation sector on the composition and chemistry of the atmosphere – part 1: tropospheric composition and air quality. Atmos Chem Phys 2013;13(13):6117–37; Wang D, Jia W, Olsen SC, et al. Impact of a future H2-based road transportation sector on the composition and chemistry of the atmosphere – part 2: stratospheric ozone. Atmos Chem Phys 2013;13(13):6139–50; Bahn O, Marcy M, Vaillancourt K, Waaub JP. Electrification of the Canadian road transportation sector: a 2050 outlook with TIMES-Canada. Energy Policy 2013;62:593–606; Shrivastava RK, Neeta S, Geeta G. Air pollution due to road transportation in India: a review on assessment and reduction strategies. J Environ Res Dev 2013;8(1):69; Vanhulsel M, Degraeuwe B, Beckx C, Vankerkom J, De Vlieger I. Road transportation emission inventories and projections – case study of Belgium: methodology and pitfalls. Transp Res D Trans Environ 2014;27:41–5; Najjar YS. Hydrogen safety: the road toward green technology. Int J Hydrog Energy 2013;38(25):10716–728.

governments, representatives from various industries and institutions, and hydrogen energy system supporters to accelerate the transition to a fully developed hydrogen energy market by leading:

• • •

Behavioral transition: for hydrogen to be accepted by all end users. Technological demonstrations: to prove that the hydrogen energy market is ready. Competitive assessments: demonstrate the advantages of hydrogen compared to other existing alternatives.

There have been many obstacles considered during the transition to a successfully developed hydrogen energy market. Even if all these challenges related to hydrogen use as a transportation fuel are addressed, there will be additional requirements for an effective market introduction, such as investments in refueling infrastructure and novel vehicle technologies, incentives to purchase hydrogen-fueled vehicles to keep them as affordable alternatives for consumers before mass production begins, etc. [67]. In order to achieve a successful transition to hydrogen as a transport fuel, governments have to play a prominent role by maintaining and augmenting incentives that can promote the uptake and mass market appeal of the next generation of zero-emission vehicles in an effort to decarbonize the road transport system. Table 13 presents the energy consumption comparison of transportation applications powered by compressed gas and cryogenic liquid hydrogen with respect to propane and gasoline. Here, it can be seen that in gas phase hydrogen, there is a significant amount of energy requirement in order to compress hydrogen to desired operating pressures. The vehicle selected here for comparative evaluation purposes is powered by diesel-fueled compression ignition engine. There are many novel hydrogen energy markets from stationary to portable applications, and in small and large scale. Some examples of these markets are midscale stationary fuel cell-powered energy systems with capacities from 200 to 1000 kW. Hydrogen-powered CHP and combined cooling, heat, and power (CCHP) facilities can be utilized for district power generation and heating purposes. Hydrogen energy systems can also potentially be used for off-grid power generation in micro- and ultimately macroscales. The Energy Savings Trust [68] has proposed that microgeneration products (e.g., fuel cell-powered CHP units) have the potential to supply about 30%–40% of the United Kingdom’s energy demand, which would significantly contribute to the United Kingdom reaching its 80% carbon emissions reduction target by 2050. Early fuel cell vehicle research is very promising and the successful demonstrations have created innovative hydrogen energy markets for the transportation industry. Some examples are backup power units for existing vehicles, buses, forklifts, LDVs, scooters, etc. Pike research [69] has reported that industrial forklifts could be the major contributor to hydrogen fuel demand in the United Kingdom by 2020, since most industries aim to find novel, affordable, energy-efficient, clean, and reliable methods to limit their costs, as mentioned earlier. In the United States alone, more than 8200 fuel cell components and pieces of fuel cell handling equipment have been manufactured since 2009. Taking advantage of the fuel cells’ durability, reliability, shorter refueling times, and less frequent refueling demands, fuel cell forklifts have shown reasonable payback periods and better cost efficiency with respect to the batterypowered forklifts currently utilized in indoor warehouses [70]. Stationary fuel cell applications can provide small- and large-scale power from the kilowatt to even megawatt scale and these systems are currently utilized to supply power to isolated locations that have no access to the grid or for backup purposes. Fuel cells can also be utilized to supply the power demands of a variety of telecommunication applications, such as data centers, networking equipment, telecommunication towers, etc. in a robust and reliable manner. In many applications, such as the ones mentioned here so far, fuel cells frequently substitute for diesel generators. This significantly reduces the emissions of the power generation systems and provides extended lifetimes along with fewer maintenance

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requirements. For every type of end-user need, there is a fuel cell type available in the hydrogen energy market. For example, portable and/or smaller energy systems with output electricity capacities up to several kilowatts do generally use proton exchange membrane fuel cells (PEMFCs). Comparatively larger (and generally more stationary) energy systems with output electricity capacities up to the megawatt scale generally utilize more stationary high-temperature fuel cells, for example, molten carbonate (MC) or solid oxide (SO) fuel cells. There are many other fuel cell systems and some of them use natural gas, while others usually use hydrogen as the primary fuel. However, there are other liquid fuels that can be used in fuel cells, for instance, diesel, ethanol, kerosene, liquefied petroleum gas (LPG), methanol, etc. There are also some gaseous fuels used in fuel cells, including biogas, butane, coal syngas, propane, etc. Stationary fuel cells are generally more commonly accepted by the public compared to portable fuel cells. For example, in 2013, stationary fuel cells contributed to about 90% of all new fuel cell systems in the United States [71]. The industry is currently very interested in expanding the hydrogen energy market as a result of diminishing fossil fuel resources and the requirements to reduce (if possible, eliminate) GHG emissions. A very possible method to incorporate hydrogen into the current energy market could be achieved via mixing it into the existing natural gas delivery systems and distributing it using the existing natural gas grid. The International Gas Union (IGU) [72] has indicated that substituting 10 vol% of a natural gas supply with hydrogen cuts CO2 emissions by about 3%. Another study conducted by NATURALHY [73] has presented that around 15% CO2 emissions cutbacks can be attained with mixing up to 50 vol% hydrogen gas into the existing natural gas grid. The CO2 emissions reductions are limited when mixing hydrogen with natural gas because of the low density and low energy density of hydrogen. It is essential to note that many governments do not permit 50% hydrogen and 50% natural gas mixture by volume. This is limited to 25 vol% on a Wobbe number basis. In the meantime, the limit on hydrogen and natural gas mixtures is currently stated as 0.1 M% in many codes and standards. The Wobbe is a measure of the interchangeability of fuel gases when introduced into a heater via a burner with a fixed differential pressure. Two gases with the same Wobbe Index will deliver the same amount of heat into a combustion process per unit of time regardless of the composition. Wobbe number is calculated as follows:

Wobbe index ¼

Heating value Specific gravity

ð5Þ

When deciding on whether or not it is beneficial to add increasing amounts of hydrogen into the existing natural gas grid, all potential effects should be considered thoroughly, including the effects on:

• • • •

Net and overall energy densities: increasing the amount of hydrogen in the mixture reduces its energy density. Wobbe number: increasing the amount of hydrogen in the mixture (up to around 70 vol%) reduces its Wobbe number slightly (it should be noted that this might not be regulated in some countries). Ignition characteristics: increasing the amount of hydrogen in the mixture reduces its “knock tendency.” Burning velocity: increasing the amount of hydrogen in the mixture (up to around 30 vol%) increases its burning velocity.

It should be noted that there are possible risks related to mixing hydrogen and natural gas supplies. For example, there are reliability risks of the grid network and fuel processing sites that might seriously affect the operators. Another impact might be the performance decrease of household appliances. Frequency of explosions and the risk of fire hazard might increase as well. Increasing hydrogen amounts in the existing natural gas pipelines might increase NOx emissions. These are some of the risks associated with introducing (or increasing the amounts of) hydrogen in the existing natural gas grid. And, all the risks mentioned earlier should be comparatively and thoroughly assessed by considering the reductions in carbon emissions that can be achieved by mixing hydrogen and natural gas instead of using natural gas alone. In addition, natural gas can be utilized for distributed heat and power supply systems via stationary CHP systems together with hydrogen. The United Kingdom Hydrogen and Fuel Cell Industry (UKHFCA) [74] has shown that by using fuel cell micro-CHP technologies to replace today’s traditional boilers, about 2.5 t equivalent of CO2 emissions can be reduced. This amount is equal to about 40%–50% of a typical European household’s annual carbon footprint. This clustering of hydrogen infrastructure for a successful hydrogen energy market is being pursued by many researchers, scientists, politicians, and people from various industries. One common goal is to develop a clustered assembly of hydrogen fueling stations in order to be served during the start of FCEV utilization. For example, a recent study convened by the US Department of Energy (DoE) identified Los Angeles and New York City as the best early markets for hydrogen FCEVs [75]. Once fuel cell vehicles are successfully deployed in big urban regions, FCEVs could then be distributed gradually to smaller cities and eventually to more rural areas. For instance, FCEVs are first planned to be used in 20 key metropolitan regions in the United States. Then, the hydrogen infrastructure is planned to be expanded to smaller cities, interstate regions, and ultimately all the way through the United States. The fundamental action steps toward the development of an effective hydrogen fueling infrastructure are presented in Fig. 11.

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Match supply and demand

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Connect early markets to develop a hydrogen energy system network

Early hydrogen station deployment Offer incentives for early adaptors Target key urban areas as early markets

Fig. 11 Key requirements for successful hydrogen energy market deployment. Modified from Chu S, Majumdar A. Opportunities and challenges for a sustainable energy future. Nature 2012;488(7411):294–303.

1.13.9

Future Directions

The future of hydrogen energy looks bright since the future requires carbon-free energy solutions. In this regard, hydrogen becomes a unique solution to help achieve hydrogenization (which means that hydrogen energy will be the main energy solution for implementation) and a carbon-free society. Resilient and innovative academic, government, and industry collaborations are required to investigate and invest in the possible hydrogen energy systems for a more sustainable future. This partnership needs innovative research and development activities from academia, strong leadership and legislative support from governments, and substantial, longstanding global investment from both public and private industries. Public acceptance of hydrogen energy systems could be stimulated by effective strategies, which can address the external supply costs and benefits coming from energy security, increased quality of air, and fewer global climate change risks. These strategies have to be reliable and they must deliver a well-defined guide to all involved industries and end users. A public exchange of ideas should be started to kindle an educated and continuing conversation on how societies evaluate cleaner, reliable, affordable, and diverse hydrogen energy systems. The common global utilization of hydrogen energy systems could potentially influence all aspects of the existing and future global energy systems, from the very beginning of the energy generation all the way to the end use and waste disposal. The specific constituents of a particular hydrogen energy system can be listed as generation, distribution, storage, conversion, and end-use applications. All these components are directly interconnected and mutually dependent. The design, development, and application of hydrogen energy systems have to be evaluated at the complete overall system level. The major components of hydrogen energy systems can overall be listed as follows:

•

Generation: partnership from academia, governments, and industries is needed to identify, design, develop, build, and test innovative hydrogen production systems. Innovation in hydrogen production is needed to reduce system costs, enhance overall efficiencies, and minimize the negative environmental impacts. Novel hydrogen production methods are required to improve large- and small-scale both centralized and distributed hydrogen energy systems. Research and development should be accelerated to improve existing hydrogen production methods, for example, steam methane reforming, coal/biomass gasification, and water electrolysis. In addition, research and development activities should keep focusing on innovative hydrogen production methods, for instance photonic based techniques, novel biological systems, etc. Most recent studies on hydrogen production show the tendency toward direct hydrogen production from renewable energy sources without the need of an intermediate electricity generation process. Photoelectrochemical and photobiological hydrogen production with novel materials and approaches, such as thin films, dye-sensitized materials, advanced membranes, and engineered microorganisms show great potential in clean hydrogen production. There have been numerous patents and studies regarding these innovative

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approaches indicating that currently fossil fuel-based hydrogen production methods are to be substituted by renewable energybased alternatives. Distribution: existing hydrogen delivery infrastructure should be improved and expanded to sustain the growth in hydrogen energy systems. Preliminary research and development activities should aim to design and develop enhanced and improved components for present distribution systems. Some of these components are sensors, pipe materials, compressors, highpressure support mechanisms, insulators, etc. Affordability, reliability, and safety-related challenges could possibly affect the hydrogen distribution systems from both design and development perspectives. Another important decision criterion for hydrogen distribution is deciding between small- or large-scale (i.e., centralized or distributed) hydrogen production methods. In order to tackle the so-called chicken and egg problem of demand and supply issues, existing and future hydrogen distribution components for both centralized and distributed systems should be tested carefully in combination with all possible end-use applications (e.g., fuel cells, refueling stations, and power generation systems). Recently, academia, governments, and industry have been investigating methods to distribute hydrogen in the most cost-efficient manner, which is by slight modifications of the existing natural gas pipelines. Also, lighter and more stable materials have been developed to build a hydrogen network with zero or minimum hydrogen gas loss. Small-scale and distributed hydrogen production with novel approaches, such as photoelectrochemical hydrogen production, have been investigated in the recent literature to minimize hydrogen distribution costs, losses, and temperature and pressure requirements of hydrogen energy systems. Storage: hydrogen storage is a crucial challenge during the transition to hydrogen energy systems. Currently, none of the existing hydrogen storage systems meet all of the requirements set by governments, industries, and end users. Coordination of academia, governments, and industries on research and development of novel hydrogen storage methods and advanced storage materials is required to reduce system costs, enhance overall efficiencies, and reduce any negative environmental impacts. Research and development activities are needed to improve the commercially available hydrogen storage methods. These methods include compressed gas and cryogenic liquid phase hydrogen storage. Innovative hydrogen storage methods involve innovative materials, for example, lightweight metal hydrides and carbon nanotubes. In the recent literature, novel approaches to chemical and physical hydrogen storage mediums have shown great potential. Light metal hydrides; complex “hydridic” hydrides, borohydrides, and alanates (such as [BH4] and [AlH4] ); complex “protonic hydrides,” nitrides, imides, and amides; other multicomponent systems, such as amide-hydride-borohydrides (simple and complex binary component systems and ternary composite systems); and ammonia-borane and amido-borane are the novel chemical hydrogen storage mediums in the literature. Novel approaches in design and development of MOFs have shown great potential in physical hydrogen storage systems. These diverse examples of very different materials show that there is still plenty of room for further invention and discovery in the bid to produce new hydrogen storage solutions. Conversion: hydrogen can be transformed into other valuable energy forms, such as electricity and thermal energy. Existing hydrogen energy conversion methods are fuel cells, heat exchangers, reciprocating engines, turbines, etc. Research and development activities are required to increase the conversion systems’ capacities and reduce their operating costs. In addition, higher efficiencies should be reached, while keeping the negative environmental impact at a minimum level. Research and development activities should also find new ways to develop cost-effective business models for stationary and distributed conversion systems and optimize system designs for mobile and stationary end use. Research is currently focusing on the enhancement of essential know-how of innovative materials, electrochemistry, and fuel cell kinetics, and discovering the important characteristics of combustion-based hydrogen conversion systems. The key to the success of hydrogen energy systems is the diversity, availability, and reliability of hydrogen energy conversion systems. The novel approaches include design, development, and testing new ways to convert hydrogen into many forms of energy, such as electricity, heating, and cooling, and other chemicals, such as ammonia. The wide variety of hydrogen energy conversion systems being developed in the literature via advanced membrane technologies, cheaper and more efficient catalysts, and integrated energy systems enhance the end-use applications, which could potentially enable wide public acceptance of hydrogen energy systems. End use: eventually, hydrogen energy systems are developed for consumers to use hydrogen for their transportation, electricity, and heating and cooling needs. Issues related to system cost, efficiencies, and environmental impacts are required to be tackled along with public awareness and acceptance of hydrogen energy systems. Major requirements of end users can be summarized as affordability, availability, convenience, reliability, safety, and less harmful health and environmental impact. Research and development activities should be accelerated to understand end-user preferences and build these preferences around hydrogen energy systems. Prospects should be recognized to utilize hydrogen energy systems in stationary and distributed power generation facilities including combined heating and power, and for transportation applications. Accommodating energy, financial, and environmental strategies should be employed from both local and global perspectives. Fuel cells are considered a key technology in a future economy based on hydrogen, as they are able to convert this energy carrier in a very efficient way. Stationary fuel cell systems, with a capacity ranging from a few kilowatts to some megawatts, can be used for backup power, distributed power generation, and cogeneration or for portable generators. The current literature and the estimations of future research activities show that most advanced hydrogen energy end-use chains are low-temperature and -pressure processes providing multiple outputs to the end user. Fuel cell and ICEs are developed with novel catalysts and membranes to lower and eliminate their emissions, reduce the operating costs, and enhance product lifetimes. Training and outreach: hydrogen energy systems are generally considered as complex. Furthermore, people do not have adequate information related to how hydrogen energy systems affect the economy, environment, public health, safety, and energy security. Eventually, end-user choices are expected to impact how energy markets, technological advancements, and

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Rain water

ic olta to-v Pho panel

ctro -ele anel o t p Pho ical m che

Hydrogen fuel cell Hydrogen distributor

Pump Hydrogen tank

Fig. 12 The vision of future hydrogen energy systems. Reproduced from International Association for Hydrogen Energy. Available from: http:// www.iahe.org/; 2017 [accessed 27.03.17].

•

public policies evolve. Educating the public via effective training materials and techniques, such as science programs and public outreach programs, can greatly assist gaining public awareness and acceptance for hydrogen energy systems. Codes and standards: locally and globally consistent rules and regulations for the planning, development, building, testing, and employment of hydrogen energy systems are required for the wide use of hydrogen products and services. Proper and consistent codes and standards can considerably accelerate many hydrogen energy system components to reach market level from their current laboratory-scale versions. The collaboration of academia, governments, and industry could help the development and application of rules and regulations. These codes and standards have to cover all local and global elements of energy systems and be internationally recognized with global public acceptance.

Fig. 12 presents the vision for hydrogen energy systems starting from production all the way to end use. It can be said that the future of hydrogen energy systems is more likely to be based on cleaner energy and material resources (such as sun and water). It should also be noted that future hydrogen energy systems are expected to be capable of providing not only electricity, but many other valuable end-use services, such as heating, cooling, clean water, etc. Hydrogen energy systems and their applications represent a great potentially long-term solution to today’s energy crisis with a vast number of advantages for almost every country in the world. An organized and motivated attempt is required to combine the academic, governmental, and industrial resources in order to evaluate the true costs and benefits of hydrogen energy systems. Subsequent steps are expected to consist of the development of comprehensive research and development strategies. In order to successfully switch to hydrogen energy systems, substantial dedication is needed from all existing resources including financial, material, human power, and services. In a little more detail:

•

•

Science and technology: there are many issues that need to be addressed when switching to hydrogen energy systems, and these are related to the basics of materials sciences, electrochemistry, biology, planning, design, and manufacturing. Governments, with support from local and global communities and scholars in universities and national laboratories, have a significant responsibility as scientific frontlines. Developments in hydrogen generation, storage, delivery, and end-use applications can change the calculation of hydrogen energy systems’ costs and benefits significantly. More focused attention should be on financially, environmentally, and thermodynamically promising alternatives. Unproductive research areas should no longer be invested in, in terms of money, human power, and time resources. Distribution of results and knowledge sharing between academia, governments, and industries should be accelerated and kept in a more efficient platform. Technological improvement: an improved technical coordination between industries, governments, universities, and private and public laboratories is required to enhance technological development programs in the hydrogen energy systems field. More detailed technological roadmaps are required to be designed to bring funding from governmental and industrial institutions to practice specific and technological opportunities, especially in the fields of hydrogen production, distribution, storage, and

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end-use applications. Governments need to more directly organize activities among different organizations, universities, research institutions, and laboratories. Product testing: urgent collaboration between academia, governments, and industries is required with the intention of implementing various innovative hydrogen energy systems. These innovative hydrogen energy systems should meet the needs of stationary and portable applications both in small- and large-scale. This collaboration is very important in order to estimate the prospects of hydrogen energy systems and their global public acceptance. Technological development and product testing via pilot-scale systems could assist in recognizing any potential problems before mass-scale operation. Effective product testing also helps in compiling experiential data to efficiently assess the costs and profits of hydrogen energy systems during the transition step. Current endeavors to employ all components of hydrogen energy systems (such as refueling stations, power generation units, transportation vehicles, etc.) should be simulated in a range of different geographical and climatic situations. The product testing results should be appropriately discussed, recorded, and widely distributed. Policy and regulations: policies related to economics, energy and the environment, utility regulations, industrial procedures, and many other codes and standards are significant foundations of the functional infrastructure required to design, develop, build, and test hydrogen energy systems. Public training and education efforts can increase public acceptance and awareness of how to accelerate the development of hydrogen energy systems. Existing policies should be analyzed in order to pinpoint redundant obstacles. In addition, business practices should be analyzed in order to detect cost-effective methods to develop hydrogen energy systems (including distributed energy systems, CHP systems, etc.). Research and development activities should involve all participating countries to promote better coordination and reliability with respect to hydrogen energy systems.

1.13.10

Concluding Remarks

The fundamental objective of this chapter is to understand the role of hydrogen in future energy systems, its potential applications, and possible solutions to some challenges related to the common and wide utilization of hydrogen energy systems. Another goal of this chapter is to help accelerate the transition to hydrogen energy systems and possibly encourage more investments in the design, development, building, and testing of novel hydrogen energy systems. The historical transition of fuel utilization shows the tendency toward hydrogen energy systems. As the traditional woodburning processes were replaced by coal combustion during the Industrial Revolution, and coal was substituted gradually by lighter fossil fuels, such as oil and eventually natural gas, the hydrogen content of fuels kept increasing significantly. The ultimate goal is to eliminate all carbon content in fuels to minimize GHG emissions. Hydrogen, as an energy carrier and a fuel, is capable of supporting existing and future energy systems in an environmentally benign way with its high GF. Currently, more than 90% of global hydrogen production is based on the energy and material input from fossil fuels. The ultimate goal is to reduce this percentage to minimal levels to eliminate or lower fossil fuel-related GHG emissions. Ammonia production is presently the largest industry using hydrogen energy systems. In addition, chemical industries and refineries are consuming significant amounts of hydrogen. In the future, with the development of the complete hydrogen energy systems from production to end use and public acceptance, the energy industry is expected to become the key component in the hydrogen industry. To maintain economic prosperity and quality of life, there is a global need for sustainable energy systems that can meet the conflicting demands for increased supply and increased energy security, whilst maintaining cost-competitiveness, reducing damage to the environment and health, and improving air quality. Hydrogen and hydrogen energy systems are firmly established as strategic technologies to meet these objectives. This chapter shows that hydrogen energy systems can create win–win situations for public and private stakeholders alike. The benefits are expected to start to really flow after public incentives and private efforts are applied to stimulate and develop the main markets, which are the stationary power generation and transportation sectors. This should be done in a balanced way that reflects the most cost-effective use of the various alternative primary energy sources and energy carriers.

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[60] Bagotsky VS, Skundin AM, Volfkovich YM. Electrochemical power sources: batteries, fuel cells, and supercapacitors. Hoboken, NJ: John Wiley & Sons; 2015. [61] Blomen LJ, Mugerwa MN. Fuel cell systems. New York, NY: Springer Science and Business Media; 2013. [62] Vogel B, Feck T, Grooß JU, Riese M. Impact of a possible future global hydrogen economy on Arctic stratospheric ozone loss. Energy & Environmental Science 2012;5 (4):6445–52. [63] Oak Ridge National Laboratory. Hydrogen markets: implications for hydrogen production technologies. Available from: http://www.intpowertechcorp.com/122902.pdf; 2005. [64] Stockford C, Brandon N, Irvine J, et al. H2FC SUPERGEN: an overview of the hydrogen and fuel cell research across the United Kingdom. Int J Hydrog Energy 2015;40 (15):5534–43. [65] Hardman S, Chandan A, Shiu E, Steinberger-Wilckens R. Consumer attitudes to fuel cell vehicles post trial in the United Kingdom. Int J Hydrog Energy 2016;41 (15):6171–9. [66] Bellaby P, Clark A. Might more harm be done than good when scientists and engineers engage with the public about new technology before it is fully developed? The case of hydrogen energy. Int J Sci Educ, Part B 2015;6:1–20. [67] Pellegrino S, Lanzini A, Leone P. Techno-economic and policy requirements for the market-entry of the fuel cell micro-CHP system in the residential sector. Appl. Energy 2015;143:370–82. [68] Galvin R. Making the ‘rebound effect’ more useful for performance evaluation of thermal retrofits of existing homes: defining the ‘energy savings deficit’ and the ‘energy performance gap’. Energy Build 2014;69:515–24. [69] Navigant Research. Electric vehicle supply equipment tracker 3Q13. Available from: http://www.navigantresearch.com/wp-content/uploads/2013/09/TR-EVSE-3Q13-ExecutiveSummary.pdf; 2013. [70] Mayyas A, Wei M, Chan SH, Lipman T. Fuel cell forklift deployment in the USA. In: Stolten D, Samsun RC, Garland N, editors. Fuel cells: data, facts, and figures. Weinheim: Wiley-VCH; 2016. [71] O'hayre R, Cha SW, Prinz FB, Colella W. Fuel cell fundamentals. Chichester: John Wiley and Sons; 2016. [72] Slim BK, Darmeveil H, van Dijk GHJ, et al. Should we add hydrogen to the natural gas grid to reduce CO2-emissions? (Consequences for gas utilization equipment). Available from: http://members.igu.org/html/wgc2006/pdf/paper/add11558.pdf; 2006 [accessed 04.12.16]. [73] KEMA. NATURALHY: assessing the potential of the existing natural gas network for hydrogen delivery. Available from: http://www.gerg.eu/public/uploads/files/publications/ academic_network/2010/1b_Florisson.pdf; 2010 [accessed 10.12.16]. [74] The United Kingdom Hydrogen and Fuel Cell Industry (UKHFCA). Fuel cell benefits. Available from: http://www.ukhfca.co.uk/the-industry/benefits/; 2016 [accessed 06.09.16]. [75] The United States Department of Energy. The Hydrogen and Fuel Cell Technical Advisory Committee. Available from: https://www.hydrogen.energy.gov/pdfs/ 2015_htac_annual_report.pdf; 2016 [accessed 07.09.16].

Futher Reading Dincer I, Joshi AS. Solar based hydrogen production systems. Springer; 2013. Dincer I, Midilli A, Kucuk H, editors. Progress in exergy, energy, and the environment Springer; 2014. Dincer I, Rosen MA. Exergy: energy, environment and sustainable development. Newnes; 2012. Dincer I, Zamfirescu C. Sustainable hydrogen production. Elsevier; 2016. Gandia LM, Arzamedi G, Diéguez PM, editors. Renewable hydrogen technologies: production, purification, storage, applications and safety Newnes; 2013. Gangloff RP, Somerday BP, editors. Gaseous hydrogen embrittlement of materials in energy technologies: mechanisms, modelling and future developments Elsevier; 2012. Granqvist CG, editor. Materials science for solar energy conversion systems. vol. 1. Elsevier; 2013. Gratzel M, editor. Energy resources through photochemistry and catalysis Elsevier; 2012. Hoffmann P, Dorgan B. Tomorrow's energy: hydrogen, fuel cells, and the prospects for a cleaner planet. MIT Press; 2012. Hoffmann P. A history of hydrogen energy: a BIT of tomorrow's energy. MIT Press; 2014. Justi EW. A solar – hydrogen energy system. Springer Science & Business Media; 2012. Ohta T, editor. Solar-hydrogen energy systems: an authoritative review of water-splitting systems by solar beam and solar heat: hydrogen production, storage and utilisation Elsevier; 2013. Sherif SA, Goswami DY, Stefanakos EL, Steinfeld A, editors. Handbook of hydrogen energy CRC Press; 2014. Veziroglu T, editor. Hydrogen energy Springer Science & Business Media; 2012. Williams LO. Hydrogen power: an introduction to hydrogen energy and its applications. Elsevier; 2013. Winter CJ, Nitsch J, editors. Hydrogen as an energy carrier: technologies, systems, economy. Dordrecht: Springer Science & Business Media; 2012. Zini G, Tartarini P. Solar hydrogen energy systems: science and technology for the hydrogen economy. Springer Science & Business Media; 2012.

Relevant Websites https://www.airliquide.com/science-new-energies/hydrogen-energy Air Liquide. http://www.airproducts.com/industries/Energy/Hydrogen-Energy.aspx Air Products. http://www.alternative-energy-news.info/technology/hydrogen-fuel/ Alternative Energy News. http://www.alternative-energy-tutorials.com/energy-articles/hydrogen-energy.html Alternative Energy Tutorials. http://www.afdc.energy.gov/fuels/hydrogen.html Alternative Fuels Data Center. http://bahcesehir.edu.tr/ Bahçes¸ehir University. http://www.bahcesehir.edu.tr/icerik/3127-energy-systems-engineering Bahçes¸ehir University – Energy Systems Engineering. http://www.azocleantech.com/article.aspx?ArticleID=29 Clean Tech.

Hydrogen Energy

https://climatechangeconnection.org/solutions/alternate-energy-sources/hydrogen-energy/ Climate Change Connection. http://www.conserve-energy-future.com/hydrogenenergy.php Conserve Energy Future. https://www.eia.gov/energyexplained/index.cfm?page=hydrogen_use Energy Information Administration. http://energystorage.org/energy-storage/technologies/hydrogen-energy-storage Energy Storage Association. http://www.fchea.org/hydrogen/ Fuel Cell and Hydrogen Energy Association. http://www.gcgw.org/ Global Conference on Global Warming. http://hydrogenenergycalifornia.com/ Hydrogen Energy California. http://www.hydrogenenergycenter.org/ Hydrogen Energy Center. http://heshydrogen.com/ Hydrogen Energy Systems, LLC. http://hydrogeneurope.eu/ Hydrogen Europe. http://www.iahe.org/ International Association for Hydrogen Energy. http://www.ich2p-2017.org/ International Conference on Hydrogen Production. http://www.ieees9.fesb.unist.hr/ International Exergy, Energy, and Environment Symposium. https://www.joiscientific.com/ JOI Scientific. http://www.lindeus.com/en/innovations/hydrogen_energy/hydrogen_energy_applications/index.html Linde Group. http://www.the-linde-group.com/en/clean_technology/clean_technology_portfolio/hydrogen_energy_h2/index.html Linde Group. http://www.mcphy.com/en/markets/hydrogen-energy/ McPhy. http://www.merlin.unsw.edu.au/energyh/about-hydrogen-energy/ Merlin. https://www.nrel.gov/workingwithus/eds-hydrogen.html National Renewable Energy Laboratory. http://hidrojenteknolojileri.org/ 2nd International Hydrogen Technologies Congress. http://www.renewableenergyworld.com/hydrogen/tech.html Renewable Energy World. https://www.industry.siemens.com/topics/global/en/pem-electrolyzer/silyzer/hydrogen-green-energy-of-the-future/pages/hydrogen-the-green-energy-of-the-future.aspx Siemens. https://www.studentenergy.org/topics/hydrogen Student Energy. http://www.iae.or.jp/e/research-groups/research-and-development-division/hydrogen-energy-group/ The Institute of Applied Energy. https://www.uoit.ca/ University of Ontario Institute of Technology. http://cerl.uoit.ca/ University of Ontario Institute of Technology – Clean Energy Research Laboratory.

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1.14 Hydro Energy Zekâi S¸en, Istanbul Medipol University, Istanbul, Turkey r 2018 Elsevier Inc. All rights reserved.

1.14.1 Introduction 1.14.2 Background and Fundamentals 1.14.2.1 Basic Theory 1.14.2.2 Energy Types 1.14.2.3 Energy Units 1.14.2.4 Direct Power 1.14.2.5 Efficiency 1.14.2.6 Water to Electricity Power Conversion 1.14.2.7 Generating Power 1.14.2.8 Need for Hydroelectric Energy Production 1.14.2.9 Energy and Electricity 1.14.2.10 Energy and Economy 1.14.3 Systems and Applications 1.14.3.1 Comparison of Hydropower to Other Energy Forms 1.14.3.2 Hydropower, the Environment, and Society 1.14.4 Analysis and Assessment 1.14.4.1 Standard Hypsographic Curves 1.14.4.2 Numerical Power Calculation 1.14.4.2.1 Single-point method 1.14.4.2.2 Double-point method 1.14.4.2.3 Subdrainage method 1.14.4.2.4 Energy-tree model 1.14.5 Case Studies 1.14.5.1 Hydropower Applications 1.14.5.1.1 Murat River power and energy potential 1.14.5.1.1.1 Hypsographical curve method 1.14.5.1.1.2 Drawdown-flow method 1.14.5.1.1.3 Energy-tree method 1.14.5.1.2 Hudson River power and energy potential 1.14.5.1.2.1 Hypsographical curve method 1.14.5.1.2.2 Drawdown-flow method 1.14.5.1.2.3 Energy-tree method 1.14.6 Overall Recommendations 1.14.6.1 Energy Consumption Optimization 1.14.6.2 Ways to Save Energy 1.14.6.3 Hydropower Glossary 1.14.7 Modern Concepts and Future Role References Further Reading Relevant Websites

1.14.1

606 607 609 612 613 614 614 614 615 615 616 618 619 619 619 620 620 621 621 621 622 622 624 626 627 627 628 628 630 630 630 630 632 632 633 634 635 635 636 637

Introduction

Hydropower can be defined as a source of renewable energy obtained from flowing water in rivers. Hydroelectric energy is the conversion of hydropower to electricity generation from the running water through turbine, generator, and convertor. Hydropower stations are at the downstream location of dams, where the potential energy accumulation behind the dam is converted to kinetic energy through the pressurized pipes leading to electrical energy. The conversion station may have large-scale generation structures such as dams or small scale ones such as “run-of-river” installations. In both, falling water in dams and running water in river channels turn one or more turbines. In nature, it is impossible to create or destroy energy, but its form can change. For instance, in electricity generation no new energy is created. In order to generate electricity from water it is necessary that there should be movement, which turns turbine blades and in this manner water kinetic energy is converted to mechanical (machine) energy. The turbine turns the generator rotor,

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and with the help of a magnetic field the mechanical energy is converted into another energy form, which is electricity. In any energy generation, if the initial source of energy is water, then it is referred to as hydroelectric power (HEP) or hydropower. Some HEP plants are located on rivers, streams, and canals, but for a regular, steady, reliable, and sustainable energy generation, water storage areas behind dams are necessary. Dams are engineering structures that store water for later release to serve irrigation, domestic, and industrial purposes in addition to power generation. The reservoir acts much like a battery, storing water to be released as needed to generate power. Hydroelectric energy is the most important naturally supported renewable and clean energy alternative especially in the subtropical climate belt of the world. It is one of the most reliable, technically exploitable, and environmentally friendly renewable energy alternatives. Hydropower is a capital-intensive energy source with low operations and maintenance cost and essentially no fuel costs [1]. Continuously increasing use of renewable energy sources, including hydropower, is a key strategy to limit the extent of future climate change [2]. Steady rise in the energy demand, coupled with reduced hydroelectricity generation, could lead to a substantial impact on the hydropower operations [3]. Finger et al. [4] indicated that hydropower accounts for about 20% of the worldwide electrical power production. Demand for power varies greatly during the day, night, and considerably from season to season. For example, the highest peaks are usually found during summer daylight hours when air conditioners are running. Nuclear and fossil-fuel plants are not efficient for producing power for the short periods of increased demand during peak periods. Their operational requirements and long startup times make them more efficient for meeting baseload needs. Since hydroelectric generators can be started or stopped almost instantly, hydropower is more responsive than most other energy sources for meeting peak demands. Water can be stored overnight in a reservoir and kept until needed during the day, and then released through turbines to generate power to help supply the peak-load demand. This mixing of power sources offers a utility company the flexibility to operate other renewable energy sources most efficiently as base plants while meeting peak needs with the help of hydropower. This technique can help to ensure reliable supplies and may help to eliminate brownouts and blackouts caused by partial or total power failures. As for the scientific facets of hydro energy almost all of the aspects are covered in the literature concerning hydrological, hydraulic, and water resources topics. In many countries, industries obtain low-cost energy from the hydroelectric plants from major dams. The environmental issues that are related to hydropower energy generation units such as dams, run-of-river, and pumped-storage plants, have ignorable effects on the atmospheric pollution and also adjacent areas. It is also well known that hydropower plants can enter energy generation interconnected systems instantaneously, whereas other energy sources such as thermal units require longer time durations to serve the energy distribution system. All these aspects of hydro energy are explained in the following sections of this paper. This work provides up to date information about hydroelectric potential and policy with scientific support on the basis of different sets of available literature. The existing calculation formulations are discussed in a detailed manner with their pros and cons, and finally, a new methodology, the energy-tree (ET) concept, is presented with applications to two river drainage basins from Turkey and the United States. Compared to classical gross hydropower calculation methodologies, the ET method provides at least 0.4% to 6.5% improvement, which is a significant addition at the hydroelectric energy plant planning stage. The knowledge and information provided in this chapter make up a useful basic foundation for anyone who would like to work further on the scientific, technological, industrial, environmental, and economic aspects of hydro energy.

1.14.2

Background and Fundamentals

It is very important to evaluate hydropower potential of any river in a practical, refined, and realistic manner. However, there are a few valuable studies to determine the hydroelectric energy potential of rivers. In the following paragraphs, the methods proposed for the aim are explained in an arrangement from the simplest to the most complex. Lehnera et al. [5] calculated hydropower potential using the application of the global water model (WaterGAP) to observe climate change’s effect on hydropower across Europe. The authors used Eq. (1) for gross hydropower potential calculations. The equation can be represented as a single-point (SP) method. The method calculates gross hydropower energy potential very roughly. The method can be represented as SP method [5], which is the simplest form of calculations. The variables used in calculation of gross hydropower potential (i.e., the energy losses, slopes, etc.) should be taken into account. GP ¼ mgh

ð1Þ

where GP, m, g, and h are the gross hydropower potential, mass, gravitational acceleration, and height, respectively. Zhou et al. [6] applied an integration optimization of hydropower considering hydrology and hydrological modeling, flood routing optimization for power generation, flood control, ecological operations, multiobjective optimization, and multiattribute risk decision-making for the upper and middle Yangtze River. Eq. (2) was used for hydropower calculation. Although the authors considered many variables (i.e., hydrology and hydrological modeling, flood routing optimization for power generation, flood control, ecological operations, multiobjective optimization and multiattribute risk decision-making), all of these variables are represented by the comprehensive efficiency coefficient, K. N ¼ KQH where N, K, Q, and H are power, comprehensive efficiency coefficient, flow, and net water head, respectively.

ð2Þ

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Kusre et al. [7] calculated hydropower using a spatial tool (GIS) and hydrological model (SWAT2000) in the Kopili River basin in India. Geographic Information Systems (GIS) is used for identifying potential location for hydropower generation. Simulated discharge values are obtained with SWAT2000 and flow-duration curves are drawn for determining discharge for varying degree of dependability [7]. These values are used for calculating hydropower using Eq. (3). The difference between Eqs. (1) and (3) is only the effect of losses represented by hydraulic efficiency of turbine Z, which is represented by K in Eq. (2). On the other hand, mg multiplication used in the first equation is represented by rgQ multiplication [7]. P ¼ ZrgQH

ð3Þ

where P, Z, r, g, Q, and H are power, hydraulic efficiency of turbine, density of water, gravitational acceleration, flow discharge, and the effective pressure head of water, respectively. Larentis et al. [8] studied hydropower potential sites using a GIS-based computational program (Hydrospot) in Brazil. Eq. (4) is used for hydropower potential calculation [8]. The basic thinking of this equation is also not too different from the two previous equations. Herein, instead of K in Eq. (2) and Zrg in Eq. (3), a constant coefficient of 8.85 is used. Although in the previous equation, Q and H are not defined as averages, in reality, they should be in average. PN ¼ 8:85 QT HA

ð4Þ

where PN, QT, and HA are the average net potential power, the average net water head, and the average discharge passing through the turbines, respectively. On the other hand, there is no definition of the constant coefficient of 8.85; however, as indicated previously, it is thought to be a coefficient, which represents the hydraulic efficiency of turbine and the unit weight of the water. Ramachandra and Shruthi [9] calculated hydropower potential using GIS in Karnataka State, India. GIS is used for identifying probable small hydropower plant (SHP) locations. As it can easily be understood from the equation, this method is also similar to the SP method. Instead of unit weight, taking density of water, r as 1000, 1000g multiplication is used. Hydropower is then calculated using the following expression [9]: P ¼ 1000gHQZ

ð5Þ

where P, 1000, g, H, Q, and Z are the hydropower potential, unit mass of the water, gravitational acceleration, effective head of water, flow discharge, and hydraulic efficiency of turbine, respectively. Cyr et al. [10] determined probable SHP locations using a synthetic hydro network (SHM) obtained from digital elevation models (DEMs). Herein the SP method is also used for hydropower calculation for SHP, which is represented by Eq. (6). P ¼ rQghe

ð6Þ

where P, r, Q, g, h, and e are the hydropower potential, density of water, the volumetric fluid flow rate, gravitational acceleration, the drop height, and the efficiency coefficient, respectively. Liucci et al. [11] modeled the mean annual gross hydropower energy from a plant using flow duration curves (FDCs) in the Umbra region of Italy. Eq. (7) is used for hydropower calculation, which is based on the SP method. P ¼ QHZgw

ð7Þ

where P, Q, H, Z, and gw are the power, flow discharge, hydraulic head, turbine efficiency, unit water weight, respectively. Arefiev et al. [12] calculated hydropower for the majority of Russia using GIS and additional programming (Python language). Eq. (8) is used for hydropower potential calculations. Different from the above mentioned methods, this equation is based on the double-point (DP) method. Therefore, it is more complex and precise than those of the previous ones. Since the time (in hours) is taken into account, this equation also gives an opportunity to calculate the hourly, daily, monthly, or annual gross hydropower. Furthermore, it is possible to calculate hydropower for a specific distance between any two points on the river [12].   n n   X X Q1i þ Q2i H t ð8Þ Ni t ¼ g P¼ 2 i¼1 i¼1 where P, Ni, n, i, g, Q1i, Q2i, H, and t are the gross hydropower potential, gross capacity of a stream reach, number of stream reach, the gravitational acceleration, flow rate at beginning point of stream, flow rate at the end of stream, elevation difference on stream, and the number of hours per year (8760 h), respectively. Another complex method was reported in Rojanamon et al. [13]. The method is proposed particularly to select the best area for hydropower generation. The method considers engineering, economic, environmental, and social criteria using GIS technology, and it was used for the Nan River basin in Thailand. Eq. (9) is used for technical hydropower potential calculation. Although the equation is different from the previously mentioned ones, it includes the parameters, which represent several criteria, but it is also based on SP method.    0:001Lh þ 0:005Lp ð9Þ P ¼ 9:81  Zt  Zg  Qd  Hd where P, Zt, Zg, Qd, Hd, Lh, and Lp are the power, the turbine efficiency, the generator efficiency, the designed discharge, the gross head, length of headrace, and length of penstock, respectively. The UN Economic Commission for Europe (ECE) reported the first study on the hydroelectric potential of Europe by employing different methodologies [14]. Among these methods, two include hypsographic curves (HCs) and drawdown-flow (DF) approaches, which are well-known methods [14,15]. Another report by the same commission provided Turkey’s gross hydropower potential as 61,248 MW and 537 TWh [16]. Alterach et al. [17,18] developed a GIS tool (VAPIDROASTE) and

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proposed a methodology to evaluate the water resources availability and the maximum potential hydropower for the entire Italian territory. Belmonte et al. [19] calculated the hydroelectric potential for microturbine applications from the topographic drop and annual mean flow in cumulative models through the application of the Idrisi Kilimanjaro software runoff tool in the Lerma Valley in Salta (Argentina). Kusre et al. [7] assessed hydropower potential also by using a spatial tool (GIS) and hydrologic model (SWAT2000) in a hilly watershed in the Kopili River basin in Assam (India). Cyr et al. [10] suggested a method to map small hydropower potential over the province of New Brunswick (Canada) [10]. Sidek et al. [20] presented a hydrologic analysis method for the assessment of hydropower potential in Sungai Pahang at Temerloh (Malaysia). Other energy supply alternatives are hydropower, solar, wind, wave, geothermal, and hydrogen energy. These resources are clean and renewable, and are extracted from the nature with almost negligible pollution effects in practice. The continuously increasing use of renewable energy sources, including hydropower, is a key strategy to limit climate change [2]. Continuous rise in the energy demand, coupled with reduced hydroelectricity generation, could lead to a substantial impact on the hydropower operations [3]. This is because of the fact that serious global problems, such as climate change, have an effect not only on energy sources, but also on almost all aspects of life. Among the renewable energy sources, hydroelectric energy is one of the most reliable and exploitable alternatives. Finger et al. [4] indicated that hydropower accounts for about 20% of worldwide electrical power production. There is an increasing use of satellite data and numerical models to assess the environmental constraints and energy potential of several renewable energies, namely solar, wind, hydropower, biomass, and geothermal.

1.14.2.1

Basic Theory

There are numerous factors that must be taken into account for optimal location, size, and layout determination of a hydroelectric power plant (HEPP) including the local topography and geologic conditions, the amount of water and head available, power demand, accessibility to the site, and environmental concerns. The most significant points in a HEPP construction are its adequate functional performance and structural safety. Hydroelectricity is an energy generated by converting the kinetic energy of falling or flowing water into electricity. It is considered as the most widely installed form of renewable energy. HEPP has considerably lower emission levels of carbon dioxide and other greenhouse gases than fossil fuel-powered energy plants, and less life cycle greenhouse gas impact than that of solar power. Furthermore, the ecological impacts of hydropower are arguably greater than those of any form of energy production, due to the large footprint of biological impact of reservoirs and other needed developed areas. A typical HEP production plant is given in Fig. 1. The force of falling water is the main source for hydroelectric energy with the capacity dependent on both the runoff water availability and falling height (head). Behind a high dam, water accumulates as potential energy in the reservoir storage, which is then transformed into mechanical energy when the water rushes down the sluice

Hydroelectric power generation

Power transmission cables Dam Transformer

Sluice gates

Power house

Generator k oc

t ns

Pe

Dam Downstream outlet Source: Environment Canada

The bigger the height difference between the upstream and downstream water level, the greater the amount of electricity generated

Turbine

Storage reservoir Silt

Fig. 1 Schematic view of hydropower production. Reproduced with permission from Environment and Climate Change, Canada, Hydroelectric power generation. Available from: http://www.ec.gc.ca/eau-water/default.asp?lang=En&n=00eee0e6-l/; 2012 [accessed 18.07.16].

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and strikes the rotary blades of turbine. The turbine’s rotation spins electromagnets, which generate current in stationary coils of wire (Fig. 1). Finally, the current is put through a transformer, where the voltage is increased for long distance transmission over power lines [21]. The natural flow is accumulated behind a dam so that the water surface elevation increases up to the designed volume of the dam; hence, potential energy storage is achieved. This energy is converted to artificial kinetic energy by means of falling from a higher elevation to lower level, where there are turbines that convert the kinetic energy to electric energy. The sequences of these energy types are shown schematically in Fig. 2. Rainfall or snowmelt conversion to surface flow naturally depends on the surface features of the drainage basin. Especially, high mountainous areas at the upper drainage basin have heavy rainfall and snow cover, which are the main sources not only for electric energy generation production but also for agricultural, domestic, and industrial water supplies and groundwater recharge possibilities. The electric energy generation is sustainable as long as the rainfall and snow events are dynamic in the area. However, recent global warming and climate change impacts cause rainfall and snow increase or decrease depending on the location of the region. Especially, in the late 19th century, hydropower became the major source of electricity generation. The first HEP was generated at Niagara Falls in 1879, which provided electric energy for lighting the streets with lamps. The three main parts of a hydropower generation system are the storage for water accumulation leading to water level rise, the dam for water regulation by opening and closing the gates, and instruments for electric energy generation. The stored water is led to the blades of a turbine to cause its turn. The electricity is generated by the spin of the turbine. The amount of electricity generation is a function of both the falling head and also the discharge of water led to the turbines (see Eq. (9)). The generated energy can be transferred to long distances by a network of transmission lines. Among the renewable energy resources, hydropower is the cheapest alternative to generate electricity, because the runoff born energy is free after the dam construction and installation of the turbines. Fig. 3 comparatively shows the production costs of different power plants. The renewability of the sources is the result of rainfall or snowmelt or both depending on the location. Most often, subtropical regions of the world are the most promising locations for hydropower generation purposes. One of the most attractive features of hydropower generation is its ready availability, controllability of water flow through the gates, and turbines to meet almost instantaneous energy demand. Apart from the electric energy generation, the dam reservoirs provide water supply, agricultural irrigation, and water sport activities in the region. The basic definition of hydropower or HEP is the energy that is obtained from the capture or water movement in the natural drainage basin channels. The major type of hydropower facility is powered by the kinetic energy of runoff as it moves from

Dams

Water flow

Tailrace Water valve

Water flow

Synchronous generator Water turbine

Tidal barrage

Ac power

Speed control Wave power

Hydro electric power generation

Fig. 2 Energy conversion sequences. Reproduced with permission from The Electropaedia, UK, Battery and Energy Technologies. Available from: http://www.mpoweruk.com/hydropower. htm/ [accessed 18.07.16].

Production cost ($/kWh)

5 4

Fuel Maintenance Operating

3 2 1 0 Thermal

Nuclear

HEPP

Gas turbine

Fig. 3 Production costs of different power plants. Reproduced with permission from Eris E, Toprak ZF. Biriktirmesiz Hidroelektrik Santralleri ve Dünyada ve Türkiye’deki Mevcut Durumları (Runoff Hydroelectric Plants and Current Stations of Turkey and World), 2. Su Yapıları Sempozyumu (II. Water Structures Symposium), 16–18 Eylül; Diyarbakır, Türkiye; 2011.

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upstream to downstream within a drainage basin. Turbines and generators convert the energy into electricity, which is then fed into the electrical grid to be used in homes, businesses, and by industry. Electricity is generated by hydropower, and referred to as “hydroelectricity.” It is generated either by the fall of water from a high elevation or from naturally flowing water. Hydropower is very flexible energy, because by means of gates in dams and other control instruments, the level of electricity generation can be fixed even immediately at a certain level according to energy demand or energy demand gap from other alternatives. Dams interrupt the natural channel flow in a drainage basin; and at the downstream of a dam, the channel has regulated flow, which may affect the ecosystem in addition to displacement of historical monuments and especially settlers, which may cause local social instability. After the completion of dam construction, there is almost no waste production, and considerably lower amount of greenhouse gases (especially carbon dioxide) compared to those of fossil energy burns. The energy from the falling water depends on discharge (the water volume per time), and on the difference in height, H, between the water surface behind the dam reservoir and the position of the turbine. This height difference is the hydraulic head and the potential energy is directly proportional to the head. Water is delivered to a turbine by means of a large pipe, which is referred to as a penstock (Fig. 4). The power, P, production through a HEPP as shown in Fig. 4 can be calculated by taking into account various factors as given in Eq. (3). A fundamental drawback of hydroelectricity is the variation of discharge, even when a large reservoir is present to regulate some flow. Temporal variation in river flow may deviate by a factor of 5–10 over long duration annual cycle, which places an inherent mismatch in power supply to a grid. One method of mitigation is to have consecutive reservoirs, which can allow use of surplus electricity to pump water to the higher elevation source, when there are peak water flows. This technique helps to regulate the power generation, but at the expense of considerable power wastage. The conversion of potential energy behind the dam is very easy through an intake gate to the pipe that leads water to the turbines. The pipe that leads water to the turbines is known as the penstock. The falling water rushes toward the turbines and hits the turbine blades with force and causes the turbine to spin. This is equivalent to the conversion of the kinetic energy to mechanical energy. The water that gives a great part of its kinetic energy to the mechanical energy leaves the turbines as energyless water and runs to the downstream channel after the dam. The generator is connected to the turbine by means of a shaft, and hence, the spin of the generator is satisfied by the turbine spin. In the generator, there is an electromagnetic field that converts the mechanical energy to electrical energy. The most important property of the water reservoir behind the dam is its very quick response to energy demand as long as there is sufficient head between the water level in the reservoir and the elevation of turbines. In this manner, electrical energy can almost instantaneously be generated after the above mentioned energy conversion sequence. The water flow through the penstock can be controlled as needed by directly opening and closing the intake gate; and hence, the electrical energy generation amount can be adjusted according to demand. In practical application, because of the instantaneous response of hydropower to energy demand, water is accumulated behind the dam and used as a support to other energy sources such as thermal, wind, geothermal, solar, biomass, or any other energy source availability. The unit where energy is generated is called a powerhouse with turbines and generators inside it. For the conversion of the energy at the final stage to electric energy there is also a transformer, which increases the voltage after the generator to a higher voltage for the purpose of reducing transmission losses.

Headwater Electrical energy

Potential energy

Dam Electricity

Forebay Generator Kinetic energy

Turbine Penstock

Afterbay Mechanical energy Fig. 4 Hydro energy conversion stages. Reproduced with permission from Duy NM. Micro hydroelectric power plant with chain turbine. Available from: http://www.frenchriverland.com/final%20-%20Report%20Hydroelectric%20power%20plant.ppt/ [accessed 19.07.16].

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Hydro Energy

The transmission of high voltages is possible through the power lines from the powerhouse to urban, industrial, military and other needy areas. In between the two locations, there are other transformers to reduce the voltage to useable levels. The categories of hydropower unit can be thought of as four types: 1. Hydroelectric dams with large storage reservoirs for conventional hydroelectric generation; 2. Without storage (reservoir) run-of-the-river hydroelectricity generation units, which convert the running water kinetic energy by means of small turbines to electrical energy. Such units are small in size and they are 10 MW or less capacity plants. They are also very convenient for isolated houses, small villages, and local industry with their few to hundred kW capacities; 3. Conduit type of hydroelectricity generation units divert running water to locations for high fall possibilities and generate electricity; 4. Pumped-storage hydroelectric energy generation units pump water from lower to higher location during low energy cost durations (mostly nights) or by support of other discontinuous energy sources such as solar and wind energy. It should be remembered that the water flow in a stream has seasonal variations; and therefore, at the planning and project stages of a hydropower unit, it is necessary to extract the necessary information from rainfall (and better from the runoff time series records). The seasonal variations can be smoothened out by dam and reservoir structures. The main environmental impact of the reservoirs is the change of the natural ecological life especially at the downstream regions. In the design of a dam, the probable maximum rainfall and its consequent probable maximum flood situations must be taken into consideration for dam stability works, flood dangers and for the spillway design, which allows unnecessary flood water to bypass the dam reservoir. For such kind of works, computer modeling procedures can be used to obtain the optimum management case.

1.14.2.2

Energy Types

First, the force, F, is defined as the change of momentum in the Newtonian physics as dðmvÞ ð10Þ dt where mv is the momentum, m is the mass, and v is the velocity of this mass. Energy, E, is equivalent to work, W, and it is defined as dE¼ dW¼FdL where dL is the distance covered. Hence, Eq. (10) can be rewritten as F¼

F dL ¼ dðmvÞ

dL : dt

ð11Þ

Since the basic definition of velocity v¼dL/dt, then the last expression takes the following form dE ¼ dðmvÞv This expression can be expanded into dE ¼ v2 dm þ mvdv

ð12Þ

which indicates that energy variation consists of two gradients, namely, the change in mass (the first term on the right hand side, similar to Einstein’s energy), and the change in velocity (the second term on the right hand side, related to Newtonian kinetic energy). Mass and energy are regarded as distinct properties, because in Newtonian physics as in Eq. (12), they are distinct and measured in different units. This is due to the fact that spatial and temporal units are perceived separately, which gives rise to the perception of different mass and time properties. The expression in Eq. (12) can be expressed verbally as “Energy change is the summation of a constant (velocity) times change in mass plus another constant (mass) times velocity times change in velocity.”

Then the next question one can ask is what the energy is. If the mass is constant in this case, the first term on the right hand side of Eq. (12) becomes zero and the energy expression takes the form as follows: dE ¼ mvdv which, after the integration, yields the total energy due to the velocity change only as EK ¼

1 2 mv 2

ð13Þ

This is the kinetic energy expression in the Newtonian physics domain. After all, these simple derivations from Eq. (12) indicate that mass and energy are not the same as suggested by some philosophers and physicists. The same equation implies that mass and energy are distinct properties of physical systems. The final conclusion of this short explanation indicates that energy and mass are different properties without conversion. There are different ways to define power as the rate of work performance, energy generation rate, and torque application rate. The reader should keep in mind that work, W, energy, E, and torque, t are synonymous words, although they are thought by many people to be different concepts (E¼ W¼ tE). Their common unit in the metric or SI system is newton meter or newton-meter (Nm) or joule (J). By definition, newton as a unit is equal to kg m/s2. Power is defined as energy per unit time, and its unit is either Nm/s (newton per second) or J/s (joule per second). Another rather commonly used unit of power is hp (horsepower).

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As for the energy types, two of the basic alternatives are the kinetic (movement) energy, EK, and potential (position) energy, EP, as EP ¼ mgh

ð14Þ

And torque as well is defined similar to work as follows: t¼F l

ð15Þ

where m is the mass of an object, in kg (SI units system); g is the gravitational acceleration due to gravity ¼ 9.8 m/s2 (SI units system); h is the elevation of the object, in meters; F is the force in N (newton); t is the torque in Nm (joule); and l is the moment arm, or perpendicular distance, in meters, from the fulcrum, at which the force is applied. In practical studies, potential and kinetic energies, work, and torque are measured in kilowatt-hours (kWh). Potential energy, kinetic energy, work, and torque can ultimately be measured in joules and kWh (unit for electrical energy). For these final units, the substitution units must be in kg for mass, m/s for velocity, and m for elevation. Based on definition and unit description for the energy types, power, P, is given as energy per unit time as follows: P¼

E t

ð16Þ

where t is the time duration for energy use. The unit of the power is joule per unit time duration, which is succinctly referred to as watt (W), and 1000 W¼ 1 kW ¼1 kW. It is possible to express energy in terms of power and time duration as E ¼ Pt

ð17Þ

Aggregate bulk materials such as sand, flour, grain, and sugar are to be conveyed by powered conveyors. There are two formulations for the calculation of required power and force quantities for moving “loose” or discrete “unit” mass. The power and force formulations are, P ¼ FDv

ð18Þ

F ¼ QDv

ð19Þ

and

where P is the power in J/s or W, F is the force required to move the conveyor belt, Dv is the change in the velocity of unit mass on the conveyor in the direction of the applied force and in the movement direction, and Q is the discharge (mass flow rate). Example 1: Over a conveyor belt moving with a velocity of 2.0 m/s there are sand drops at the rate of 20,000 kg/min, hence, 1. Calculate the force that impacts on the conveyor. 2. Calculate the minimum motor size for the conveyor movement.

1.14.2.3

Energy Units

In general, energy is defined as the ability to perform work. According to the first law of thermodynamics, the total sum of all the forms of energy in a closed system is constant. It is also referred to as the principle of energy conservation. In order to discuss various energy alternatives quantitatively and comparatively, it is necessary to bring them all to a common expression in terms of units of measurement. The basic and physical unit of energy is joule (J), which is based on the classical definition of work as the multiplication of force by distance. Hence, one joule (J) is equivalent to the multiplication of one newton (N) of force by 1 m distance, and this definition gives us J ¼ Nm. The joule is named after the 19th century scientist James Prescott Joule, who demonstrated by experiments the equivalence of heat and work. Unfortunately, the joule is far too small a unit to be convenient for describing different resources of world energy supplies. It is, therefore, necessary to define its greater versions as megajoule (MJ) as 106 J and gigajoule (GJ) equivalent to 109 J and terajoule (TJ) as 1012 J. Another difficulty in practice with the joule is that oil producers measure the output of a well by barrels and coal producers by tons. And such different units require unification of the energy units by a common base. For instance, the coal equivalent ton (cet) is such a basic unit, which has been adopted by the United Nations. A commonly used value for the cet is 38.6  106 kJ. Likewise, it is also possible to define oil equivalent ton (oet), which is equal to 51  106 kJ. On the other hand, electrical energy is expressed, in general, in terms of kilowatt-hours (kWh). It is, therefore, necessary to know the energy conversion factors between different energy units [22]. Solution 1: 1. The force calculation can be achieved from Eq. (19), which yields F¼ 20,000  2  (1/60) ¼666.67 kg m/s2 ¼ 666.67 N. 2. Eq. (10) helps to calculate the motor power as P ¼666.67  2 ¼1333.3 Nm/s ¼ 1333.3 J/s¼1333.3 W. Furthermore, since 746 W ¼ 1 hp (horsepower), then in terms of hp the minimum motor power can be calculated as 1333.3/746 ¼ 1.79 hp.

614 1.14.2.4

Hydro Energy Direct Power

Practically, direct current, DC, power is equivalent to power in the mechanical realm and it is also referred to as the “real power”; unlike the alternative current (AC) power, its entire transformation into work is possible, easily comparable to the other forms of energy such as potential energy, kinetic energy, heat energy, etc. Transformation assessments are possible through power, P, and energy, E, relationships as in Eq. (17), where E is the mechanical work performed under DC (J or Nm) and t is the direct current power application duration. The definition of DC power, P, is given as P ¼ VI

ð20Þ

where V is the direct current voltage in volts (V), and I is the direct current in ampere (A). Eqs. (16) and (20) provide an opportunity to quantify mechanical work in terms of voltage, current, and time as follows. E ¼ VIt

ð21Þ

DC is measured in W, kW, MW, GW, TW in the SI or Metric unit system, where the letters k, M, G, and T signify thousand, million, billion, and trillion units, respectively. Other commonly used power conversion factors between the SI system and US system are 1.055 kJ/s ¼ 1.055 kW ¼ 1 BTU/s; 1 hp¼ 746 W ¼ 746 J/s ¼ 746 Nm/s ¼0.746 kW ¼ 550 ft-lbf/s. On the other hand, DC energy or “real” energy is traditionally measured in Wh, kWh, MWh, GWh, TWh (1012 Wh). The valid conversions between the SI and US realms are 1000 kW  1 h ¼ 1 MWh; 1 BTU ¼ 1055 J ¼ 1.055 kJ; 1 BTU¼ 778 ft-lbf; and 1 hp  1 h ¼1 hp-hour. Example 2: Someone left his/her car with its parking lights on for 1 h. The car battery has 12 V DC and the lamps are incandescent. Assuming that all of the parking lamps are extracting a combined current of 4 A, what is the total energy consumption expectation by the parking lights, in the form of heat and light? Solution 2: Application of Eq. (21) yields E¼ 12  4  1¼(48 W) (3600 s)¼48(J/s) (3600 s)¼ 172,800 J ¼172.8 kJ.

1.14.2.5

Efficiency

The efficiency factor is the ratio between the total energy production and the theoretical potential energy of the water that passes through the turbine. This factor is provided by turbine manufacturing companies, which obtain its value after a series of experimental tests. The factor reflects the losses as head loss due to the flow friction in the power canal and penstock, tail water rise due to flow, station location, gravitation variation, temperature and barometric air pressure, and water density variations. In any system, efficiency is the ratio of output to input, which essentially indicates “what percentage of the input is converted to output.” In general, both output and input can be power, energy, torque, or work. When power is the subject of analysis, then the definition of efficiency is as follows: Efficiency ð%Þ ¼ Z ¼ 100

Output power Input power

ð22Þ

In the case of energy, it takes a similar form but this time energy instead of power as given in the following formulation. Efficiencyð%Þ ¼ Z ¼ 100

Output energy Input energy

ð23Þ

The overall system efficiency calculation based on work can be stated as follows by taking into consideration that work is energy. Efficiencyð%Þ ¼ Z ¼ 100

Work performed by the electromechanical system Input energy

ð24Þ

Since energy cannot be created, the numerical value of the efficiency lies between 1% and 100%. Large-scale hydroelectric generation is by far the most efficient method, where water kinetic energy is concentrated on a specific point on the turbine blade in a controllable manner, and thence, kinetic energy is captured and converted into electric energy after passing through the generators. During all these processes, there are no inefficiencies as far as thermodynamic or chemical processes and heat losses are concerned. HEPP conversion efficiency depends mainly on the type of water turbine, and it can reach up to 95% for large installations, but in smaller plants (output powers less than 5 MW) the efficiencies remain between 80% and 85%.

1.14.2.6

Water to Electricity Power Conversion

Let’s assume that the turbine blades receive power, P, deliverance from water jet, PW, without any kinetic head loss or potential head loss and zero frictional head loss, and thence, the simple formulation of P can be given in Eqs. (16), (18), and (20). The transformation of power and energy from water to electricity is first depreciated in the turbine and later in the generator by respective efficiencies of the turbine and generator. And then, electrical power generation is routed to the power grid through the necessary switchgear and transformers. On the other hand, in the context of energy flow from water to electricity, functional relationship between electrical power, PW, generator efficiency ZG, water turbine efficiency ZT, and the water power, Pwa after the losses can be written as [9]: Pwa ¼ Pw ZG ZT

ð25Þ

Hydro Energy

615

In HEP plants, power and energy are transferrable from water to electricity by means of hydraulic turbines and such a flow of power and energy is referred to as “water to wire” flow of power. Furthermore, the power transmission by the water to the turbine blades is called “water horsepower, WHP,” which is rarely referred to as “hydraulic horsepower” or “fluid horsepower” as well. The power transformation from hydraulic to electrical form can be computed through the expressions, WHP ¼

hA gQ 550

ð26Þ

WHP ¼

DPQ 550

ð27Þ

or

where WHP is the water horsepower as a result of the water pressure onto the turbine, hA is the net head added to the water, g is the specific weight or density, DP is the differential pressure across the turbine, and Q is the discharge (volumetric flow rate of water) that flows through the turbine. In case of water energy transition to electricity, there is a functional relationship between electrical power, PE, generator efficiency ZG, turbine efficiency ZT, and WHP as [9] PE ¼ WHP ZT ZG

1.14.2.7

ð28Þ

Generating Power

The dam gives rise to a water head or height from which water flows through a pipe (penstock) that directs the water from the reservoir to the turbine. The fast-moving water pressurizes the turbine blades, something like a pinwheel in the wind. The water’s force on the turbine blades turns the rotor, the moving part of the electric generator. When coils of wire on the rotor sweep past the generator’s stationary coil (stator), electricity is produced. There are numerous factors that must be taken into consideration for optimal location, size, and layout determination of a HEP plant including the local topography and geologic conditions, the amount of water and head available, power demand, accessibility to the site, and environmental concerns. The most primarily significant point in a HEP plant construction is its adequate functional performance structural safety.

1.14.2.8

Need for Hydroelectric Energy Production

There are many reasons for the HEP generation need in the future. These can be summarized as follows [23,24]. 1. Water is the core source within the country and not foreign dependent, and it is renewable and cheap; 2. Clean and environmentally friendly energy source without damaging CO2, SO2, and NOx emissions or ash; 3. The adaptation capability is very swift and in the case of any breaks in any HEP plant, another one can replace its production almost instantly; 4. Peak power demand is the cheapest and matches the demand easily; 5. Regulates the frequency and voltage and makes equilibrium as a compensator; 6. Works interconnectedly with other HEP plants in a harmonic manner at the least cost with high quality energy production; 7. Dams regulate the natural flows of rivers including floods and droughts; provides water supply, irrigation water, and recreational sites with sports activities; 8. Dams store electric energy as water reservoirs and produce energy at the time of demand; 9. The excavations for providing fuel to thermal power plants require extra fuel consumption and cause environmental pollution, which is not the case in HEP generation; 10. The economic lives of dams and any elements such as spillways, derivation tunnels, etc. are very long (100 to 200 years). The active life of turbines is almost 40 to 50 years; 11. The initial investments of HEP plants are comparatively very high, but production and management as well as operation and maintenance costs are very low. Repays the initial investment in a short time duration after the beginning of operation; 12. HEP is not affected by fluctuations in oil prices, and it is reliable and continuous; 13. In developed countries, most of the HEP plants were completed before the high increase rate in oil costs prior to 1960. However, some countries stayed behind this trend; and now that the oil prices are high, the construction of HEP plants greatly presses their economic and industrial developments; 14. The raw material of HEP is water and its conversion to electricity gives 90% convertibility, which is quite high compared to 50% yield in thermal power plants; 15. The risk of accidents at HEP plants is relatively very low compared to other power production facilities; 16. In HEP, the water fall causes rotation of the turbines; and during this procedure, the friction losses are negligibly small, and hence there is no danger of wearing out; 17. The HEPPs can enter the energy circuit simultaneously and adaptively whereas in thermal plants the boilers must be heated prior to any energy production;

616

Hydro Energy

18. The construction of HEP plants provides employment, and typically local engineers and workers are the main beneficiaries of employment; 19. Almost 80% of the investment costs are for construction and the remaining 20% are for the electromechanical costs. On the contrary, in thermal power plants, 20% are the construction, whereas 80% are the electromechanical costs; 20. In the long term, the production cost per kWh at HEP is about 0.92 cents, whereas it is 4.362 and 4.184 cents for natural gas and lignite plants, respectively. The major climate change effects on water resources, and hence, on HEP production can be given as follows [25]: 1. Climate change impact will be more significant on the water resources in some regions and accordingly the quantity of water resources that feed these regions will have a decreasing trend; 2. Also, water production and ecology of the environment will be affected negatively, again in a decreasing trend manner; 3. In the long run, some regions are expected to have a decrease in rainfall and increase in temperature, which may couple the intensity and areal extent of regional droughts with reductions in agricultural production and also changes in crop types; 4. Accordingly, there will be significant decreases in overall HEP production, which may reach to 5 to 10 percent reduction; 5. Recreational areas are also expected to be affected by climate change, leading to more desertification especially in the southeastern and Mediterranean regions; 6. Due to droughts, the overall sedimentation into the dams is expected to increase, which will cause reduction in the active life of the dams, and hence, negative effects on electric energy production; 7. Possible sea level rises along the coastal areas are expected to cause salt water intrusions into the coastal aquifers and coastal flooding and loss of precious land use; 8. Per capita water supply will decrease, and on the other hand, the population rise will make water resources more precious; 9. As a result of reduction in the surface water quality, many societies may enter alternative agriculture with less waterintensive crops. Technologically, the construction of hydropower generation systems has become well established with minor problems depending on the specific location site. They can be constructed from different materials such as solid masonry or concrete dams, which resist overturning moment of water pressure by their own weight only. Arched masonry or concrete dams are curved in plan, with its convexity toward the upstream side. Such a dam transfers the water pressure and other forces mainly to the abutments by arch action. Buttress dams consist of a sloping deck supported by buttresses, which are triangular concrete walls, which transmit the water pressure from the deck slab to the foundation. Rock fill dams are built of dumped rock fill in preference to concrete dams, if an abundance of suitable rock is available nearby, or in remote areas where the cost of cement would usually support some type of concrete dam as well, so the choice is a question of economics. Earth dams resist the forces exerted upon them mainly due to shear strength of the soil. They are built usually in wide valleys having flat side slopes and can be built on all types of foundation. In earthen rock fill dams, some section of the dam might have a combination of rock fill and any type of earth fill construction. The high Aswan dam is an example of such type of dam. All these types of dams have almost the same environmental effects, which are negligibly small compared to those of other energy sources including fossil fuels and many renewables. Socially, dam sites are useful for water sports, recreational activities, fishing, and sailing purposes. As far as the economy is concerned, hydroelectric energy production plant investment, initial necessary construction, and land preservation costs are rather high, but their life durations are comparatively longer, and more durable than those of other energy production sources; and therefore, in the long-run, energy prices are at the lowest level among other energy production units.

1.14.2.9

Energy and Electricity

In the last 30 years, the variety, production, and consumption rates of electric energy resources have increased in an unprecedented manner with effective management strategies on the supply and demand side as well as refined technological developments that become more suitable to local conditions. Such innovative changes have been in progress since the 1970s, with the first worldwide oil price shock. In the meantime, each country has developed different renewable energy sources; but in some of the subtropical and polar climate belts, hydroelectric energy is still the most explicitly used one for electric energy production. Especially in recent years, energy systems’ capacity and technologies have expanded to convert various energy sources into electricity. Technological advancements in various energy generation gadgets have provided the opportunity for developing countries to leapfrog over the traditional alternatives by expanding energy generation facilities even to rural areas. Furthermore, energy use efficiency has also increased with education of societies, and there is a tendency in research and application to reduce the use of fossil fuels to maintain the chemical composition of troposphere, and hence, alleviate global warming and combat the impact of climate change. Among the future electric energy generation prospects is the resistance to fossil fuel usage with the support of a gradual shift toward cleaner fossil fuels by increasing involvement of renewable energy sources. Countries try to divert the energy production into a direction for greenhouse gas emissions reductions, and hence, climate stabilization. Technological developments based on the digital, social, and economic aspects encourage people to use more electric energy and service. Improvements in energy use efficiency help to direct attention to better prospects of energy production at lower cost. Unfortunately, energy consumption is centralized to urban areas; therefore, poor people in rural areas often cannot benefit from electric energy facilities. In order to balance the energy consumption among different sectors and areas, it is necessary to try

Hydro Energy

617

and decentralize energy distribution by more efficient and expanded off-grid systems. There are three main ways to improve electricity delivery in a balanced manner: 1. Consumers are one of the main key sectors to reduce electric energy wastage and they may provide additional ways of energy savings. Such efforts help to reduce the capacity of electric energy generation units as dams. In energy systems, inefficient appliances must be replaced with modern and efficient ones. The users must care for demand management alternatives so as to reduce electric energy consumption and find ways of efficient use. On the demand-side management, consumers support the system by using less and more efficient electric energy in the sectors that they are engaged with. For more effective sustainability, it is recommended to expand information training programs on energy efficiency services for suppliers and consumers; 2. Electric energy generation companies or governments should strive for efficient production, and centralized generations should be transmitted and distributed to local users. There is considerable scope to reduce transmission losses in many countries and these require urgent attention; 3. Traditional electric energy generation units must be replaced by new technological production to support the overall efficiency in addition to the efficiency works at the demand and supply ends. Especially, grid and off-grid efficiency must be improved continuously. Transmission losses from the energy production plant and the consumer location must be reduced as much as possible through innovative technological developments. Among the transmission losses are the technical losses at the power station, step-up transformer losses, and transmission and distribution losses. In some countries transmission losses may reach to 25%–30%. For instance, there is about 35% loss of electric energy in India, due to insufficient functions of transmission lines and distribution system. It is possible to reduce this high rate of loss to about 10%–15% by technical improvements. Significant advances in the electronic control and direct current (DC) transmission technology (including AC/DC and DC/AC converters) provide better grid connections and operation. Hydropower covers 19% of the world’s electrical supply, whereas all renewable sources (biomass, wind, solar, geothermal, ocean energy sources, and cogeneration) currently constitute around 1.4%–1.6% of global generation. Hydropower, wind, and solar energy sources are intermittent with technical limitations, and at times of their availability they can supply to the grid. There are many technical criteria that influence the utility preference for a particular generation source (peak, base, reserve, or intermittent power supply). HEP plant construction has social and environmental impacts as well. Many advocate that HEP is clean and green in the sense that low-carbon emissions are valid. Since HEP is a low greenhouse gas emitter, it helps to protect the global climate, and foster economic growth and social development. Hydropower is a flexible renewable energy with the aim of the lowest impact for low-carbon electricity. It features many energy developments coupled with climate mitigation tasks. Technical hydropower potential use in Africa is less than 10%. South and North America use 2% and 39%, respectively; whereas in Europe, it is about 53%. In sub-Saharan Africa, hydropower plants are the majority renewable energy source. The Africa-EU Energy Partnership (AEEP) has already committed to installing 10,000 MW by 2020 along with the increase of other renewable generation capacities. Since 2005, among the renewables (especially biomass, wind, solar, and geothermal energy sources), HEP provides the largest electricity generation capacity as shown in Fig. 5 [26]. 12

Other

10

Geothermal Solar 8 Wind 6

4 Hydropower 2

0 2012

2020

2025

2030

2035

2040

Fig. 5 World net electricity generation from renewable sources (trillion kilowatt-hours). Note: Other generation includes biomass, waste, and tide/ wave/ocean. Reproduced with permission from S¸en Z. Applied drought modeling, prediction and mitigation. Amsterdam: Elsevier; 2015. p. 472.

618

Hydro Energy

Hydropower’s environmental and social impacts are a major concern, even though single and multipurpose dams have economic and social developments for controlling hydrological variability, settlements, and agricultural land from flooding during the wet season, and providing water for irrigation and domestic use during the dry season [27]. For about a century, they have also been used to generate HEP. However, dams obstruct upstream–downstream connectivity and regulation of natural flow variability leading to ecosystem degradation and affecting the livelihoods of the communities. Due to the reservoir area inundations, forced community relocations take place in addition to land confiscation with inadequate compensation or even without payment. However, neither the World Commission on Dams (WCD) nor other international standards have shown a distinctive impact. Actual practical applications and observations do not show any comprehensive environmental and social impact assessment studies of environmental management and resettlement action plans [28]. Greenhouse gas emissions from hydropower schemes are not zero but are very low. The Intergovernmental Panel on Climate Change (IPCC) [29] found overall emissions of hydropower per unit of energy generated to be 100–250 times lower than those of fossil thermal plants. Hydropower has the potential to replace and prevent large amounts of emissions and can contribute to the phasing-out of thermal power plants, and also affordable electricity from hydropower plants can replace diesel generators. In the tropics, it is particularly important that reservoirs are cleared of vegetation in order to reduce the generation of methane and other GHG. It is always possible to combine HEP plants with other renewable energy sources. HEP plants have water reservoirs from where water can be employed to generate electricity at any time unlike solar and wind power. Hydropower plants have the ability to act with quick startup and shutdown capabilities, and hence, they enhance the efficiency and stability of electricity grids. HEP plants help to support other renewable energy source developments, and in this way they also help for further greenhouse gas emission reductions. An IPCC [29] report predicts that certain regions will have wetter (or drier) conditions, which would affect both average and seasonal flows and thus reduce production. Under the conditions of increased climate variability, hydropower reservoirs play a significant role in climate adaptation by attenuating floods and droughts. In many places, small hydropower and run-of-river plants are preferable, because they have less negative impacts than those of large-scale dams. However, the significant questions are whether the impacts are high or low, and whether there are means of impact reduction possibilities that could be taken into consideration right from the beginning of any HEP plant planning and then construction.

1.14.2.10

Energy and Economy

Continuance of economic growth and prosperity rely heavily on adequate energy supply at reasonably low costs. As a whole, electricity production based on fossil or nuclear fuels induces substantial social and environmental costs whereas it would appear that the use of renewable energy sources involves far fewer and lower costs. There are a number of different energy cost categories that must be taken into consideration in the comparison of different energy resources and technologies; these are impact on human health, environmental damage, long-term cost of resource depletion, subsidies for research and development, cost of an increased probability of wars, cost of radioactive contamination of production equipment and dwellings after major nuclear accidents, and psychosocial cost [30]. Hydroelectricity cost is comparatively lower than those of any other renewable energy alternatives; and after the investment costs, it is even cheaper in the long-run. The nature of adaptation and mitigation decisions is costly and changes over time. Research and development may provide low-cost available alternatives allowing for a transition to low-carbon venting pathways. This is unlikely to happen overnight, but rather, through a set of cooperative decisions among involved shareholders. Such decisions have addressed the climatic risks (e.g., drought early-warning systems) and to be anticipatory or proactive (e.g., land-use management). Decisions might also slow trends by accelerating transitions with substantive jumps from one development or technological pathway to another [31–33]. There are many studies that focus on technology options, cost effectiveness, and energy market competition without consideration of the implications for adaptation. Natural-resource management sustainability is a focal point for economic growth and poverty reduction. It calls for clean energy sources such as hydropower, and the nature and pattern of agriculture, industry, and trade should not unduly impinge on ecological health and resilience. Swaminathan [33] and Yohe et al. [34] suggested “eco-technologies” (based on an integration of traditional and frontier technologies including biotechnologies, renewable energy, and modern management techniques) as a critical ingredient rooted in the principles of economics, gender, social equity, and employment generation with due emphasis given to climate change. Another way of economic savings is the optimum management of energy sources. For the optimization of energy consumption, the following issues should be addressed: 1. Anticipated long-term energy needs of a local place, country, or region must be taken into consideration for better development; 2. Public and private energy sectors should know their responsibilities and limitations in energy management and development; 3. Various impact assessments should be taken into consideration on a local, national, or regional basis. For instance, long-term assessments of climate change impacts expose significant effects [30]; 4. Clean, efficient, flexible, and dependable energy consumption must be carried out with integrated system credits and incentives;

Hydro Energy

619

5. In cases of serious problems, duly common decisions must be taken after mutual negotiations toward the solution of the problem at hand, especially concerning important structures without any delay; 6. Any decision at lower stages must be transferred without any delay to higher decision makers, who should take right and timely decisions with subsequent applications. Another problem is the optimum operation and management of the interconnected energy sources over the whole country during all times in an efficient manner. The management aspect of different sources presents by itself a major problem that should be solved adaptively by introduction of new alternatives such as nuclear and solar-hydrogen energy alternatives into the system.

1.14.3 1.14.3.1

Systems and Applications Comparison of Hydropower to Other Energy Forms

The sun’s energy is the main cause of wind to blow by heating air masses that rise, cool, and sink to the Earth again. Solar energy is at work continuously in sunlight rays, in air currents, and in the water cycle. The solar irradiation that reaches the Earth in one week is greater than all of the known coal, oil, and gas reserves. The seasonal, daily, and even hourly changes in the weather and energy from the wind and the sun are neither constant nor reliable, because peak production times do not always coincide with high power demand times. Intermittent solar and wind powers can be tied to major HEP systems for better economical and feasible circumstances. Hydropower can serve as an instant backup and meet peak demands. Wind power and hydropower link can add to the overall supply of electrical energy, and large wind plants can be tied with HEP plants. Dams save their water for later release to generate power in peak periods.

1.14.3.2

Hydropower, the Environment, and Society

By using water for power generation, people have worked with nature to achieve a better lifestyle. The mechanical power of falling water is a long-used tool, going back to as early as the 1700s. Governments with hydroelectric potential became involved in hydropower production because of their commitment to water resource management by dams that are significant electricity producers. In these countries, HEP generation has long been an integral part of their energy systems even as a byproduct of water development. In the early days of hydropower generation, new projects lacked many of the modern conveniences, one of these being electrical power. This made it desirable to take advantage of the potential power source in water. Hydropower was put to work lifting, moving, and processing materials to build the dams and dig canals. Power plants run sawmills, concrete plants, cableways, giant shovels, and draglines. Night operations are possible because of the lights fed by HEP. When constructions are complete, hydropower drives pumps that provide drainage or convey water to lands at higher elevations than could be served by gravity-flow canals. 1. Surplus power can be sold to existing power distribution systems in the area or even exported to nearby countries; 2. Local industries, towns, and farm consumers benefit from the low-cost electricity; 3. Much of the construction and operating costs of dams and related facilities were paid by sale of surplus power, rather than by the water users alone. This proved to be a great savings to irrigators struggling to survive; 4. Hydropower provides one of the best ways for rapidly expanding the region’s energy output. Addition of more power plant units makes it possible to expand energy production, and construction pushed ahead to speed up the availability of power; 5. The supply of low-cost electricity attracts large defense industries to the area such as shipyards, steel mills, chemical companies, oil refineries, and automotive and aircraft factories all of which needed vast amounts of electrical power; 6. Hydropower is vital for all industries that use mineral resources or farm products as raw materials. Many industries have depended wholly on hydropower; 7. Hydropower directly benefits rural areas by generating revenue, which contributes toward repayment of irrigation facilities by easing the water user’s financial burden and also by making power available for use on the farm for domestic purposes; 8. Hydropower is important from an operational standpoint as it needs no “ramp-up” time, as many combustion technologies do; 9. Hydropower can increase or decrease the amount of power it is supplying to the system almost instantly to meet shifting demand; 10. With these important load-following capability, peaking capacity, and voltage stability attributes, hydropower plays a significant part in ensuring reliable electricity service and in meeting customer needs in a market driven industry. In addition, hydroelectric pumped storage facilities are the only significant way currently available to store electricity; 11. Hydropower has the ability to provide peaking power and load following, and frequency control helps protect against system failures that could lead to the damage of equipment and even brown- or blackouts; 12. Hydropower, besides being emissions-free and renewable, has the above operating benefits that provide enhanced value to the electric system in the form of efficiency, security, and most important, reliability; 13. The electric benefits provided by hydroelectric resources are of vital importance to the success of any society for regulation of the electric industry.

620

Hydro Energy

1.14.4

Analysis and Assessment

The gross HEP potential is defined as the annual energy that is potentially available if all natural runoffs at all locations are to be harnessed down to the sea level (or to the transboundary line of a country) without any energy loss [35]. This chapter regards the sea level as river outlet. The gross power definition assumes no losses in the flow (discharge) for energy generation [36,37]. Frequently used classical methodologies for gross hydropower potential calculations are the HC and DF approaches.

1.14.4.1

Standard Hypsographic Curves

These curves represent the scaled down subarea ratios of any drainage basin versus corresponding height ratios. For this purpose, the drainage subareas, A1,A2,…,An (corresponding heights h1,h2,…,hn from the drainage area outlet) are divided by the total drainage area, AT, (the biggest height, HB). This is referred to as the standard HCs as shown in Fig. 6. In a drainage basin, the HC construction starts from the highest elevation point, HB, which is referred to as upstream input point, where the discharge value is equal to zero and descending toward the downstream lowest height, HL, the outlet point. At the outlet point the discharge has its maximum value. In general, any drainage area reflects one of the three standard HC shapes shown in Fig. 6 either as “young,” “mature,” or “old” depending on the geological process through millions of years. The evolution of any drainage basin is from the “young” to the “old” class over time. Each HC can also be classified according to the upstream; middle-stream, and downstream portions depending on the height classification. The shape of each standard HC helps to classify the geomorphological surface features and the possibility of HEP generation qualitatively. This classification provides preliminary general information about the hydropower potential at different portions of a drainage basin as follows: 1. Upstream: The height differences are comparatively lower in “young” (recent geological times) age HC than those of the other two, and the biggest is in the “old” case. It is further possible to classify the upstream parts as “low,” “medium,” and “high” hydropower potentials at “young,” “mature,” and “old” HCs, respectively; 2. Middle-stream: The “young” age has more HEP potential than its upstream portion; “mature” age remains almost the same, whereas the “old” HC has lower HEP potential than that of its upstream portion. Although HEP potential in case of “mature” HC remains the same, as the height decreases, the “young” (“old”) HC experiences HEP potential increase (decrease); 3. Downstream: The “young” age drainage basins have the highest HEP potentials; the “old” HC has the lowest potential, but the “mature” HC behaves as in the middle- and upstream cases.

Upstream

1.0

Height ratio

Young age

0.50

Middlestream

Time Downstream

Mature Time

Old age 45° 0

0.5

1.0

Area ratio Fig. 6 Different standard hypsographic curves (HCs). Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

Hydro Energy

621

The HC of the Euphrates and the Tigris rivers are in the “old” category, compared to the others within Turkish river basins [38]. Since Turkey has the headwaters of these rivers, more than 90% of HEP potential remains within the Turkish boundary. Especially from an agricultural point of view, the best locations are along the middle, and comparatively to a lesser extent, at the downstream portions. From this point of view, Syria has a better position than Iraq along the Euphrates River. It is clear to understand why Turkey has concentrated on the Euphrates and Tigris Rivers’ water sources for HEP generation and also for agricultural production in the southeastern region. For this purpose, Turkey started the Southeastern Anatolian Project (Güneydoğu Anadolu Projesi, GAP, Regional Development Plan) in the early 1980s, and implementation of this project is still going on. This project is expected to double Turkish agricultural products in addition to HEP generation when 19 generation plants are completed. The hydroelectric energy generation plants are among the largest in the world. Again, in the southeastern region of Turkey, due to the convenient HC of the Tigris River, the Ilısu Dam currently under construction is expected to generate additional 3800 GWh per year.

1.14.4.2

Numerical Power Calculation

In practice, there are few methodologies used for determining hydropower potential such as the HCs and DF approaches. However, these are not sensitive enough and do not have visual ability for pointing out hydroelectricity generation locations. In order to overcome such shortcomings, an effective approach is proposed under the name of ET, which incorporates two important quantities as the discharge and elevation difference in a continuous functional form. The gross hydropower potential is defined as the annual energy that is potentially available if all natural runoffs at all locations are to be harnessed down to the sea level (or to the transboundary line of a country) without any energy loss [36]. This study regards the sea level as the river outlet. The gross power definition assumes no losses in the flow (discharge) for energy generation [36,37]. In practical applications, HEP potential of a drainage basin is calculated by three classical and rather simple rational formulations that convert the discharge and height quantities into the hydropower amount. These are SP, DP, and subdrainage (SD) methodologies. The fourth one is suggested in the next section as the ET approach, which conceptually subsumes all three methods and provides a better and more refined calculation procedure. The first weakness of classical methods is that they are for only the river basins with low flow potentials and they cannot be generalized for every river and also they provide approximate results [15]. On the other hand, these methods give the opportunity to calculate theoretical gross power producible between the two points, but in between these two points cannot be considered. Another deficiency is their rough calculations, and therefore, they do not provide confidence to generalization. The classical methods have less visual ability, and give opportunity to graphically see the producible gross power between two points. Furthermore, they need precision measurements especially for the altitude.

1.14.4.2.1

Single-point method

This most commonly used practical formulation is useful for preliminary hydroelectric power, P, calculations, which is expressed as equal to g times the discharge, Q, multiplied by the falling head, H, as previously given in Eq. (1). The end product, P, is in kW. In order to assess the gross HEP potential of a drainage basin, most often the height and the discharge are taken at the outlet point of the drainage basin concerned. Due to the gross hydropower potential definition, since the annual energy that is potentially available if all natural runoffs at all locations are to be harnessed down to the sea level (or to the transboundary line of a country) without any energy loss [36], then Eq. (1) is not sufficient to cover the content of this statement. Furthermore, this consideration assumes no losses in the flow (discharge) for energy generation [37]

1.14.4.2.2

Double-point method

In the literature, this method is known as the DF approach. Eq. (1) does not take into consideration any geomorphologic parameters of the drainage basin such as the elevation differences along the main channel; and therefore, the results cannot be reliable. Height and discharge measurement considerations at two sites provide better results. In practice, two points are taken as the arithmetic average of the drainage basin height, hi, at the input point and another height, ho, at the outlet point. Hence, rational and logical thinking leads to another version of Eq. (1) as [37], P ¼ gðhi

ho Þ

Qi þ Qo 2

ð29Þ

where Qi and Qo are the discharges at the inflow and outlet points, respectively. This method has the following implicit assumptions: 1. The elevation difference assumes a linear height change between the two points, whereas most often in nature, there are nonlinear topographic variations between the two points; 2. The arithmetic average of the two discharges implies that there is a constant discharge, whereas in nature, depending on the geomorphologic features of the drainage basin between the inflow and outlet locations, the discharge accumulates with distance along the main channel and reaches its maximum value at the outlet; 3. Although the height difference is taken into consideration, this formulation does not consider the distance between the points.

622

Hydro Energy

1.14.4.2.3

Subdrainage method

In the literature, this is known as the HCs method. In the two previous methods, the drainage basin is considered as a single water catchment without any distinction between the discharges along the main channel and also from the subcatchments in terms of lateral discharge contributions. In the SD method, the power generation is thought of as the discharge along the main channel and lateral discharges with their respective and relevant elevations. If for a drainage basin, or any part of it, the water entrance (input) and exit (output) points’ elevations (hi and ho) are considered with input and output discharges (Qi and Qo), then the gross HEP can be thought of in two parts: 1. The input discharge generates HEP along the main channel until it reaches the output point, and during its travel the discharge falls from the height equal to (hi–ho); 2. The discharge amount that comes from the surface area of the drainage basin is equal to (Qo Qi). As for the falling head of this discharge the difference between the average drainage basin height, ha, and the outlet height, ho is considered as (ha–ho) [37]. P ¼ gðha

ho ÞðQo

Qi Þ þ gðhi

ho ÞQi

ð30Þ

The weighted average elevation value can be calculated according to the following expression, which is based on the hypsographical curve (HC) concept: Pn Ai hi ð31Þ ha ¼ Pi n¼ 1 i ¼ 1 Ai or in the case of continuous data availability, according to:

ha ¼

R Ao Ai

hðAÞ
dA

Ao

ð32Þ

Ai

where Ai and hi are the area and elevation of ith drainage subarea; and n is the number of subdrainage areas. This method yields better results in drainage basins with low flow potentials. In Fig. 7, the shaded area shows theoretically producible power between points a and b, by a linear variation consideration; due to this, the method has weakness on the physical base. DF also has less visual ability similar to HC as shown in Fig. 7(B). It gives the opportunity to graphically see the gross power producible only between two points. This method also gives the opportunity to calculate theoretically producible gross power only between the two points on the main river or the same distributaries. All the points between points a and b cannot be considered in the calculations.

1.14.4.2.4

Energy-tree model

The three classical methods provided in the previous section have restrictive assumptions. To overcome such shortcomings, a new approach, referred to as the energy-tree, ET, model is proposed in this section for refining the gross hydropower potential calculation. Conceptually, Fig. 8 represents a main basin with three subbasins of a river with areas (A1, A2, and A3) and corresponding elevations (h1, h2, and h3). The basic equation of ET includes two important parameters, the flow discharge and elevation difference, which are simply related to the summation of hydropower formulation as provided below: P¼g

N X

Qi ðHi

Hi 1 Þ

ð33Þ

i¼2

where Qi is the mean flow at the ith location with the elevation, hi, at the downstream location and hi-1 is the previous upstream point. Theoretically, Eq. (33) can be converted into an integration form as Z Ho P¼g QðhÞdh: ð34Þ Hi

This expression reflects the most refined HEP calculation, because the discharge along the main channel is dependent on the elevations and also discharges from the subbasins in a continuous manner. In Eq. (34), the discharge is shown as the function of elevation and since HC reflects a relationship between the elevation and the drainage area, Q (A). Hence, in the application of ET methodology the following steps are necessary: 1. Given n sampling points with discharges (Q1, Q2, … ,Qn) and corresponding subbasin areas (A1, A2, … , An) along the river for hydropower generation, it is possible to obtain an empirical relationship as Q¼ f(A)Q ¼f(A). It is well known from the literature that the relationship between the discharge and the drainage area is in the form of straight lines on double logarithmic paper [39]. Any straight line on double logarithmic paper is in the form of mathematical power function. In general, such an equation has the following mathematical expression with two parameters a and b: QðiÞ ¼ f ðAÞ ¼ a  Ai b The parameters can be calculated from the discharge and corresponding area data as follows: Pn  Pn  a¼e

i ¼1 n

lnðQi Þ

b

i¼ 1 n

ð35Þ

lnðAi Þ

ð36Þ

623

Hydro Energy

Elevation (m)

hi

ha

ho

Basin area (A, km2)

Elevation (m)

(A)

ha

hb

Qa

(B)

Discharge (m3 s-1)

Qb

Fig. 7 Classical approaches: (A) hypsographical curve (HC) method and (B) drawdown-flow (DF) method. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

A3 h3

A2 h2

A1 h1

Fig. 8 A typical river basin. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

b¼

n

Pn

n

Pn Pn lnðQi Þ i ¼ 1 lnðQi Þ:lnðAi Þ i ¼ 1 lnðAi Þ: Pi n¼ 1 2 Pn 2 Pn 2 ð ln ð A Þ Þ ð ln ð A Þ Þ i i i¼1 i¼1 i ¼ 1 Ai

ð37Þ

2. The availability of elevations (h1, h2, … , hn) helps to obtain another relationship between the basin areas and elevations as A¼ f (h);

624

Hydro Energy

Q5 h5, A5, P5

Q4 h4, A4, P4

Q3 h3, A3, P3

Q2 h2, A2, P2

Q1 h1, A1, P1 Q = Discharge h = Elevation A = Area P = Power Fig. 9 Representative energy-tree (ET) templates. Reproduced with permission from Alashan S. Nehir Hidroelektrik Enerji Potansiyelinin Hesaplanmasında Yeni Bir Yaklas¸ım (Enerji Ag˘acı Yöntemi) ve Murat Nehri Örneg˘i (A New Methodology for Determining River Gross Hydroelectric Energy Potential (Energy Tree) and An Application of Murat River), Doctorate Thesis, Istanbul Technical University, Istanbul; 2016.

3. The substitution of empirical Q ¼ f (h) expression into Eq. (34) and the completion of the integration operation yield the gross hydropower potential of concerned drainage basin. Since, the drainage areas, A, and heights, h, are related to each other by HC (see Fig. 8), it is possible to convert the Q (A) to Q (h) or vice versa. 4. A template for the main and subbasin areas is suggested in Fig. 9 with one main basin and four subbasins each with relevant quantities. This template looks like a tree, and therefore, the approach in this chapter is referred to as an energy tree, or ET. It is similar to a decision tree, a concept in statistics literature [40]. On the basis of this template, it is possible to calculate the gross hydropower from Eq. (33) or better from Eq. (34). The advantages of the ET methodology are that it gives opportunity to see or calculate the gross hydropower for each station on the different distributaries of any river (see Fig. 9). However, the HC and DF yield the gross power only between the two points, but the ET method calculates gross power by taking into consideration in between points. The two classical methods (HC and DF) are less visual. On the other hand, ET does not accept linearity between the gross power and discharge as well as between the gross power and altitude. So, one can state that ET has a physical base and can be generalized for any river or basin. These claims are comparatively summarized among the three methods in Table 1.

1.14.5

Case Studies

Murat River is the largest tributary of the Euphrates River within Turkey where the measurement stations are sparsely distributed in the basin (see Fig. 10). The elevation of the Euphrates River basin ranges from 3000 to 4000 m with a total area of 25,856 km2. The Murat River bed elevation ranges approximately from 850 to 1500 m. These variations are caused by tectonic and volcanic events, in addition to sudden river collapses [41]. The mean slopes are about 5% and 40% for 7156 km2 and 348 km2 of the total basin area, respectively. There are seven stations in the drainage area with mean annual discharge values obtained from State Hydraulic Works (DSI), Turkey. Figs. 11 and 12 present the scatter diagrams for discharge–area and discharge–elevation relationships and also continuous nonlinear functions that are straight lines on double logarithmic papers. The two relationships as already mentioned in steps (1) and (2) in the previous section have the following mathematical forms: Q ¼ 38:63  106 h

1:768

ð38Þ

625

Hydro Energy

Table 1

The comparison of methods

Criterion

Models

Limitation Generality Sensitivity Measurement precision Physical base Accuracy Mathematically Technically Utilization

ET (Exponential)

ET (Power)

DF

HC

No Generalizable Very high Moderate Exists Very high Sound Applicable Easy

No Generalizable High Moderate Exists High Sound Applicable Easy

Limited Limited Low Needed Low Low Sound Limited Easy

No Moderate Moderate Needed Low Moderate Sound Limited Easy

Abbreviations: ET, energy tree; HC, hypsographic curve; DF, drawdown-flow.

Black Sea

Mediterranian Sea

Station Provincial center Streams

Fig. 10 Location of Murat River and flow observation. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

and Q ¼ 1:574 A1:072

ð39Þ

On the other hand, the Hudson River watershed has two main branches; namely, the Upper Hudson River and the Mohawk River (see Fig. 13). The Upper Hudson River extends 257 km (160 miles) from Lake Tear of the Clouds in the Adirondack Mountains 1317 m (4322 feet) above the mean sea level to the Federal Dam at Troy [42]. The upper Hudson River has a drainage basin area of 9772 km2 (4590 square miles) [43]. The upper Hudson is a wild high-gradient (2.6 m/km) river largely unaffected by gross human impacts and the seasonal flow characteristics are close to their natural state [44].

626

Hydro Energy

105

Discharge, Q, (m3 s−1)

104 Q = 38.63.106.h–1.768 103

102

101

100 102

103

104

Elevation, h, (m) Fig. 11 Murat River height and discharge relationship. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

Discharge, Q, (m3 s−1)

103

Q = 0.0075.A1.025

102

101 103

104

105

Area, A, (km2) Fig. 12 Murat River discharge and area relationship. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

There are five stations with annual flow measurements between 2003 and 2013 on the main distributary of the Upper Hudson River. These stations are named as 01331095, 01327750, 01318500, 01315500, and 01312000 from downstream to upstream in respective order. Figs. 14 and 15 present the scatter diagrams for discharge–area and discharge–elevation relationships and also continuous nonlinear functions that are straight lines on double logarithmic papers. The two relationships as already mentioned in steps (1) and (2) in the previous section have the following mathematical forms: Q ¼ 910h

0:5

ð40Þ

and Q ¼ 0:0236A0:98

1.14.5.1

ð41Þ

Hydropower Applications

In the application of the three methodologies, the minimum elevation is adapted as the reference level for hydropower assessment within drainage basins. For this purpose, in the HC and DF calculations the minimum elevation is subtracted from absolute

Hydro Energy

627

Maine V.T. N.H.

Mass. Conn.

01312000

P.A.

er Riv on o r ch

N.J. Indian

r

S

01315500

Rive

01318500

H

ud

Sa

son

ca

nd

ag

aR

ive

r

Lake

AT L OC AN EA TIC N

New York

Lake Tear of The Clouds

Upper

Batten

Hoosic

Station

01327750

Hudson Falls

CORINTH

kill

01331095

River

Provincial center Streams

Fig. 13 Location of Hudson River and flow observation stations. Reproduced with permission from Geyer RW, Chant R. The physical oceanography processes in the Hudson River Estuary. In: Levinton JS, Waldman JR, editors. The Hudson River Estuary. New York, NY, Cambridge University Press; 2006.

elevations at station locations. The values used are the mean measurements for the two rivers. Figs. 16 and 17 represent power values for three methods and all years.

1.14.5.1.1

Murat River power and energy potential

1.14.5.1.1.1 Hypsographical curve method By consideration of the average outflow elevations with subbasin drainage areas as weights, one can numerically obtain from Eq. (32), ha ¼

R 25515 5882

ð 1:181  10

6  A2 25; 515

0:001783  A þ 1582ÞdA ¼ 1225 m 5882

Using Eq. (30) for hydropower calculation, water specific discharge is adapted as g¼ 9.781 kN/m3 at 251C and the substitution of all the relevant numerical values into this expression yields P ¼ 9:781  ð1225

859Þ  ð230:84

46:19Þ þ 9:781  ð1552

Hence, the corresponding energy value is 974.10  8765 ¼8765 GWh

859Þ  46:19 ¼ 974:10 MW

628

Hydro Energy

Discharge, Q, (m3 s−1)

103

Q = 910.h–0.5 102

101 101

102

103

Elevation, h, (m) Fig. 14 Hudson River height and discharge relationship. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

Discharge, Q, (m3 s−1)

103

Q = 0.0236.A0.98 102

101 102

103

104

Area, A, (km2) Fig. 15 Hudson River discharge and area relationship. Reproduced with permission from Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi: 10.1007/s13369-015-1982-5.

1.14.5.1.1.2 Drawdown-flow method For the application of this methodology, Eq. (29) is considered and the substitution of the numerical values into this expression gives P ¼ 9:781  ð1552

1241Þ  ð127:33 þ 46:19Þ=2 þ ð1241

859Þ  ð230:84 þ 127:33Þ=2 ¼ 933:04 MW

Its corresponding energy equivalent is then 933.04  8765 ¼ 8178 GWh 1.14.5.1.1.3 Energy-tree method The hydropower calculation formulation in Eq. (34) needs continuous functional relationships between the discharge and the height, which has generally been given in Eq. (38) together with the relevant coefficient values. The substitution of the relevant values into Eq. (34) leads to Z 1552    P ¼ 9:781  0:7745  h0:8691 þ 505:6 dh ¼ 930:80 MW 859

E ¼ 930:80  8765 ¼ 8158 GWh The repetition of similar calculations for each year gives the time variation profile of the HEP for the Murat River in Fig. 16 and relevant coefficients given in Table 2.

629

Hydro Energy

HE 1400 DF Power (MW)

1200

ET

1000 800 600

1983

1982

1981

1980

1979

1978

1977

1976

1975

1974

1973

1972

1971

1970

400

Years Fig. 16 Murat River basin power potentials. Reproduced with permission from Alashan S. Nehir Hidroelektrik Enerji Potansiyelinin Hesaplanmasında Yeni Bir Yaklas¸ım (Enerji Ag˘acı Yöntemi) ve Murat Nehri Örneg˘i (A New Methodology for Determining River Gross Hydroelectric Energy Potential (Energy Tree) and An Application of Murat River), Doctorate Thesis, Istanbul Technical University, Istanbul; 2016.

HE DF

Power (MW)

ET 400

200 2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

Years Fig. 17 Hudson River basin power potentials. Reproduced with permission from Alashan S. Nehir Hidroelektrik Enerji Potansiyelinin Hesaplanmasında Yeni Bir Yaklas¸ım (Enerji Ag˘acı Yöntemi) ve Murat Nehri Örneg˘i (A New Methodology for Determining River Gross Hydroelectric Energy Potential (Energy Tree) and An Application of Murat River), Doctorate Thesis, Istanbul Technical University, Istanbul; 2016.

Table 2

Discharge–elevation equation coefficients

Murat River

Hudson River

Years

a

1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983

0.5846 6406 0.2309 0.0007741 0.006766 0.4975 4.16 3.012 55.5 26.93 11,930 7.188 0.0004752 0.000005847

b

c 0.8782 0.3042 1.016 1.705 1.455 0.9048 0.7124 0.7285 0.4094 0.4344 0.04427 0.6042 1.838 2.341

Years 411.2 649.9 454.5 260.3 331.2 424.5 842 683.4 1186 698.5 8564 646.8 401.2 211.2

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

a 358.5 148.7 198.2 126 167.3 146 184.7 195.5 33.84 234.7 83.2

b

c

0.09514 0.1871 0.1464 0.2197 0.1771 0.1868 0.1583 0.1436 0.3841 0.1259 0.235

657.2 487.4 501.5 508.3 515.2 479.9 505.5 486.7 381.3 522.7 368.7

630

Hydro Energy

It is obvious from the comparison of these three calculation methodologies that the refined calculations are provided by the ET method, which takes into consideration not discrete station elevations and discharges, but a functional rule between the elevation and discharge as in Eq. (6).

1.14.5.1.2

Hudson River power and energy potential

1.14.5.1.2.1 Hypsographical curve method The weighted average outflow elevation by considering subbasin drainage areas as weights one can obtain numerically that (see Eq. (32)) R 9772 ð6:117  10 6  A2 0:1106  A þ 519:2ÞdA ¼ 156:43 m ha ¼ 497 9772 497 With all the relevant numerical values substitution into Eq. (30) yields the final result as P ¼ 9:781  ð156:43

24:08Þ  ð222:87

14:32Þ þ 9:781  ð472:44

24:08Þ  14:32 ¼ 332:73 MW

It is possible to calculate simply the corresponding energy amount as 332.73  8765 ¼ 2916 GWh. 1.14.5.1.2.2 Drawdown-flow method Similar to the calculations for the Murat River, this time the substitution of Hudson River values into Eq. (29) results as 52:49 þ 14:32 þ ð300:99 2 222:87 þ 176:28 ¼ 354:22 MW þ ð30:48 24:08Þ  2 Its energy equivalent is then 354.22  8765¼3104 GWh.

P ¼ 9:781  ð472:44

300:99Þ 

171:9Þ 

98:76 þ 52:49 þ ð171:9 2

30:48Þ 

176:28 þ 98:76 2

1.14.5.1.2.3 Energy-tree method Eq. (34) is the basic expression for this suggested methodology that requires a functional relationship between the discharge and elevation and consideration of the power functional form in Eq. (40) and the corresponding coefficient values in Table 2 gives Z 472:44   P ¼ 9:781  128:2  h0:1967 þ 446:6 dh ¼ 343 MW 24:08

E ¼ 343  8765 ¼ 3011 GWh The Hudson River power time profile is presented in Fig. 17 for the three methodologies used in this paper. As seen from the comparison of Figs. 16 and 17, ET and DF give rather close results, but the power variation domain is wider for the Murat River than that for the Hudson River, which is due to the fact that in the Hudson basin there are more stations on the main stream. Usually, water structures such as dams are not constructed near the stations; and therefore, it is important to interpolate values among stations so as to calculate the necessary values at the structure location. The HE method cannot calculate intermediate values among the stations, but is capable of calculating only the hydroelectric potentials for all basins. On the other hand, the ET and DF methods are capable of calculating the intermediate values among the stations. These two methods are tested as to their success in calculating intermediate values among the stations. For this purpose, a set of points are selected among the stations on the main stream. At these points, values are unknown. For the validation of the proposed model, 01327750, 01318500, and 01315500 stations are treated as points, where known values are assumed as unknown. The values at these stations are calculated from the known stations, and the relative errors are calculated as HEP difference per meter according to ET and DF methods and the results are presented in Fig. 18. Although the three methods are applied to four rivers, herein only the Hudson and Murat Rivers are presented. In the application of the three methodologies the minimum elevation is adapted as the reference level for hydropower assessment within drainage basins. The value that corresponds to 50% risk level of lognormal distribution is taken as the annual mean of discharge for both the Hudson and Murat Rivers. In order to determine the energy and power values first, the weighted average elevation is calculated from Eq. (32) by considering the drainage area of all the subbasins. R 25;515 ð 1:181  10 6  A2 0:001785  A þ 1582ÞdA ¼ 1225 m haðMuratÞ ¼ 5882 25; 515 5882 haðHudsonÞ ¼

R 9772 497

ð6:117  10

6

 A2 0:1106  A þ 519:2Þ
dA ¼ 156:43 m 9772 497

Later, Eqs. (29), (30), and (34) are used to calculate power and energy amount for both the Murat and Upper Hudson River basins. The results are presented in Table 3. It is obvious from the comparison of these three calculation methodologies that the refined calculations are provided by the ET method, which takes into consideration not only discrete station elevations and discharges, but also a general rule between the

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ET 800 DF

600 500 400 300 200 100

2013

2012

2011

2010

2009

2008

2007

2006

2005

–100

2004

0

2003

Power differance errors (MW/m)

700

–200 Years Fig. 18 Hudson River basin power difference errors. Reproduced with permission from Alashan S. Nehir Hidroelektrik Enerji Potansiyelinin Hesaplanmasında Yeni Bir Yaklas¸ım (Enerji Ag˘acı Yöntemi) ve Murat Nehri Örneg˘i (A New Methodology for Determining River Gross Hydroelectric Energy Potential (Energy Tree) and An Application of Murat River), Doctorate Thesis, Istanbul Technical University, Istanbul; 2016. Table 3

Power and energy values

Method

Murat basin

HC DF ET

Table 4 Streams

Hudson

Murat

Hudson basin

Power (MW)

Energy (GWh)

Power (MW)

Energy (GWh)

1017.94 956.65 1022.80

8922.26 8385.01 8965.10

291.02 307.10 303.35

2550.80 2691.73 2658.86

Hydropower potentials and relative errors in study areas Number of considered stations

5 4 3 2 3 2

Potential power

Relative error

ET (Exponential)

ET (Power)

DF

HC

ET (Exponential)

ET (Power)

DF

303.35 295.15 319.10 287.83 892.62 793.43

305.77 268.90 279.86 149.24 864.07 735.32

307.10 333.43 344.80 457.54 956.65 1335.51

291.02 No change

0.00 2.70 5.19 5.12 0.00 11.11

0.00 12.06 8.47 51.19 0.00 14.90

0.00 8.57 12.28 48.99 0.00 39.60

1017.94 No change

HC

Abbreviations: ET, energy tree; HC, hypsographic curve; DF, drawdown-flow. In order to modify Eqs. (38) and (39), the data obtained from seven stations are used; whereas for determining the power potential, only the three located on the main distributary are taken into consideration.

elevation and discharge as given in Eqs. (38) and (40). In general, the relationship between the basin area and altitude graphically occurs as convex (young age), approximately linear (mature age), and concave (old age) depending on the geological formations within the drainage basins. The Murat River runs on young aged geological regions. So the relationship between discharge and altitude is shaped as a convex curve and has higher power potential according to the DF method. The ET method determines the relationship as exponential, power, and polynomial between discharge and altitude of streams, and gives more realistic results compared to the classical methods. There are insufficient stations established along the main river body for annual flow measurement. Therefore, the methods should give the possibility to express the discharge–altitude relationship with insufficient station number. As one can see from Table 4, the greater the number of stations, the bigger is the decrease in the difference among ET and other methods. On the other hand, ET is not affected by insufficient station number. This shows that ET is more robust than the others. For the Murat River potential energy (PE), yield according to different methods shows that PEETEPEHC4PEDF. In other

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Table 5 Method

SP DP ET Between ET-SP ET-DP DP-SD

Gross hydropower potential of the Murat River Power (MW)

(GWh)

956.65 1017.94 1022.80 Relative error (%) 6.5 0.5 6.0

8922.26 8385.01 8965.10

words, ET yields relatively more energy than those of the two more commonly used methodologies with 0.4% and 7% relative error, respectively. However, in the Hudson River case, PEDFEPEET4PEHC. In other words, the ET method yields approximately the same energy as DF, but more energy than that of HC. In the application of the three methodologies (SP, DP, and ET), the minimum elevation is adapted as the reference level for hydropower assessment within the Murat River drainage basin. For this purpose, in the DP and SD method calculations, the minimum elevation is subtracted from absolute elevations at seven locations. In the calculations, the specific weight of water is taken as g¼ 9.781 kN/m3 at 251C, which is the average monthly temperature in the study area. The results from the three methods are presented in Table 5. The comparison of these three methods is based on the calculation of the relative error, which indicates percentage difference between the methods. The last three rows provide the relative error percentages. It is possible to see that the ET approach improves the calculations significantly. In general, the gross hydropower output calculations yield in a sequence as ET4SD4DP. The use of the refined calculation methodology provides improvement from 0.4% to 6.5% in the hydroelectric energy calculation at the planning stage. In practical applications, many basins may not have discharge records, which makes the application of the gross hydropower potential formulations impossible. However, use of discharge calculation methodology by Farmer and Vogel [45] for nongaged drainage basins help to predict discharge values at any desired point along the main channel, and hence, the application of the ET method becomes applicable. Additionally, for hydropower energy potential, the height and area quantities are obtained through the GIS work as suggested by [18,37]. For any country to evaluate its gross hydropower potential, refined calculation methodologies are necessary on the basis of each drainage area. For this purpose, currently employed classical formulations are revised in terms of SP, DP, and SD methodologies; and after their critiques, for more refined calculations, a new methodology is suggested as the ET approach. Refined hydropower calculations in practical studies are necessary and for this purpose in this chapter, an effective method, namely, the ET model is introduced with its application to the data sets from Turkey and the United States. The proposed method aims to combine the advantages of two frequently used methods that are available in the current literature, namely, HCs and the DF. In the calculations, it becomes necessary to consider empirical elevation–discharge and elevation–area relationships in the forms of mathematical power functions according to geological structure on streams. These functions help to calculate the discharge at any point within the drainage basin provided that the elevation is given for any desired point. When the results of applications are considered collectively, it is possible to conclude that ET yields more energy and is also more robust than the HC and DF methods. On the other hand, the proposed method yields more refined and physically plausible results in spite of an insufficient number of stations. The main ramification in the application of the ET method is to consider the nonlinear relationship (power, polynomial or exponential function) between the elevation and discharge in the drainage basin.

1.14.6 1.14.6.1

Overall Recommendations Energy Consumption Optimization

For the successful optimization of energy consumption the following issues should be addressed: 1. Anticipated long-term energy needs of a local place, country, or region must be taken into consideration for better development; 2. Public and private energy sectors should know their responsibilities and limitations in the energy management and development; 3. Various impact assessments should be taken into consideration on a local, national, or regional basis. For instance, long-term assessments of climate change impacts expose significant effects [29]; 4. Clean, efficient, flexible, and dependable energy consumptions must be carried out with integrated system credits and incentives;

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5. In the case of important problems, duly common decisions must be taken after mutual negotiations toward the solution of the problem at hand, especially concerning important structures, without any delay; 6. Any decision at lower stages must be transferred without any delay to higher decision makers, who should take right and timely decisions with subsequent applications. Another problem is the optimum operation and management of the interconnected energy sources across the whole country during all times in an efficient manner. The management aspect of different sources presents by itself a major problem that should be solved adaptively by introduction of new alternatives such as nuclear and solar-hydrogen energy alternatives into the system.

1.14.6.2

Ways to Save Energy

In order to care for future generations, energy conservation is very essential. Toward this end, one has to consider the following points: 1. Conservation and more efficient use of energy. Since the first energy crisis, this has been the most cost-effective mode of operation. It is much cheaper to save a barrel of oil than to discover new oil; 2. Reduce demand to zero growth rate and begin a steady state society; 3. Redefine the size of the system and colonize the planets and space. For instance, the resources of the solar system are infinite and our galaxy contains over 100 billion stars; 4. Because the Earth’s resources are finite, a change to a sustainable society, which depends primarily on renewable energy, becomes imperative on a long-term scale. The following adaptation and mitigation policies are important for enhancement works in every society: 1. 2. 3. 4.

Practice conservation and efficiency; Increase the use of renewable energy; Continue dependence on natural gas, and Use coal, but include all social costs (externalities). Regional and local policies must be the same. Efficiency can be improved in all major sectors: residential, commercial, industrial, transportation, and even the primary electrical utility industry. The most gains can be accomplished in the transportation, residential, and commercial sectors. National, state, and even local building codes will improve energy efficiency in buildings. Finally, there are a number of things that each individual can do in conservation and energy efficiency. Human settlements are integrators of many of the climate impacts initially felt in other sectors and differ from each other in geographic location, size, economic circumstances, and political and institutional capacity. As a consequence, it is difficult to make blanket statements concerning the importance of climate or climate change that will not have numerous exceptions. However, classifying human settlements by considering pathways by which climate may affect them, size or other obvious physical considerations, and adaptive capacities (wealth, education of the populace, technological and institutional capacity) helps to explain some of the differences in expected impacts. Human settlements are affected by climate in one of three major ways:

1. Economic sectors that support the settlements are affected because of changes in productive capacity (e.g., in agriculture or fisheries) or changes in market demand for goods and services produced there (including demand from people living nearby and from tourism). The importance of this impact depends in part on whether the settlement is rural – which generally means that it is dependent on one or two resource-based industries – or urban, in which case there is usually (but not always) a broader array of alternative resources. It also depends on the adaptive capacity of the settlement. 2. Some aspects of physical infrastructure (including energy transmission and distribution systems), buildings, urban services (including transportation systems), and specific industries (such as agroindustry, tourism, and construction) may be directly affected. For example, buildings and infrastructure in deltaic areas may be affected by coastal and river flooding; urban energy demand may increase or decrease as a result of changed balances in space heating and space cooling; and coastal and mountain tourism may be affected by changed seasonal temperature and precipitation patterns and sea-level rise. Concentration of population and infrastructure in urban areas can mean higher numbers of persons and higher value of physical capital at risk, although there also are many economies of scale and proximity in ensuring well-managed infrastructure and service provision. When these factors are combined with other prevention measures, risks can be reduced considerably. However, some larger urban centers in Africa, Asia, Latin America, and the Caribbean, as well as smaller settlements (including villages and small urban centers), often have less wealth, political power, and institutional capacity to reduce risks in this way. 3. Population may be directly affected through extreme weather, changes in health status, or migration. Extreme weather episodes may lead to changes in deaths, injuries, or illness. For example, health status may improve as a result of reduced cold stress or deteriorate as a result of increased heat stress and disease. Population movements caused by climate changes may affect the size and characteristics of settlement populations, which in turn changes the demand for urban services. The problems are somewhat different in large population centers (e.g., those of more than 1 million population) and midsized to small-sized regional centers. The former are more likely to be destinations for migrants from rural areas and smaller settlements and crossborder areas, but larger settlements generally have much greater command over national resources. Thus, smaller settlements

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actually may be more vulnerable. Informal settlements surrounding large and medium-size cities in the developing world remain a cause for concern because they exhibit several current health and environmental hazards that could be exacerbated by global warming and have limited command over resources.

1.14.6.3

Hydropower Glossary

After all that has been explained in the previous sections the following basic and fundamental definitions can help to grasp the basic concepts firmly. Alternating current: An electric current changing regularly from one direction to the opposite. Ampere: The common unit of measurement of electrical current. Baseload: The minimum constant amount of load connected to the power system over a given time period, usually on a monthly, seasonal, or yearly basis. Baseload plant: A plant, usually housing high-efficiency steam-electric units, which is normally operated to take all or part of the minimum load of a system, and which consequently produces electricity at an essentially constant rate and runs continuously. These units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs. Bus (buswork): A conductor, or group of conductors, that serves as a common connection for two or more electrical circuits. In power plants, buswork comprises the three rigid single-phase connectors that interconnect the generator and the step-up transformer(s). Capability: The maximum load that a generating unit, generating station, or other electrical apparatus can carry under specified conditions for a given period of time without exceeding approved limits of temperature and stress. Capacity: The amount of electric power delivered or required for which a generator, turbine, transformer, transmission circuit, station, or system is rated by the manufacturer. Circuit: A conductor or a system of conductors through which electric current flows. Current (electric): A flow of electrons in an electrical conductor. The strength or rate of movement of the electricity is measured in amperes. Dam: A massive wall or structure built across a valley or river for storing water. Demand: The rate at which electric energy is delivered to or by a system, part of a system, or a piece of equipment. It is expressed in kilowatts, kilovolt amperes, or other suitable units at a given instant or averaged over any designated period of time. The primary source of “demand” is the power-consuming equipment of the customers. Direct current: Electric current going in one direction only. Distribution system: The portion of an electric system that is dedicated to delivering electric energy to an end user. The distribution system “steps down” power from high-voltage transmission lines to a level that can be used in homes and businesses. Energy: The capacity for doing work as measured by the capability of doing work (potential energy) or the conversion of this capability to motion (kinetic energy). Energy has several forms, some of which are easily convertible and can be changed to another form useful for work. Most of the world’s convertible energy comes from fossil fuels that are burned to produce heat that is then used as a transfer medium to mechanical or other means in order to accomplish tasks. Electrical energy is usually measured in kilowatt-hours and represents power (kilowatts) operating for some time period (hours), while heat energy is usually measured in British thermal units. Generation (electricity): The process of producing electric energy by transforming other forms of energy; also, the amount of electric energy produced, expressed in watthours (Wh). Generator: A machine that converts mechanical energy into electrical energy. Head: The difference in elevation between the headwater surface above and the tail-water surface below a HEP plant under specified conditions. Horsepower: A unit of rate of doing work equal to 33,000 foot pounds per minute or 745.8 W (Brit.), 746 W (United States), or 736 W (Europe). Hydroelectric power: Electric current produced from water power. Hydroelectric power plant (HEPP): A building in which turbines are operated to drive generators, using the energy of natural or artificial waterfalls. Kilowatt (kW): Unit of electric power equal to 1000 W or about 1.34 horsepower. For example, it is the amount of electric energy required to light ten 100-watt light bulbs. Kilowatt-hour (kWh): The unit of electrical energy commonly used in marketing electric power; the energy produced by 1 kW acting for 1 h. Ten 100-watt light bulbs burning for 1 h would consume one kilowatt-hour of electricity. Kinetic energy: Energy that a moving body has because of its motion, dependent on its mass and the rate at which it is moving. Load (electric): The amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy-consuming equipment of the consumers. Megawatt: A unit of power equal to one million watts. For example, it is the amount of electric energy required to light 10,000 100-watt bulbs. Ohm: Electrical resistance measurement unit. The resistance of a circuit when a potential difference of one volt produces a current of one ampere.

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Peak load: The greatest amount of power given out or taken in by a machine or power distribution system in a given time. Power: Mechanical or electrical force or energy. The rate at which work is done by an electric current or mechanical force, generally measured in watts or horsepower. Pumped storage: A plant that usually generates electric energy during peak-load HEP plant periods by using water previously pumped into an elevated storage reservoir during off-peak periods when excess generating capacity is available to do so. When additional generating capacity is needed, the water can be released from the reservoir through a conduit to turbine generators located in a power plant at a lower level. Rated capacity: Hydro generator is the capacity that can deliver without exceeding mechanical safety factors or a nominal temperature rise. In general, this is also the nameplate rating except where turbine power under maximum head is insufficient to deliver the nameplate rating of the generator. Reservoir: An artificial lake into which water flows and is stored for future use. Turbine: A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam, or hot gas). Turbines convert the kinetic energy of fluids to mechanical energy through the principles of impulse and reaction, or a mixture of the two. Volt (V): The unit of electromotive force or potential difference that will cause a current of one ampere to flow through a conductor with a resistance of one ohm. Watt (W): The unit used to measure production/usage rate of all types of energy; the unit for power. The rate of energy transfer equivalent to one ampere flowing under a pressure of one volt at unity power factor. Watt-hour (Wh): The unit of energy equal to the work done by one watt in 1 h. Although most energy in the world is produced by fossil-fuel and nuclear power plants, hydroelectricity is still important for many countries and it accounts for about 20% of world total energy production. Water flows through the dam’s spin turbine blades (made out of metal instead of leaves), which are connected to generators. Power is produced and is sent to homes and businesses.

1.14.7

Modern Concepts and Future Role

Hydropower does not discharge pollutants into the environment; however, it is not free from adverse environmental effects. Considerable efforts have been made to reduce environmental problems associated with hydropower operations, such as providing safe fish passage and improved water quality in the past decade. Dam safety endurance efforts can be achieved in the best possible manner by means of fast and more accurate computer software for optimization of the operations in addition to innovative new technologies’ support for environmental improvements. These facilities open the best ways to maintain the economic viability of hydropower depending on demand increase also. Furthermore, research and development programs are helpful for improvement of the operation efficiency and the environmental performance of hydropower facilities. Today, hydropower research and development are still important for water resources management, fish passage, turbine responses, and dam safety related also to hydropower generation. Reclamation is significant for improvement of the reliability and efficiency of hydropower generation. The main purpose is to increase production and efficiency. The major points in hydropower concepts and approaches are uprating existing power plants, developing small plants (low-head hydropower), peaking with hydropower, and pumped storage and hydropower relationships to other renewable energy. For additional HEP one of the most immediate, cost-effective, and environmentally acceptable means is the uprating of existing hydroelectric generator and turbine units at power plants. Various power plants are used to meet peak electrical energy demands, rather than operating around the clock to meet the total daily demand. Increasing use of other energy-producing power plants in the future will not make HEP plants obsolete or unnecessary. On the contrary, hydropower can be even more important. While different power plants including nuclear, fossil-fuel burning, wind, solar, wave, tide, and geothermal can provide baseloads, hydroelectric plants can more economically deal with varying peak load demands.

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In: Singh JS, Sharma VP, editors. Glipses of the work on environment in India. Angkor, New Delhi 2005 51–71. [34] Yohe GW, Lasco RD, Ahmad QK, et al. Perspectives on climate change and sustainability. In: Parry ML, Canziani OF, Palutikof JP, van der Linken PJ, Hanson CE, editors. Climate change: impacts, adaptation and vulnerability. Cambridge, UK: Cambridge University Press; 2007. p. 811–41. [35] Eurelectric, Study on the importance of harnessing the hydropower resources of the world, Union of the Electric Industry (Eurelectric), Hydro Power and other Renewable Energies Study Committee, Brussels; 1997. [36] Cuya DGP, Brandimarte L, Popescu I, et al. A GIS-based assessment of maximum potential hydropower production in La Plata basin under global changes. Renew Energy 2013;50:103–4. doi:10.1016/j.renene.2012.06.019. [37] Alashan S, S¸en Z, Toprak ZF. Hydroelectric energy potential of turkey: a refined calculation method. Arab J Sci Eng 2016;41:1511–20. doi:10.1007/s13369-015-1982-5. [38] S¸en Z. Terrain topography classification for wind energy generationTerrain topography classification for wind energy generation. Renew Energy 1999;16:904–7. [39] Alashan S. Nehir Hidroelektrik Enerji Potansiyelinin Hesaplanmasında Yeni Bir Yaklas¸ım (Enerji Ag˘acı Yöntemi) ve Murat Nehri Örneg˘i (A New Methodology for Determining River Gross Hydroelectric Energy Potential (Energy Tree) and An Application of Murat River), Doctorate Thesis, Istanbul Technical University, Istanbul; 2016. [40] Benjamin JR, Cornell CA. Probability, statistics and decisions for civil engineers. New York, NY: McGraw-Hill; 1970. p. 684. [41] Günek H. Murat NehriHavzasının (Fırat) Su PotansiyeliveDegerlendirilmesi (Hydropower Potential and Its Assessing in Murat River Basin). Eastern Geogr Rev 2006;16:141–64. [42] Geyer RW, Chant R. The physical oceanography processes in the Hudson River Estuary. In: Levinton JS, Waldman JR, editors. The Hudson River Estuary. New York, NY: Cambridge University Press; 2006, p. 24. [43] United States Geological Survey (USGS), US, NATIONAL WATER QUALITY ASSESSMENT PROGRAM – The Hudson River Basin. Available from: http://ny.water.usgs.gov/ projects/hdsn/fctsht/su.html#HDR0/; 2016 [accessed 21.07.16]. [44] Jackson JK, Huryn AD, Strayer DL, Courtemanch DL, Sweeney BW. Atlantic Coast rivers of the Northeastern United States. In: Benke AC, Cushing CE, editors. Rivers of North America. San Diego, CA: Elsevier; 2005, p. 37. [45] Farmer W, Vogel RM. Performance-weighted methods for estimating monthly stream flow at ungauged sites. J Hydrol 2013;477:240–50.

Further Reading American Society of Civil Engineering. Hydrology Handbook, ASCE Manuals and Reports on Engineering Practice, 28, United States of America; 1996. Coskun HG, Alganci U, Eris E, et al. Remote sensing and GIS innovation with hydrologic modelling for hydroelectric power plant (HPP) in poorly gauged basins. Water Resour Manag 2010;24(14):3757–72. doi:10.1007/s11269-010-9632-x. Dudhani S, Sinhaand AK, Inamdar SS. Assessment of small hydropower potential using remote sensing data for sustainable development in India. Energy Policy 2006;34:3195–205. doi:10.1016/j.enpol.2005.06.011. Tapiador FJ. Assessment of renewable energy potential through satellite data and numerical models. Energy Environ Sci 2009;2:1142–61. doi:10.1039/B914121A. Toprak ZF, Eris E, Agiralioglu N, et al. Modeling monthly mean flow in a poorly gauged basin by fuzzy logic. CLEAN-Soil Air Water 2009;37(7):555–64. doi:10.1002/ clen.200800152.

Hydro Energy

Relevant Websites http://hgenergy.com/index.php Hydro Green Energy. https://www.hydropower.org/ International Hydropower Association. https://water.usgs.gov/edu/wuhy.html U.S. Geological Survey.

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1.15 Solar Energy Ilhami Yildiz, Dalhousie University, Truro-Bible Hill, NS, Canada r 2018 Elsevier Inc. All rights reserved.

1.15.1 Introduction 1.15.2 Light and Solar Physics 1.15.2.1 Light as Waves 1.15.2.2 Light as Particles 1.15.2.3 Solar Physics 1.15.3 Source of the Sun’s Energy 1.15.4 The Radiation Laws 1.15.5 Characteristics of Solar Radiation 1.15.5.1 The Solar Constant 1.15.5.2 The Solar Spectrum 1.15.5.3 Solar Time 1.15.5.4 Solar Geometry 1.15.5.5 Solar Radiation 1.15.5.6 Solar Angle 1.15.5.7 Atmospheric Effects 1.15.5.7.1 Direct normal solar radiation 1.15.5.7.2 Diffuse solar radiation 1.15.6 Insolation Levels at the Earth’s Surface 1.15.7 Concluding Remarks References Relevant Websites

639 639 639 640 640 641 641 642 642 643 646 647 648 649 651 652 653 654 664 664 664

Nomenclature a A AST B c C d E ET F FPC Gm h H Hz I J

Constant (2897 mm K); or (0.1996 d (Gm) 3/2) Albedo; apparent incoming solar radiation at air mass ¼ 0 (W m 2) Apparent solar time (minutes) Dimensionless ratio Speed of light (3  108 m s 1); constant; dimensionless ratio Diffuse radiation factor (dimensionless), degree celsius Day; Julian day (number); number of days per year (365) Amount of energy (J s 1, J m 2 s 1, MJ m 2 s 1 or W m 2 mm 1); east Equation of time (minutes) Angle factor (dimensionless) Flat plate collector Gigameter Planck constant (6.626  10 34 J s) Hour angle (degree of arc) Hertz (cycle s 1) Amount of solar radiation (W m 2) Joule

Greek letters b Solar altitude (degree of arc) δ Solar declination (degree of arc) D Difference

638

K L LON LSMT LST m M N NE NW Q QOP QOV R S SE ST SW T W Y

Absolute temperature Local latitude (degree of arc) Local longitude (degree of arc) Longitude of the standard time meridian (o of arc) Local solar time (degree of arc) Mass (kg); meter Mega North Northeast Northwest Amount of heat energy (J, kJ or MJ) Incident angle for the vertical surface (o of arc) Angle of incidence (degree of arc) Radius (m or km) South Southeast Standard time (degree of arc) Southwest Temperature (oC or K) Watt; west Time period (days)

e f F g

Emissivity Solar azimuth angle (degree of arc) Tilt angle of the Earth (degree of arc) Surface solar azimuth (degree of arc)

Comprehensive Energy Systems, Volume 1

doi:10.1016/B978-0-12-809597-3.00117-6

Solar Energy

S ς C

Stefan–Boltzmann constant (5.679  10 J m 2 K 4 s 1) Tilt angle of the surface (degree of arc) Reflectance (dimensionless), Surface azimuth angle (degree of arc)

Subscripts d Diffuse D Direct DH Direct component of insolation on a horizontal surface DN Direct normal dg Ground-reflected diffuse ds Diffuse solar E Earth g Ground H Horizontal

max r S sg ss SE t V l 1 2

Maximum Ground reflected; summer solstice Sun Between the surface and the ground Between the surface and the sky Earth to the Sun Direct solar radiation Vertical Monochromatic Number Number

Superscripts

*

Blackbody

Wavelength (mm) Micro Frequency (cycles s 1 ¼ Hz) Angle of incidence (degree of arc)

l m v y

1.15.1

s

639

8

Introduction

Solar energy powers virtually everything in the Earth and atmosphere system. This energy warms the air and the Earth’s surfaces, and drives the winds, currents, evaporation, clouds, rain, etc. Essentially, the process starts when the Sun’s energy in the form of electromagnetic radiation (radiation, in short) enters the atmosphere. The seasonal distribution of this energy obviously depends on the orbital characteristics of the Earth revolving around the Sun. Solar radiation reaching the Earth is significantly impacted by the inclination of the Earth’s axis. This axis (the line joining the two poles through the center of the Earth) is tilted 23.5 degrees from the perpendicular. The axis maintains the same orientation with respect to the galaxy; therefore, the amount of incoming solar radiation at the top of the atmosphere, hence at the surface of the Earth, varies considerably, creating seasons (by impacting the duration of daylight and elevation of the Sun in the sky with respect to time). The solar spectrum covers the range of radiation from very short wavelengths to very long wavelengths. The spectrum belonging to a blackbody at 6000K is pretty close to the incident radiation from the Sun at the top of the Earth’s atmosphere. When the Sun’s radiation passes through the Earth’s atmosphere, it is reflected, scattered, and absorbed by dust particles, gas molecules, ozone, and water vapor. The magnitude of the solar radiation’s attenuation at a given time and location is determined by atmospheric composition and length of atmospheric pathway the solar radiation travels. Compared to scattering, atmospheric absorption of solar radiation is relatively small. Ozone’s absorption of ultraviolet radiation is a significant component, which is vital for sustaining life on Earth. In addition to the ultraviolet absorption, at other wavelengths, absorption by nitrous oxide, carbon dioxide, oxygen, ozone, and water vapor takes place as well. The solar radiation reaching a surface on the Earth has both direct and diffuse components. Energetically they act in the same way. Since diffuse radiation comes from the entire sky, it is difficult to predict its intensity as it varies as moisture and pollutant contents of the atmosphere change throughout any given day at any location. This radiant energy entering the Earth and atmosphere system is eventually transformed into a variety of other energy forms. We will begin this chapter with solar physics, and talk about the source of the Sun’s energy. Then we will cover the radiation laws. And then, after covering the characteristics of solar radiation in depth, the chapter concludes with a brief conclusion statement.

1.15.2

Light and Solar Physics

Newton was among the first to realize that a sunbeam is the composite of beams of different colors that comprise what is termed as the visible spectrum. We have spent the last three centuries understanding the nature of light, and now we have a fairly complete model of the nature of light, or more generally speaking, of radiation.

1.15.2.1

Light as Waves

Light is considered to behave as the composite waves of different wavelengths. Wavelength is the distance between a given point (let us say the peak) on one wave and the same point (the next peak) on the next wave in the same wavelength. The wavelengths

640

Solar Energy

of, let us say, visible light are extremely short; therefore, we use a relatively small unit of wavelength: the micrometer. A micrometer is one-millionth of a meter, and is abbreviated as mm where m stands for one-millionth, and m indicates “meter.” In the visible spectrum, the red light has the longest wavelengths, whereas the violet has the shortest. As will be discussed later in depth, the atmosphere scatters light differently based on its wavelength. In the visible spectrum, for instance, shorter wavelength blue and violet light are more readily scattered compared to longer wavelength lights. Actually, this is the reason that we see the sky in blue (as the human eye is not so sensitive to violet wavelengths).

1.15.2.2

Light as Particles

Performed experiments also indicated that light energy behaves like a stream of particles. For instance, it is difficult to understand how sunlight travels through an empty space, as waves require a medium to travel in or propagate their energy. Ocean and sound waves for instance have water and air media to travel using the water and air molecules to propagate their energy, respectively. Without the mentioned media, it would not be possible for them to exist as there would be no molecules to vibrate. Light waves, however, require no medium to propagate. Light is considered as a stream of particles of radiant energy, also known as photons. And they have no mass, occupy no space, and travel at the speed of light; in this sense, they are quite different from particles of matter. As will be presented further in the chapter, the amount of energy carried by an individual photon is extremely small and inversely related to wavelength. The shorter the light’s wavelength is, the higher the energy content of its photons. In the visible spectrum, for instance, violet light photons have more energy content than those of red light photons. As presented above, each of the wave and particle models describes certain behavior of light that the other model cannot. Hence, light is only explained by this wave–particle duality model. Another important aspect is that the photons are different from particles of matter. Countless photons are created and destroyed at any time; however, these creations and destructions do not violate the law of conservation of energy, as they simply change forms through emission and absorption. Energized particles of matter (a molecule or electron), before discharging their excess energy fully or partially and returning to their lower energy levels, remain at energized or excited stage for a very short time. This discharging or shedding of excess energy is done by releasing a photon. Obviously, more energy interactions result in higher energy photons, and thus, emissions at shorter wavelengths. The energy source leading to photon production can be in any form, such as nuclear, combustion, and electricity. In summary, a photon can be described as a bundle of energy emitted by an excited molecule, atom, or electron as it returns from a high-energy level to a lower energy level. Molecules, atoms, and electrons (that is, the basic particles of matter) create and destroy photons, which form the basic particles of radiant energy.

1.15.2.3

Solar Physics

Solar energy comes from the thermonuclear reactions in the core of the Sun, where most of the solar mass is concentrated (Fig. 1). In the core, the temperature at a pressure of about 10  106 bar is estimated to be approximately 15  106K. This energy moves outwards by radiative diffusion in the interior section; from there it is transferred by convection to the photosphere. Then from this outer surface zone, the energy, mostly shortwave radiation, is emitted into space in all directions by radiation. The outer surface or photosphere has an average temperature of about 6000K (more accurately 5780K); however, it fluctuates due to the sunspots, Photosphere Convective zone

Interior

Core

Fig. 1 Main radial zones of the Sun. Modified after Taylor FW. Elementary climate physics. New York: Oxford University Press; 2005. p. 29–39.

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641

which are relatively cooler regions having temperatures closer to 4000K. When it strikes a material, the radiation can be absorbed, transmitted, or reflected. The Sun has a radius (696,000 km) approximately 100 times larger than that of the Earth. And its mass is estimated as 2  1030 kg which is 300 million times bigger than that of the Earth. Just like any other planet, it is believed that the Sun is 4.5 billion years old, mainly composed of hydrogen (91.2%) and helium (8.7%), and most likely to last for 5.5 billion more years.

1.15.3

Source of the Sun’s Energy

As noted earlier, solar energy comes from the thermonuclear reactions in the core of the Sun, where most of the solar mass is concentrated. Spectroscopic measurements of sunlight reaching the Earth from the photosphere (Fig. 1) dictates that the solar mass is mainly composed of two elements, hydrogen (H) – which makes up about 70% of solar mass, and helium (He) – about 27%; the remaining 3% of solar mass is made up of all the other elements [1]. The reaction is
 4 1 H -4He þ energy þ 2 neutrinos The conversion of H into He through solar fusion serves as the source of solar radiation (electromagnetic radiation) received on the Earth. Every second, approximately 630 t of H are estimated to be converted to 625 t of He and 5-t mass equivalent energy (E¼mc2), which gives an approximate energy release of 4  1020 MJ every second.

1.15.4

The Radiation Laws

Photosphere, the outer layer of the Sun, continuously loses energy by electromagnetic radiation into space in all directions covering all regions of the electromagnetic spectrum; therefore, a large temperature gradient exists between the core and the outer surface of the Sun. This electromagnetic energy is radiated as a stream of light particles, photons, moving along a sinusoidal wave trajectory. Radiation is a form of energy that is emitted by all objects having a temperature above absolute zero, and can travel through the vacuum of outer space. Consequently, the energy coming from the Sun and leaving the Earth ought to be in the form of radiation. The radiation laws govern the relationships between the surface of the Sun and the energy emitted into the space in all directions. First of these laws is called Planck’s law, which basically states that the wavelength of emission from a perfectly black object, a blackbody, which is a perfect emitter and absorber of radiation (Kirchhoff’s law), depends on the temperature of the emitting body. 5 E l ¼ c1 =fl ½expðc2 =lTÞ21Šg

ð1Þ

2 m where E m 1) emitted at a single wavelength l (mm) (blackbody monochromatic radiation) at l is the amount of energy (W m temperature T (K). The constants c1 and c2 have magnitudes of 3.74  108 W mm4 m 2 and 1.44  104 mm K, respectively. Solar radiation, a very good approximation to that of a blackbody, which follows Planck’s curve, is obtained using Eq. (1) for an average outer surface temperature (6000K) of the Sun (Fig. 2). Actual objects can emit less than the theoretical blackbody value, that is, El ¼ el E l where el is emissivity, which is a measure of emission efficiency.

Example 1: Find: blackbody monochromatic radiation at a single wavelength of 0.5 mm emitted by the Sun’s surface, E l. Solution: Assuming a surface temperature of 6000K, blackbody monochromatic radiation at 0.5 mm is n
 o 5 8 4 2 4 E l ¼ 3:74  10 W mm m = ð0:5 mmÞ exp 1:44  10 mm K =ð0:5 mmÞð6000K Þ 21 6 E l ¼ 99:3  10 W m

2

mm

1

108

6000K

15 (W m–2 µm–1)

Spectral irradiance (W m–2 µm–1)

Solar Terrestrial

10 300K 5 0

0 0

~0.5

2 Wavelength (µm)

0

~10

60

80

Fig. 2 Schematic views of the standard blackbody curves for solar and terrestrial radiations assuming the corresponding temperatures. Quantitative vertical scales approximately show the differences in total energy emitted by the Sun and the Earth. The values given by the Stefan–Boltzmann equation (E ) are given by the area beneath the curves.

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Solar Energy

Or, it is simply 99.3 MJ per square meter solar surface area every second. The fundamentals of radiation or the photon emission process were discussed in depth in Section 1.15.2. Absorption of radiation or photons is the exact reverse of the photon emission process. A photon is absorbed as soon as it interacts with a molecule, an atom, or one of its electrons. And this interaction destroys the photon and brings the molecule or an atom to an excited state. The excited molecule or atom subsequently starts reemitting one or more photons, and continues the exchange of energy from radiant energy to atomic excitation and back again. Two other particularly useful radiation laws, which can be derived from Eq. (1) by differentiation and integration, respectively, are Wien’s law for the wavelength of a maximum emission for a blackbody at a given temperature, and the Stefan–Boltzmann law for the total energy emitted by a blackbody. Wien’s displacement law states that the wavelength at which a blackbody emits its maximum amount of radiation is inversely proportional to its absolute temperature in Kelvin. lmax ¼ a=T

ð2Þ

where l is in mm, a is 2897 mm K, and T in K. Example 2: Find: calculate lmax for the Sun’s surface. Solution: Assuming an average surface temperature of approximately 6000K, we would have its maximum emission at lmax ¼ 2897 mm K =6000K lmax ¼ 0:48 mm A wavelength of approximately 0.5 mm lies within the visible spectrum. Example 3: Find: calculate lmax for the Earth’s surface. Solution: Assuming an average surface temperature of 151C (i.e., 288.15K), we would determine its maximum emission at lmax ¼ 2897 mm K =288:15K lmax ¼ 10:0 mm A wavelength of 10.0 mm lies within the infrared spectrum way beyond the visible spectrum. This shows that a hotter object emits a greater portion of its energy at shorter wavelengths than a cooler object. For determining how much radiation a given object emits over all wavelengths combined, we need to sum up all the energy contributions of the photons at all wavelengths. Actually, this total energy is represented by the area between the object’s blackbody curve and the x-axis as shown in Fig. 2. That area, and therefore the energy, is given by the Stefan–Boltzmann law, which is simply given as E ¼ s T 4 ð3Þ  where E is the energy in Joules emitted by a square meter of the objects surface per second, s is known as Stefan–Boltzmann constant and has a magnitude of 5.679  10

8

Jm

2

K

4

s 1, and T is the absolute temperature of the surface in Kelvin.

Example 4: Find: using the Stefan–Boltzmann Law, estimate the Sun’s radiation emission. Solution: Assuming an average surface temperature of the Sun as 6000K, we can estimate that the Sun emits:
E ¼ 5:679  10 E ¼ 73:6 MJ m Overall, in all directions with a radius of 6.96  10 MJ of energy every second.

1.15.5

11

2

8

Jm

2

K

4

s

1



ð6000KÞ4

every second:

m, we can easily calculate the Sun’s emission as approximately 4.5  1020

Characteristics of Solar Radiation

This section starts with the solar radiation reaching the outer space of the atmosphere, and analyzes the spectral distribution of this radiation. And then, variations in the amount of this radiation are studied covering the impacts of different variables, such as time, solar geometry, and atmospheric effects.

1.15.5.1

The Solar Constant

It is pretty useful to know a few energy terms. The first one is the amount of solar radiation reaching onto a horizontal surface, which is called the insolation – short for “incoming solar radiation.” The second term is the rate of energy flow, which is also known as power. The unit of power used in SI units is the watt. One watt is an energy flux of one joule per second; therefore, the unit of time is built into the definition of the watt. The third term refers to the amount of insolation reaching the top of the Earth’s

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643

atmosphere, that is, the amount of solar energy passing through unit area every second at the mean distance of the Earth (perpendicular to the Earth–Sun) line, and is called the solar constant. The term solar constant provides a convenient way of referring to the flux of energy radiated by the Sun. Measurements over approximately the past 100 years show that the Sun’s energy output is nearly constant. The measured flux is virtually the same. The quantity of the solar constant, the amount of solar radiation incident per second on a 1 m2 surface oriented perpendicular to the beam and positioned at the top of the atmosphere at Earth’s mean distance from the Sun, varies only slightly with time, and expressed in watts, has a mean measured value of 1368 W m 2. And these watts are related to the units in which people buy electric energy for their households, which are typically given in the unit of kilowatt-hour. Example 5: Find: using the measured solar surface temperature of 5780K, calculate the solar constant. Solution: E ¼ ð5:679  10

8

Jm

E ¼ 63;384;522 W m

2

K

4

s 1 Þ ð5780KÞ4

2

And using a surface area of the Sun ( ¼ 4pR2S ¼ 6:09  1012 km2 ), we can calculate E in watts,

 E ¼ 63;384;522 W m 2 6:09  1018 m2 E ¼ 3:86 1026 W And dividing this by the surface area of a sphere at the mean distance of Earth to the Sun (4pR2S ¼ 2:83  1017 km2 ), we can calculate the solar constant as
 Solar Constant ¼ E ðWÞ = 4pR2SE
 ¼ 3:86  1026 W = 2:83  1023 m2 Solar Constant ¼ 1364 W m

2

This calculated solar constant is pretty close to the mean measured value (by satellites) of 1368 W m 2 at an average distance (Earth orbit radius), RSE, of 1.495  108 km. Note that we employ the inverse-square law here (that is, radiation emitted from a spherical source decreases with the square of the distance from the center of the sphere, E2 ¼ E1  (R1/R2)2, where R is the radius from the center of the sphere). If we multiply, let us say, the measured solar constant 1368 W m 2 by the projected area of the Earth (pR2E , where RE is the mean radius of the Earth, 6371 km), then using the area of a disk rather than the surface area of a sphere, we can find the intercepted solar radiation by the Earth as a whole at the top of the atmosphere every second approximately 1.74  1011 MJ. In reality, incoming radiation is the solar constant minus reflected sunlight, times the area of the intercepting surface; that is, (1 A) (Solar Constant) (pR2E ), where A is the global albedo (0.3), which will be discussed further in depth later. Overall, the top of the atmosphere receives about 4.5  10 10 of the total energy output of the Sun. Example 6: Find: determine the intercepted solar radiation by the Earth as a whole at the top of the atmosphere every second. Solution:
 Intercepted Solar Radiation ¼ ð1 AÞ ðSolar ConstantÞ pR2E

where albedo A is 0.3, the measured solar constant is 1368 W m 2, and the mean radius of the Earth is 6.371  106 m. Then, 2 
  Intercepted Solar Radiation ¼ ð1 0:3Þ 1368 W m 2 p 6:371  106 m Intercepted Solar Radiation ¼ 1:22  1011 MJ

Ignoring the losses from the solar beam as it goes through the atmosphere; we can find that a one-square-meter area of the Earth’s surface oriented toward the solar beam at about 45-degree angle receives 1.368 kWh of solar energy every hour. Considering that a kilowatt-hour is a 1000-W energy flow lasting for an hour, we can now imagine the amount of solar energy reaching a roof surface exposed to the Sun during a day.

1.15.5.2

The Solar Spectrum

Fig. 3 shows the complete set of possible wavelengths, also known as the electromagnetic spectrum. The solar spectrum covers the range of radiation from very short wavelengths (high frequency) to very long wavelengths (low frequency), as shown in Fig. 4. The smooth spectrum (dashed line) in Fig. 4 belongs to a blackbody at 6000K. And this spectral shape is pretty close to the incident radiation from the Sun at the top of the Earth’s atmosphere. The observed deviations are mostly in the high-energy (ultraviolet) region (lo0.4 mm), where the molecular bands responsible for ozone production are found. The wavelength of peak radiation emission at 0.5 mm actually suggests that the Sun has a blue-green color; however, we see the Sun as yellow-white due to the radiation’s interaction with the Earth’s atmosphere and relative sensitivity of the human eye (has a

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Solar Energy

44%

7%

0.4

37%

0.7

11%

1.0

AM radio waves

Short radio waves

TV waves

Microwaves

Far infrared

Near infrared

Ultraviolet

Radiation intensity (amount)

Visible light

Less than 1%

1.5

0.001

Wavelength (µm)

1

10

100

Wavelength (m)

Spectral intensity (kW m−2 µm)

Fig. 3 Electromagnetic spectrum: the complete set of possible wavelengths. Courtesy of Donald C. Essentials of meteorology: an invitation to the atmosphere. 4th ed. Southbank, Vic.: Thomson Learning Inc.; 2004.

6000K blackbody radiation

2.0

Solar spectrum at top of the atmosphere 1.5 Solar spectrum at sea level 1.0

0.5

0 0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

Wavelength, λ (µm) High High

Frequency Photon energy content

Low Low

Fig. 4 Solar spectrum. The smooth dashed line is the spectrum that the Sun would have if it were a blackbody at the “best fit” temperature of 6000K. Modified after Sen Z. Solar energy fundamentals and modeling techniques. Springer London; 2008. p. 47–98. Sen, 2008.

maximum sensitivity B0.55 mm). And as shown in Fig. 4, the effect of the Earth’s atmosphere is to reduce the total insolation reaching the top of the atmosphere to the magnitudes reaching sea level. The solar radiation emission mainly falls in the wavelength region of 0.15–4.0 mm, with about 9% in the form of ultraviolet radiation (l o0.40 mm), 38% in the visible (0.40–0.70 mm), and 53% in the near infrared (0.7–4.0 mm) regions. In Fig. 4, we see that at very short wavelengths, the Sun emits a relatively small amount of radiation, and as we move to the right toward the visible spectrum, the emission increases sharply reaching a maximum at about the middle of the visible range. However, the visible spectrum is still just a segment in a much broader range of solar radiation. Earlier we called this electromagnetic radiation because it has both electric and magnetic properties. The properties of light presented earlier in Section 2 apply to radiation throughout the electromagnetic spectrum or solar spectrum. Therefore, moving to the left in Figs. 3 and 4 also means moving toward radiation of shorter wavelengths and hence more energetic photons. Moving to the right, on the other hand, means that we move toward longer wavelengths and therefore less energetic photons. As will be discussed further later, the photons of ultraviolet radiation, for instance, are highly energetic and the stratospheric ozone plays an important role in shielding the Earth’s surface from these photons. The Sun also emits shorter wavelength X-rays and gamma rays, and longer wavelength infrared (4.0–100 mm), microwave (0.1–10 mm), and radio (41 cm) photons; however, these do not make

Solar Energy

100

Nitrous oxide

100

20

10

5

1

0.7

0.5

0.3

0.1

15

N2O

50 0

645

Methane CH4

50 0 100 50

O3

O2

O3

Molecular oxygen and ozone

Absorption (%)

0 100 50

Watervapor H2O

0 Carbondioxide 100 CO2 50 0 Infrared (IR) Atm window

5

1

0.7

0.5

0.3

0

0.1

50

Total atmosphere

20

Visible

15

UV

10

100

Wavelength (µm) Fig. 5 Absorption of radiation by gases in the atmosphere – line spectra of radiation. Courtesy of Donald C. Essentials of meteorology: an invitation to the atmosphere. 4th ed. Southbank, Vic.: Thomson Learning Inc.; 2004.

any significant contribution to the total solar energy reaching to the Earth and atmosphere system. As mentioned earlier, the smooth spectrum (dashed line) in Fig. 4 belongs to a blackbody at 6000K. Blackbody is the term employed to describe a perfectly efficient radiator (not referring to its actual color). Therefore, the blackbody radiation given in Fig. 4 represents the maximum radiation the Sun at a given average temperature of 6000K can emit. And we should also remember that most solids, liquids, and dense gases radiate very close to the blackbody radiation and have what we call continuous spectra of radiation. Air molecules, as in the atmosphere, however, are quite separated and have much less interaction with each other compared to those molecules of denser substances. And each air molecule has distinct mass and structure, vibrates, rotates, and goes through different processes more or less independent of the surrounding molecules. Substances (such as CH4, N2O, O2 and O3, CO2, and H2O) that interact with only certain discrete energy level photons and wavelengths are defined as selective absorbers and emitters. These substances are not considered as blackbodies because at certain wavelengths they emit (or absorb) either very little or no radiation – line spectra of radiation (Fig. 5). It is because of this reason that the Stefan–Boltzmann equation (which gives the total amount of radiation emitted or absorbed) is not applicable for a selective emitter or absorber like the atmosphere; therefore the solar spectrum at sea level has a different shape from the other two in Fig. 4. As Figs. 3 and 4 show, wavelength (l) and frequency (v) are related, and this relationship can formally be expressed through the speed of light, c, as follows: c¼lv 8

1

ð4Þ 1

where c is the speed of light, which has a value of 3  10 m s , l is the wavelength (mm), and v is the frequency (cycles s , also known as Hz). If one is known, then the other can easily be determined using the speed of light, which is a constant. Example 7: Find: determine the frequency for a radiational wavelength of 0.5 mm.

646

Solar Energy

Solution: c ¼ lv v ¼ c=l ¼ 3  1014 m s 1 =ð0:5 mmÞ ¼ 3  1014 mm s 1 =ð0:5 mmÞ ¼ 6  1014 cycles s 1 v ¼ 6  1014 Hz And similarly, a radiational wavelength of 10 mm has a frequency, v, of 3  1013 cycles s 1 (or 3  1013 Hz). Solar radiation consists of photons, which can be considered as packets of energy, which is related to frequency v as E ¼ hv

ð5Þ 34

J s). This shows that shorter wavelengths have higher where E is the energy content (J) and h is Planck’s constant (6.626  10 frequencies and higher energy contents compared to those of longer wavelengths (lower frequencies), as shown in Figs. 3 and 4. Example 8: Find: determine the energy content, E, of a frequency of 6  1014 Hz (or 0.5 mm wavelength). Solution: E ¼ hv E ¼ ð6:626  10 E ¼ 3:98  10

19

34

J sÞ ð6  1014 cycles s 1 Þ

J

And similarly, a radiation frequency of 3  1013 Hz (or 10 mm wavelength) has an energy content, E, of approximately 1.99  10 20 J. This clearly shows the above-mentioned difference between the energy contents of two different wavelengths.

1.15.5.3

Solar Time

Orbital velocity of the Earth varies throughout the year, as does apparent solar time (AST), determined by a sundial, which changes in small amount from the mean time, which is kept by a clock running at a constant rate. This change is called the equation of time (ET). The position of the Sun in the sky is dictated by local solar time (LST), which is determined by adding the ET to the local civil time. Local civil time, on the other hand, is calculated from local standard time (either by adding to or subtracting from) the longitude correction of 4 min/degree difference between the local longitude and the longitude of the standard time meridian (LSTM) for the location in hand (e.g., 75 degrees for the Eastern Standard Time in Canada and the USA). The relationship between AST and local standard time is provided in Eq. (6): AST ¼ LTS þ ET þ 4 ðLSTM

LONÞ

ð6Þ

where ET is the equation of time in minutes of time (Table 1), LSTM is the local standard time meridian in degree of arc (in Canada and the USA, the LSTs are 60 degrees for Atlantic Standard Time (ST); 75 degrees for Eastern ST; 90 degrees for Central ST; 105 degrees for Mountain ST; 120 degrees for Pacific ST; 135 degrees for Yukon ST; 150 degrees for Alaska–Hawaii ST), LON is the local longitude in degree of arc, and 4 is the minutes of time required for the Earth’s 1.0-degree rotation. Table 1 Month

Equation of time (ET), declination angle, apparent insolation (A) at zero air mass, and related data for the 21st day of each month Equation of time (ET) (min)

Solar declination (degrees)

A (W m 2)

B

C

(dimensionless ratios) January February March April May June July August September October November December

11.2 13.9 7.5 1.1 3.3 1.4 6.2 2.4 7.5 15.4 13.8 1.6

20.0 10.8 0.0 11.6 20.0 23.45 20.6 12.3 0.0 10.5 19.8 23.45

1228.5 1212.8 1184.4 1134.0 1102.5 1086.8 1083.6 1105.7 1149.8 1190.7 1219.1 1231.7

0.142 0.144 0.156 0.180 0.196 0.205 0.207 0.201 0.177 0.160 0.149 0.142

Source: ASHRAE. Handbook of fundamentals. American society of heating. Atlanta, GA: Refrigeration and Air Conditioning Engineers, Inc.; 1989. p. 27.1–27.38.

0.058 0.060 0.071 0.097 0.121 0.134 0.136 0.122 0.092 0.073 0.063 0.057

Solar Energy

Northern spring Southern fall

647

Northern winter Southern summer Periapsis January 3

March 21

Equinox June 21

147 Mkm Declination Angle, 

Line of solstice

December 21 152 Mkm

September 21

Apoapsis July 3

Northern fall Southern spring

Northern summer Southern winter Fig. 6 Earth’s motion around the Sun (time of orbit is one revolution of 365.242 days).

In the next section, we will see that the equatorial plane of the Earth is tilted at an angle of 23.5 degrees to the orbital plane (Fig. 6); and therefore, the solar declination δ (the angle between the Earth–Sun line and the equatorial plane) varies throughout the year (Fig. 6 and Table 1). And this variation, with its nonuniform periods of daylight and darkness, is the reason behind having different seasons.

1.15.5.4

Solar Geometry

We know that the planets in the solar system make elliptical orbits around the Sun. The main features of the orbital geometry of the Earth are shown in Fig. 6. The ellipticity in the solar system is relatively small; therefore, the Earth’s motion around the Sun as well follows a nearly circular elliptical orbit with a period of 365-1/4 days. Kepler found that, for circular orbits, the time period (Y) of the orbit is related to the distance (R) of the planet from the Sun, that is, Y¼ a R3/2. Parameter a¼ 0.1996 d (Gm) 3/2, where d is Earth days and Gm is gigameters (109 m). Example 9: Find: the Earth’s orbital period, Y. Solution: Using an average Sun to Earth distance, R¼ 149.6 g. Y ¼ a R3=2 Y ¼ 0:1996 d ðGmÞ

3=2

ð149:6 GmÞ3=2

Y ¼ 365:2 days Using a leap year every 4 years, the shortcoming of 365 days we use per year is corrected accordingly. Fig. 6 shows that the Earth is closest to the Sun when it is winter (January) in the Northern Hemisphere, and farthest away in July. As mentioned earlier, solar radiation reaching the Earth is significantly impacted by the inclination of the Earth’s axis. This axis (the line joining the two poles through the center of the Earth) is tilted 23.5 degrees from the perpendicular. And, the axis maintains the same orientation with respect to the galaxy; therefore, the amount of incoming solar radiation at the top of the atmosphere, hence at the surface of the Earth, varies considerably creating seasons (by impacting the duration of daylight and elevation of the Sun in the sky with respect to time). The incoming solar radiation reaching a unit horizontal area at any specific location on the Earth’s surface, therefore, even though the Sun’s output energy is nearly constant, varies between 0 and 1050 W m 2, depending on the latitude, the season, the time of the day, the degree of cloudiness and air pollution. And this section addresses the variations due to the latitude, the season, and the time. Fig. 7 shows the Sun’s apparent paths across the sky on different dates. This is called the apparent path because it is not the actual motion of the Sun; rather, it is the Earth’s rotation about its own axis once per day. As Earth rotates, different regions start receiving the sunlight and end again. On September 21 (and on March 21), anywhere on the Earth, the Sun seems to rise from the eastern side of the sky, move toward the west across the sky, and set 12 h later in the west. However, the actual apparent path varies considerably based on the latitude. Solar beam is actually very rarely perpendicular to the Earth’s surface at any given location. Fig. 7 shows that the smaller the angle between the incoming solar beam and the Earth’s surface is, the larger the area the solar energy spreads; as a result, less solar energy is received per unit area. In late September, for instance, at the top of the atmosphere

648

Solar Energy

June 21 September 21/March 21

W

December 21

  S

N

E Fig. 7 Annual and hourly changes in the Sun’s position for 401N (b is the solar altitude – angle above the horizon, and f is the solar azimuth – angle from the true south). Modified after Hinrichs RA, Kleinbach M. Energy: its use and the environment. 4th ed. Belmont, CA: Thomson Brooks/ Cole; 2006. p. 160–204.

over equatorial regions, more solar energy is received per unit area compared to that over other regions; however, a location directly on the equator will receive the solar beam directly downward for a very short time around noon. Daily path of the Sun is not constant throughout the year; rather it shifts slightly and steadily every day. And this has a huge impact on insolation. The latitude and the season are a result of the solar geometry. For instance, the North Pole has a tilt toward the Sun when it is summer in the Northern Hemisphere, and is away from the Sun when it is winter. Consequently, the Northern Hemisphere has more daylight hours in the summer, reaching a maximum value on the summer solstice, June 21 (the position on the left side of Fig. 6), when the North Pole’s tilt toward the Sun is greatest, and hence, the amount of solar radiation reaching a horizontal surface is at the maximum in the summer. In the Northern Hemisphere, the Sun does not directly shine down on the equator, but rather, on latitude 23.51N. On the summer solstice, the daily path is highest in the sky, and the length of daylight is the longest of the year. In the Southern Hemisphere, on the other hand, the situation is the reverse, and the hemisphere is tilted farthest from the Sun on or about June 21 and receives the least amount of sunlight and onset of winter. In the Northern Hemisphere’s winter, however, due to the tilt angle (and the North Pole) facing away, that is, farthest from the Sun, the solar radiation needs to go through a longer path resulting in more absorption and scattering in the atmosphere; therefore, less radiation reaches to the Earth’s surface when the need for heat is the greatest. At this time of the year, the Sun is directly overhead at latitude 23.51S, which is called the winter solstice; and at this time, the Southern Hemisphere starts enjoying the beginning of summer with long hours of the Sun high in the sky. Fig. 7 schematically shows the annual and hourly changes in the Sun’s position and relevant solar angles for latitude, approximately let us say, 401N latitude. At the extreme, the noontime Sun is directly overhead at either the Tropic of Cancer (summer solstice), or Tropic of Capricorn (winter solstice). At winter solstice, the areas north of the Arctic Circle have 24-h darkness, whereas the areas south of the Antarctic Circle have 24-h daylight. When the Sun is directly overhead at the equator (spring and autumnal equinoxes, on March 21 and September 21, respectively) there are 12 h of daylight everywhere on the Earth; that is, all latitudes have equal amounts of day and night (Fig. 6). Fig. 7 shows that as summer moves into fall, and then into winter, the sunrise and sunset times of the Sun’s motion across the sky gradually move southward. As a result, the day lengths get shorter and the solar path gets lower in the sky. In December, the Sun rises and sets quite a bit south of east and south of west, respectively. Fig. 7 depicts the Sun’s annual and hourly position only for 401N. Note that the Sun’s summertime daily path never goes below the horizon; therefore, these regions experience continuous sunlight (24 h of daylight each day) during summer months, which gives them the highest amount of insolation at the top of the atmosphere, at least, at that time of the year. We must also note that there is a lack of significant variation in insolation values at the top of the atmosphere throughout the year along the equator, compared to seasonal changes at higher latitudes. We also need to recognize that January insolation values decrease drastically as we go from the equator toward the North Pole, but remain constant south of the equator. In June, however, this pattern is reversed, with northern latitudes exposing little change.

1.15.5.5

Solar Radiation

As it will be discussed in depth in the following section, some solar radiation scattered by air molecules and dust reaches the Earth in the form of diffuse radiation, Id. The intensity of diffuse radiation is a difficult task to complete as it comes from all directions in

Solar Energy

649

the sky, and varies as moisture and dust content of the atmosphere change throughout any given day. For instance, on an overcast day, the diffuse component is all the solar radiation reaching the Earth. The total solar radiation reaching a terrestrial surface, It, is composed of the direct solar radiation ID, the diffuse sky radiation Id, and the solar radiation reflected from the surrounding surfaces Ir [2]. The direct solar radiation ID, is the product of the direct normal solar radiation IDN and the cosine of the angle of incidence y between the incoming solar rays and a line normal (perpendicular) to the surface [3]: It ¼ IDN cos y þ Id þ Ir

1.15.5.6

ð7Þ

Solar Angle

The position of the Sun in the sky is expressed in terms of the solar altitude and the solar azimuth. The height of the Sun, the elevation of the Sun, is usually given in terms of the solar altitude b (Figs. 4 and 5). This is the angular distance between the Sun’s rays and the horizon, and is given by Eq. (8) [3]. And the solar azimuth f is the angle measured from the true south (Figs. 4 and 5), given by Eq. (9) [3]. sin b ¼ cos L cos δ cos H þ sin L sin δ

ð8Þ

cos f ¼ ðsin b sin L2sin δÞ = ðcos b cos LÞ

ð9Þ

where these angles depend on the local latitude L; the solar declination δ (the angle between the Earth–Sun line and the equatorial plane (Fig. 6 and Table 1), which is a function of the time of year, and therefore varies from þ 23.5 degree on June 21 to 23.5 degrees on December 21; and the AST, expressed as the hour angle H, where H ¼ 0.25  number of minutes from local solar noon), in degrees. Hour angle is zero at local noon and increases in magnitude by p/12 (15 degrees) for every hour before or after noon [3]. Further, assuming that the Earth’s orbit is circular, the solar declination angle for any day of the year can be approximated using δ¼ F cos [C (d – dr)/dy], where F is the tilt angle of 23.5 degrees, C is full 360 degrees, d is the Julian Day, dr is the Julian day for summer solstice on June 21; and it is 172 for non-leap years, dy is the number of days per year, that is, 365 days (use 366 on a leap year). Example 10: Given: F ¼ 23.5 degree; C=360 degree; dr ¼ 172 days; dy ¼ 365 days. Find: the solar declination angle on March 21. Solution: Assume: Not a leap year.   Using δ ¼ F cos C ðd2dr Þ=dy : δ ¼ 23:5 degree cos ½360 degree ð80 days 2 172 daysÞ=365 daysŠ δ¼

0:3 degree

On the spring equinox (March 21), the declination angle should be zero; so our calculation is a good approximation. It is still winter before March 21, and the declination angle should be negative; the values in spring and summer are positive. Example 11: Find: the solar azimuth and altitude at 0830 Atlantic Standard Time (ST) on March 21 at 451N latitude and 631W longitude. Solution: Using Eq. (6), local time is 0830 þ 4 (60–63 degrees) ¼0818. Table 1 gives the ET as 7 min, so AST¼ 0818 – 7¼ 0811 or 229 min from local solar noon; therefore, the hour angle, H ¼0.25  229 min ¼ 57.3 degrees. As calculated in Example 10 and also provided in Table 1, the solar declination on March 21 is 0 degree. Therefore, using Eq. (8), the solar altitude, b can be calculated as follows: sin b ¼ cos 45o cos 0o cos 57:3o þ sin 45o sin 0o sin b ¼ 0:382; therefore; b ¼ 22:5o And, the solar azimuth, f, can be calculated using Eq. (7) as cos f ¼ ðsin 22:5o sin 45o 2 sin 0o Þ = ðcos 22:5o cos 45o Þ cos f ¼ 0:414; therefore; f ¼ 65:5o Fig. 8 shows the solar angles and incident angles for horizontal and vertical surfaces. Line OV is perpendicular to the horizontal plane in which the solar azimuth, angle HOS and the surface azimuth, angle POS (C) are located. Angle HOP is the surface solar azimuth (g) and is given by g¼f

C

ð10Þ

The solar azimuth angle f is negative for morning hours and positive for afternoon hours. The absolute value of the surface solar azimuth g is used in Eq. (11). The surface is considered in the shade if g is greater than 90 degrees or less than 270 degrees.

650

Solar Energy

V Z

Q

Earth-sun line N

Tilted surface

W

Solar altitude

 Σ = Tilt angle

 H

O

Solar azimuth 

Normal to vertical surface

Ψ

E

S P

Fig. 8 Solar angles (b is the solar altitude – angle above the horizon, and f is the solar azimuth – angle from the true south). Modified after ASHRAE. Handbook of fundamentals. American society of heating. Atlanta, GA: Refrigeration and Air Conditioning Engineers, Inc.; 1989. p. 27.1–27.38.

For any surface, the angle between the incoming solar rays and a line normal to the surface is called the angle of incidence, y. For the horizontal surface given in Fig. 8, the angle of incidence yH is QOV; the incident angle for the vertical surface yV is QOP. The incident angle y for any surface is related to the solar altitude b, the surface solar azimuth g, and the tilt angle of the surface from the horizontal S as shown below [3]: cos y ¼ cos b cos g sin S þ sin b cos S

ð11Þ

where S is the tilt angle of the surface from the horizontal plane. When the surface is horizontal S is equal to zero degrees, and cos y H ¼sin b. When the surface is vertical, however, S is equal to 90 degrees, and cos y V ¼cos b cos g [3]. Example 12: Find: for the conditions of Example 11 given above, find the incident angle at a vertical surface facing southeast. Solution: As we have determined that the surface azimuth angle is to the east (AST o1200), and the surface azimuth is also to the east (Table 2), they both must be negative, that is, f¼ 65.5 degrees and C ¼ 45 degrees. Therefore, the surface solar azimuth, g, can be calculated using Eq. (10) as g¼

65:5 degrees

ð 45 degreesÞ ¼

20:5 degrees

The negative surface solar azimuth angle that we calculated above indicates that the Sun at the given time is east of the line normal to the surface. As mentioned above, when the surface is vertical, S is equal to 90 degrees, and the incident angle, yv, can then be determined using the relationship mentioned earlier, cos yv ¼cos b cos g. Therefore, cos yv ¼ cos 22:5o cos 20:5o ¼ 0:865 Then, the incident angle, yv, the angle between the incoming solar rays and a line normal to the surface: yv ¼ 30:1 degrees

Solar Energy

Table 2

651

Surface orientations and azimuth angles, measured from the south

Orientation

N

NE

Surface azimuth angle, C

180 degree

E

135 degree

SE 90 degree

45 degree

S

SW

W

NW

0 degree

45 degree

90 degree

135 degree

Source: ASHRAE. Handbook of fundamentals. American society of heating. Atlanta, GA: Refrigeration and Air Conditioning Engineers, Inc.; 1989. p. 27.1–27.38.

Reflected from surface, clouds, and atmosphere

4%

20%

Radiation from the sun 100%

Top of the atmosphere

6%

20% absorbed by clouds and atmosphere

50% absorbed by surface Earth’s surface Fig. 9 Schematic distribution of what happens to solar radiation after it falls on the Earth. Modified after Modified after Taylor FW. Elementary climate physics. New York: Oxford University Press; 2005. p. 29–39.

1.15.5.7

Atmospheric Effects

In the previous section, we mainly focused the distribution of insolation at the top of the atmosphere at different times and locations. In this section, we will trace a beam of solar energy and explore its interactions with the atmosphere. It will be assumed that the beam has 100 units of energy as it enters the atmosphere. The fate of these 100 units of energy can be tracked by referring to Fig. 9 as we read. From our daily observations, it would be clear that, if the air is free of clouds and pollution, the solar beam would reach the ground with little interference from the atmosphere. The solar disk, on the other hand, becomes completely obscured under cloudy or dirty sky conditions. Clear air is quite transparent to sunlight. Normally, when the Sun’s radiation passes through the Earth’s atmosphere, it is reflected, scattered, and absorbed by dust particles, gas molecules, ozone, and water vapor. The magnitude of the solar radiation’s attenuation at a given time and location is determined by atmospheric composition and length of atmospheric pathway that the solar radiation travels. The length of atmospheric path is given in terms of the air mass m, which is the ratio of the atmospheric air mass in the actual Earth–Sun path to the mass that would exist if the Sun were overhead at sea level (m¼ 1.0). Obviously, above the atmosphere, m is equal to zero. Almost for all purposes, the air mass m at any given time and location equals the cosecant of the solar altitude b (Fig. 8), multiplied by the ratio of the existing barometric pressure to standard pressure. Interactions of solar radiation within the atmosphere takes place almost simultaneously; however, these interactions are separate processes with different consequences, therefore, they must be treated separately. Whenever a photon hits a particle or an object without being absorbed, scattering of radiation takes place. As soon as radiation gets into the atmosphere, it starts interacting with small particles; this process is called scattering. When, however, radiation hits a larger object, then there is a complete change in the photon’s travel direction, and this special condition is called reflection. This change in travel direction can be in any or multiple directions. Air molecules have sizes of somewhere between 0.0001 and 0.001 mm, which indeed are much smaller than the wavelength of the visible band (0.4–0.7 mm). Small particles compared to the wavelength of solar radiation, such as atmospheric gas molecules, generate something called Rayleigh scattering. How much scattering generated is directly proportional to the fourth power of the wavelength; therefore, the scattering of blue light (lB0.4 mm) within a cloudless atmosphere without pollution is about 10 times greater than that for red light (lB0.7 mm). As a result of this Rayleigh scattering process, we see the daytime sky in blue. In the evening time, however, we observe a much redder Sun and reddish sky. This is because of the very long pathway the radiation

652

Solar Energy

travels through the atmosphere, which causes most of the visible wavelengths to be scattered many more times leaving only the red wavelength, some of which is also scattered to form a reddish sky. When larger particles, such as water droplets and pollution particles, exist in the atmosphere – that is, the scattering particles and the wavelength of the radiation have similar sizes – then a different type of scattering process takes place, which is called and simplified as Mie scattering. In this case, all wavelengths are scattered almost uniformly, and the scattering is a function of both the particle size and the wavelength of the radiation. When the atmosphere is polluted or overcast, then no wavelength is preferentially scattered; as a consequence, it creates a light blue/greyish sky. Air molecules and other small particles deflect some of the incoming solar beam in all directions. And under clear sky conditions, 6% of the original 100 units are scattered back to space. Compared to scattering, atmospheric absorption of solar radiation is relatively small. Ozone’s absorption of ultraviolet radiation is a significant component that is vital for sustaining life on Earth. In addition to the ultraviolet absorption, at other wavelengths, absorption by nitrous oxide, carbon dioxide, oxygen, ozone, and water vapor takes place as well. Overall, as shown in Fig. 9, approximately 20% of the energy reaching the top of the atmosphere is absorbed by the clouds (2%, i.e., 2 units of our sample of 100 units) and the atmosphere (18%, i.e., 18 units of our sample of 100 units). As mentioned above, some of the atmospheric absorption takes place due to the molecules of ozone and monatomic oxygen in the upper atmosphere. Actually, it is this absorbed energy that is the cause of the high temperatures observed in the stratosphere and thermosphere. As a result of the scattering, and the absorption by the clouds and the atmosphere, only 74 units of the sample 100 units of energy are able to reach the Earth’s surface as direct beam or diffuse solar radiation (which will be discussed further in the following section). Fig. 9 shows that the clouds alone significantly reduce the amount of solar energy reaching the Earth’s surface. As mentioned above, clouds absorb 2%, and reflect 20% back to space (Fig. 9). All these atmospheric processes (absorption, reflection, and scattering) leave only 54% of the original energy, which eventually reaches the Earth’s surface (Fig. 9). It is obvious that the areas of maximum radiation receipt are the desert regions of the Earth, while minimum radiation is received in the polar regions. It also needs to be remembered that Fig. 9 represents the long-term, global averages; therefore, the local values would differ drastically. In high latitudes, for instance, where the solar angle is low, the solar beam has to pass through a much longer atmospheric path than that at low latitudes; therefore, the solar beam is more likely to be scattered or absorbed further. As briefly mentioned above, the solar radiation reaching a surface on the Earth has both direct (the radiation that casts a shadow) and diffuse (radiation scattered from clouds, particles, and air molecules, coming from the entire sky) components. Energetically though, they act in the same way. Since diffuse radiation comes from the entire sky, it is difficult to predict its intensity as it varies as moisture and pollutant contents of the atmosphere change throughout any given day at any location. Since cloud cover and atmospheric pollution vary considerably and are hard to predict, the best one can do is average the solar radiation received at a location over a number of recent years and assume that, on average, the same amount will be received in the future. At the Earth’s surface on clear days, solar radiation is approximately 85% direct and 15% diffuse. On a completely overcast day, all solar radiation reaching the Earth’s surface is diffuse radiation.

1.15.5.7.1

Direct normal solar radiation

As mentioned earlier, the main portion of the solar radiation reaching the Earth’s surface on clear days is direct normal radiation or solar intensity IDN, which is determined by Eq. (12) [3]: IDN ¼ A=½exp ðB=sin bފ

ð12Þ

where A is the apparent incoming solar radiation (insolation) at air mass ¼ 0 (Table 2), and B is the atmospheric extinction coefficient, a dimensionless ratio (Table 2). Both values vary during the year due to the seasonal changes in atmospheric pollution and water vapor contents and the Earth–Sun distance. Using Eq. (12) and Table 2, values for direct normal radiation or solar intensity IDN, at the Earth’s surface on a clear day for any given latitude, can be calculated and tabulated for the daylight hours for the 21st day of each month. Example 13: Find: for a clear day, find the direct component of insolation, IDH, on a horizontal surface for the conditions given in our original example. Solution: We have already determined that the solar altitude, b¼ 22.5 degrees, and that sin b¼ 0.382. Using Eq. (12), and the A, B, and C values provided in Table 2, we can easily determine the direct normal irradiation or solar intensity, IDN, as IDN ¼ A= ½exp ðB=sin bފ ¼ ð1184:4 W m 2 Þ = ½exp ð0:156=0:382ފ IDN ¼ 787:3 W m

2

And therefore, the direct component of insolation, IDH, on a horizontal surface is IDH ¼ IDN sin b ¼ ð787:3 W m 2 Þ sin 22:5 degree IDH ¼ 301:3 W m

2

Example 14: Find: for a clear day, determine the direct component of insolation, ID, on an inclined surface that has a tilt angle of 45 degrees and faces southeast for the conditions used in the examples above. That is, the solar azimuth and altitude at 0830 Atlantic Standard Time (ST) on March 21 at 451N latitude and 631W longitude.

Solar Energy

653

Solution: Earlier, the local time was determined to be 0818. And Table 1 provided the ET as 7 min, so AST was determined as 0811 or 229 min from local solar noon; therefore, the hour angle was then calculated as 57.3 degrees. As also determined previously and provided in Table 1, the solar declination on March 21 is 0 degree. Then, using the solar altitude, b and solar azimuth were calculated as b ¼22.5 degrees and f ¼ 65.5 degrees, respectively. We also determined that the surface azimuth is also to the east (Table 2), so it must be negative, C ¼ 45 degrees. Therefore, the surface solar azimuth, g, was calculated using Eq. (10) as 20.5 degrees. The negative surface solar azimuth angle obviously indicates that the Sun at the given time is east of the normal to the surface. Finally, the incident angle, yv, the angle between the incoming solar rays and a line normal to the surface was calculated as yv ¼ 30.1 degrees. In Example 13, the direct normal irradiation or solar intensity, IDN, was calculated as 787.3 W m 2. As it was expressed earlier, the total solar radiation reaching a terrestrial surface, It, is composed of the direct solar radiation ID, the diffuse sky radiation Id, and the solar radiation reflected from the surrounding surfaces Ir. The direct solar radiation, ID, is the product of the direct normal solar radiation, IDN, the cosine of the angle of incidence y between the incoming solar rays and a line normal (perpendicular) to the surface, and also the surface solar azimuth g (as the Sun is east of the inclined surface):
 ID ¼ IDN cos y cos g ¼ 787:3 W m 2 cos 30:1o cos 20:5o ID ¼ 638 W m

2

Example 15: Find: assuming that the solar oven is 20% efficient and the useful rate of heat energy needed for cooking is 200 W, and that the collector surface is horizontal, and ignoring the diffuse sky radiation and the ground-reflected diffuse radiation falling on the collector, then find the reflector area of the oven that is needed to receive the required amount of radiation at 0830 Atlantic time on March 21, 451N latitude. Solution: The direct component of insolation reaching on a horizontal surface is calculated in Example 13 and already determined as 301.3 W m 2. The energy needed for the cooker is equal to the direct component of insolation times the oven efficiency times the reflector are:

 301:3 W m 2 ð0:20Þ Area; m2 ¼ 200 W Area ¼ 3:3 m2 We should remember that we have determined the required area for the cooking at 0830 in the morning when the direct component of insolation reaching a horizontal surface is quite low. In reality, we would use the noontime insolation rate for determining the required design area. We would also consider the diffuse sky radiation and the ground-reflected diffuse radiation falling on the collector.

1.15.5.7.2

Diffuse solar radiation

The diffuse solar radiation reaching a surface on Earth may come from the sky and reflected solar radiation from adjacent surfaces. On a clear sky, a simplified relation for the diffuse solar radiation reaching any surface from the sky is given by Eq. (13) [3]: Ids ¼ C IDN Fss

ð13Þ

where C is the diffuse radiation factor (dimensionless), Fss is 0.5 and 1.0 for vertical and horizontal surfaces, respectively, IDN is the sky radiation falling on a horizontal surface, and Fss is the angle factor between the surface and the sky (dimensionless) determined by Eq. (14) for other surfaces [3]: Fss ¼ ð1:0 þ cos SÞ=2

ð14Þ

where S is the tilt angle measured upward from the horizontal plane (Fig. 8). Solar radiation reflected by ground has the components of diffuse sky and direct solar radiation falling on a horizontal surface. The amount of total solar radiation reaching the ground is determined by Eq. (15) [3]: ItH ¼ IDN ðC þ sin bÞ

ð15Þ

where IDN times sin b gives the direct radiation falling on a horizontal surface. Then, the ground-reflected diffuse solar radiation on any surface can be estimated by Eq. (16) [3]: Idg ¼ ItH ςg Fsg

ð16Þ

where ςg is the reflectance of the foreground (dimensionless), and Fsg is the angle factor between the surface and the ground (dimensionless). Obviously, the sum of the angle factors equals 1.0, and the angle factor for surface to ground is determined by Eq. (17) [3]: Fsg ¼ ð1:0

cos SÞ=2

And if the surface is exposed to only the ground and the sky, then Fss ¼(1.0 surfaces and foreground surfaces are provided by Threlkeld [4].

ð17Þ Fsg). The reflectance values for different ground

654

Solar Energy

Example 16: Find: the diffuse solar radiation incident on a solar collector first, and then determine the overall total solar radiation reaching a collector surface with a 45-degree slope that faces southeast, at 0830 Atlantic time on March 21, 451N latitude. Solution: Eq. (8) for the local latitude of L¼45 degrees, the declination angle of δ¼ 0 degree (Table 1), and the hour angle of H ¼57.3 degrees gave the solar altitude of b as 22.5 degrees. And then, we calculated IDN as 787.3 W m 2 for 451N latitude at 0830 Atlantic time (i.e., at AST of 0811). And Table 1 gives C¼ 0.071 for March 21. Using Eq. (17) we can calculate the angle factor, Fsg, from the collector to the ground as Fsg ¼ ð1:0

cos 45o Þ=2 ¼ 0:146

Remember that if the surface is exposed to only the ground and the sky, then Fss ¼ (1.0 the collector to the sky, Fss, is calculated as:

Fsg). Therefore, the angle factor from

Fss ¼ ð1:020:146Þ ¼ 0:854 As mentioned earlier, solar radiation reflected by the ground has the components of diffuse sky and direct solar radiation falling on a horizontal surface. Then, the diffuse solar radiation reaching the collector from the sky can be determined using Eq. (13) as Ids ¼ 0:071 ð787:3 W m 2 Þ 0:854 Ids ¼ 47:7 W m

2

The amount of total solar radiation reaching the ground is calculated using Eq. (15): ItH ¼ ð787:3 W m 2 Þ ð0:071 þ sin 22:5o Þ I tH ¼ 357:2 W m

2

If the ground is crushed rock having a solar reflectance of 20% (Table 3), the ground-reflected diffuse radiation, Idg, falling on the collector can then be easily determined using Eq. (16) as
 Idg ¼ 357:2 W m 2 ð0:20Þ ð0:146Þ Idg ¼ 10:4 W m

2

The total diffuse solar radiation falling on the collector is, then, determined as the sum of diffuse sky radiation and the groundreflected diffuse radiation, that is, 47.7 þ 10.4 ¼ 58.1 W m 2. And then, the overall total solar radiation reaching a collector surface with a 45-degree slope that faces southeast, at 0830 Atlantic time on March 21, 451N latitude can be determined by Eq. (7) as It ¼ ID þ Id þ Ir It ¼ 638 W m

2

þ 47:7 W m

It ¼ 696:1 W m

1.15.6

2

þ 10:4 W m

2

2

Insolation Levels at the Earth’s Surface

As explored in the previous section, on a long-term, global average, only 54% of the solar energy passing through the top of the atmosphere reaches the Earth’s surface (Fig. 9). Just a portion of this energy is absorbed at the Earth’s surface, while the remainder is reflected. The reflected portion compared to the incoming radiation is defined as the albedo. Albedo; A ¼ Reflected solar radiation=Incoming solar radiation

Table 3

ð18Þ

Solar reflectance values of various surfaces

Foreground surface

New concrete Old concrete Bright green grass Crushed rock Bitumen and gravel roof Bituminous parking lot

Incident angle (degrees) 20

30

40

50

60

70

0.31 0.22 0.21 0.20 0.14 0.09

0.31 0.22 0.22 0.20 0.14 0.09

0.32 0.22 0.23 0.20 0.14 0.10

0.32 0.23 0.25 0.20 0.14 0.10

0.33 0.23 0.28 0.20 0.14 0.11

0.34 0.25 0.31 0.20 0.14 0.12

Source: Adopted from Threlkeld JL. Thermal environmental engineering. New York, NY: Prentice-Hall; 1962. p. 321.

Solar Energy

Table 4

655

Albedos of typical surfaces

Surface

A

Surface

A

Surface

A

Surface

A

Fresh snow Old snow Gray ice Deep water Dark wet soil Light dry soil Red soil Wet clay Dry clay Wet loam Dry loam

75–95 35–70 60 5–20 6–8 16–18 17 16 23 16 23

Sandy soil Pet soil Lime Gypsum Lava Granite Stones Tundra Sand dune Thick cloud Thin cloud

20–25 5–15 45 55 10 12–18 20–30 15–20 20–45 70–95 20–65

Asphalt road Dirt road Concrete Buildings Mean urban Fallow field Wheat Rice paddy Sugar cane Winter rye Corn

5–15 18–35 15–37 9 15 5–12 10–23 12 15 18–23 18

Tobacco Potatoes Alfalfa Cotton Sorghum Coniferous forest Deciduous forest Green grass Green meadow Savanna Steppe

19 19 23–32 20–22 20 5–15 10–25 26 10–20 15 20

Source: Adopted from Stull RB. Meteorology for scientists and engineers. 2nd ed. Pacific Grove, CA: Thomson Brooks/Cole; 2000. p. 23–38.

Albedo is normally expressed as a percentage, and satellite measurements indicate that the Earth’s surface has an average albedo value of 8%; that is, on average, 8% of the insolation reaching the Earth’s surface is reflected back. Albedos for typical surfaces are presented in Table 4. When both sides of Eq. (18) are multiplied by the incoming solar radiation, then the expression becomes Reflected solar radiation ¼ A  Incoming solar radiation

ð19Þ

Example 17: Find: using Eq. (19) and an average surface albedo of 8% (i.e., 0.08), determine the reflected solar radiation. Solution: Reflected solar radiation ¼ A  Incoming solar radiation ¼ 0:08  54 units Reflected solar radiation ¼ 4:32 ðB 4Þ units reflected (see Fig. 9) If the albedo concept is applied to the whole Earth and atmosphere system, then we obtain the so-called planetary albedo, which has a long-term average value of 30%; that is, 30 units (20 from clouds, 6 from atmosphere, and 4 from the Earth’s surface) of the sample 100 units of solar energy are reflected back to space (Fig. 9). The remaining 70% of the solar energy reaching the Earth and atmosphere system is absorbed and transformed into heat. In Section 5, we defined insolation as the amount of solar radiation reaching onto a horizontal surface – short for “incoming solar radiation.” Basically, that means how much sunlight is shining down on us. By knowing the insolation levels of a particular region, we can actually determine the size of solar collector that is required, and how much energy it can produce. Obviously, an area with poor insolation levels will need a larger collector area than an area with high levels. For application purposes, insolation level is generally expressed in kWh m 2 day 1, and is the amount of solar energy that strikes a square meter of the Earth’s surface in a single day. Btu or MJ may also be used, in which case the conversion is: 1 kWh m 2 day 1 ¼ 317.1 or Btu ft 2 day 1 ¼ 3.6 MJ m 2 day 1. The raw energy conversions are: 1 kWh ¼3412 Btu ¼ 3.6 MJ. As discussed earlier in depth, insolation levels change throughout the year, with the lowest in winter and the highest in summer. And, close to the equator, the difference throughout the year is minimal whereas at high latitudes winter can be just a fraction of summer levels. A very high summer value, as we would see in a hot desert area is 7 kWh m 2 day 1. For comparison purposes, the readers are referred to the average annual insolation values for Oslo, Norway ¼2.27 kWh m 2 day 1 (considered as very low) and Miami, Florida ¼5.26 kWh m 2 day 1 (considered as very high). Tables 5–10 list the average insolation values for major cities in each region of the world, which can be used in solar energy project designs [5]. The NASA Surface Meteorology and Solar Energy (SSE) data set consists of resource parameters that were developed and formulated for assessing and designing renewable energy systems. The monthly average amount of the total solar radiation incident on a horizontal surface at the surface of the Earth for a given month, is averaged for that month over a 10-year period. Each monthly averaged value was evaluated as the numerical average of 3-hourly values for the given month. Renewable energy technologies range in complexity from the introduction of solar ovens and simple photovoltaics panels into rural communities to the construction of commercial buildings with integrated photovoltaics and large thermal and wind generating power plants. The availability of accurate global solar radiation and meteorology data is extremely important for successful renewable energy projects. NASA’s Earth Science Enterprise (ESE) makes the SSE data set available free of charge over the Internet (http://eosweb.larc.nasa.gov/sse/). Historically, climatological profiles of insolation and meteorology parameters calculated from ground measurements have been used for determining the viability of renewable energy projects. Although ground measurement data have been used successfully, ground measurement stations are situated mainly in populated regions. In remote areas, where many renewable energy projects are being implemented, measurement stations are quite limited. Also, at some stations, available data can be

656

Solar Energy

Table 5

Monthly and annual average of daily insolation values (kWh m

2

day 1) for Africa

AFRICA Country

City

Lat

Long

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Year Avg

B. Faso C. A. Rep. Cameroon Djibouti Algeria Egypt Ethiopia Ghana Gambia Guinea Kenya Liberia Libya Morocco Mali Mauritania Niger Nigeria Sudan Sierra Leone Senegal Somalia Tunisia

Ouagadougou Bangui Yaoundé Djibouti Alger Cairo Addis Ababa Accra Gambia Conakry Nairobi Liberia Tarabulus Rabat Bamako Nouakchott Niamey Abuja Al Khurtum Freetown Dakar Muqdisho Tunis

121 240 N 181 320 N 31 480 N 111 330 N 361 500 N 291 350 N 91 20 N 51 360 N 131 280 N 91 360 N 11 160 S 61 3000 N 321 540 N 321 320 N 121 300 N 171 450 N 131 300 N 91 120 N 151 330 N 81 290 N 141 380 N 21 020 N 361 480 N

11 300 E 1201 360 E 111 300 W 431 090 E 31 000 E 311 090 E 381 420 E 01 120 W 161 390 W 131 360 E 361 480 E 91 300 W 131 110 W 91 170 W 71 540 E 151 450 E 21 120 W 71 110 E 331 320 E 131 140 W 171 270 W 451 200 E 101 680 E

5.48 4.13 4.94 5.60 2.22 3.39 5.96 5.65 5.01 5.81 6.05 5.43 3.10 3.13 5.61 5.31 5.42 5.57 5.46 5.19 4.84 6.38 2.29

6.43 4.97 5.38 5.77 2.94 4.17 5.80 6.01 5.93 6.41 6.24 5.72 4.03 3.86 6.35 6.21 6.39 6.33 6.19 5.91 5.77 6.81 3.06

6.56 5.99 5.16 6.59 3.87 5.24 6.23 5.65 6.67 6.51 6.07 5.59 5.19 5.09 6.64 6.80 6.72 6.22 6.75 6.08 6.56 6.71 4.09

6.62 6.61 4.68 6.81 5.00 6.49 6.31 5.33 6.92 6.22 5.70 5.31 6.48 6.08 6.78 7.54 6.79 6.10 7.25 5.47 6.81 6.28 5.47

6.53 6.17 4.46 6.85 5.88 7.11 6.11 5.00 6.72 5.69 5.42 5.11 6.89 6.89 6.42 7.57 6.75 5.89 6.85 4.76 6.70 5.85 6.38

6.16 5.53 4.42 6.87 6.69 8.00 5.79 4.49 6.06 5.69 5.14 4.61 7.77 7.31 6.47 7.63 6.31 5.47 6.96 4.09 5.70 5.45 7.16

6.76 5.73 5.17 6.46 7.23 7.88 5.03 4.50 5.48 5.09 4.88 4.25 8.11 7.34 5.87 7.20 6.07 4.92 6.52 3.60 5.15 5.21 7.57

5.48 4.87 5.07 6.47 6.48 7.40 5.00 4.59 5.09 5.05 5.09 4.19 7.45 6.80 5.65 6.90 5.78 4.65 6.35 3.58 5.01 5.61 6.80

5.87 5.07 5.03 6.56 5.15 6.42 5.64 4.67 5.30 5.46 5.78 4.67 6.12 5.69 6.04 6.78 6.07 5.12 6.42 4.25 5.13 6.15 5.33

6.18 4.55 5.40 6.77 3.53 5.07 6.31 5.25 5.67 5.87 6.03 5.13 4.58 4.37 6.13 6.34 6.16 5.82 6.17 4.84 5.46 6.16 3.65

5.83 4.07 5.29 6.22 2.43 3.86 6.15 5.70 5.36 5.98 5.48 5.24 3.35 3.25 5.85 5.49 5.79 5.81 5.66 4.93 5.03 6.00 2.54

5.35 3.81 4.83 5.56 2.02 3.19 5.75 5.55 4.95 5.60 5.60 5.20 2.76 2.82 5.36 4.88 5.29 5.42 5.22 4.94 4.63 5.91 2.08

6.02 5.12 4.98 6.37 4.45 5.68 5.84 5.20 5.76 5.78 5.62 5.03 5.48 5.21 6.09 6.55 6.12 5.61 6.31 4.80 5.56 6.04 4.70

sporadic and incomplete, and data inconsistencies may occur as well. In contrast to ground measurements, the SSE data set is continuous, consistent, and long-term global insolation data. Although the SSE data within a particular grid cell are not necessarily representative of a particular microclimate, or point, within the cell, the data are considered to be the average over the entire area of the cell. The SSE data set is however not intended to replace ground measurement data. NASA reports that it is prepared to fill the gap where ground measurements do not exist, and to augment areas where ground measurements are available. In utilizing the SSE data set, the renewable energy resource potential can be determined for any location on the globe and is considered to be accurate for preliminary feasibility studies for renewable energy projects. Detailed insolation information (including direct solar normal and diffuse components, and more) for any particular location or time can be directly obtained from NASA [6]. Table 11, on the other hand, lists the estimates of annual solar resource availabilities and ranks around the world, and may prove to be useful [6]. Example 18: Find: assuming that the flat plate collector (FPC) efficiency is 50% and ignoring the ground-reflected radiation falling on the collector, determine the collector size to be tilted from the horizontal surface facing south (for both Los Angeles (341N latitude), California, USA, and Halifax (451N latitude), Nova Scotia, Canada) needed to heat a total of 150 L of hot water per day (required for four people living in a household) from 10 to 501C in March. Solution: We know that the amount of heat required for the given temperature difference can be calculated using the equation Q¼ m Cp DT, where m is the mass of water, Cp is the specific heat of water, and Q is the heat needed.
 Q ¼ 150 kg 4186 J kg 1 o C 1 ð50210Þo C Q ¼ 25; 116; 000 J day

1




B 25:1 MJ day

1



The heat available from the FPC is Q¼ Insolation  FPC Area  Efficiency. Table 10 provides the average intensity of the insolation falling on the ground for March in Los Angeles as 5.09 kWh m 2 day 1. Then, the heat available from the FPC is
 25:1 MJ day 1 ¼ ð5:09 kWh m 2 day 1 Þ 3:6 MJ kWh 1  FPC Area ðm2 Þ  0:5 Collector Area ¼ 2:7 m2 As a useful rule of thumb, the collector should be tilted 44–45 degrees from the horizontal surface facing south for Los Angeles (341N local latitude plus 10 degrees), California, USA.

Solar Energy

Table 6

Monthly and annual average of daily insolation values (kWh m

2

657

day 1) for Asia-Pacific

ASIA-PACIFIC Country

City

Lat

Long

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Year Avg

UAE Australia Australia Australia Australia Australia Australia Bangladesh China China China China Indonesia Israel Iran Iran Iran Iran India India India Iraq Jordan Japan Cambodia North Korea Korea Laos Lebanon Myanmar Mongolia Malaysia New Zealand New Zealand New Zealand Oman Philippines Philippines S. Arabia

Abu Dhabi Adelaide Brisbane Hobart Melbourne Perth Sydney Dhaka Beijing Nanjing Shanghai Hong Kong Jakarta Tel Aviv Tabriz Tehran Mashhad Bandar Abbas New Delhi Bombay Bangalore Baghdad Amman Tokyo Phnom Penh Pyongyang Seoul Vientiane Beirut Yangon Ulaanbaatar Kuala Lumpur Auckland Christchurch Wellington Muscat Cebu Manila Riyadh Singapore C. Bangkok Chiang Mai Hanoi Aden

241 280 N 341 550 S 271 990 S 421 520 S 371 470 S 311 570 S 341 000 S 231 420 N 391 550 N 321 030 N 311 100 N 221 180 N 61 110 S 321 050 N 381 480 N 351 400 N 361 160 N 271 150 N 281 000 N 181 330 N 121 570 N 331 200 N 311 570 N 351 350 N 111 330 N 391 000 N 371 310 N 181 070 N 331 540 N 161 470 N 471 550 N 31 070 N 361 520 S 431 320 S 411 170 S 231 370 N 101 190 N 141 370 N 241 390 N 11 000 N 131 450 N 181 000 N 211 000 N 121 500 N

541 220 E 1381 360 E 1531 080 E 1471 190 E 1441 580 E 1151 520 E 1511 000 E 901 220 E 1161 250 E 1181 530 E 1211 280 E 1141 100 E 1061 500 E 341 460 E 461 180 E 511 260 E 591 340 E 561 150 E

3.92 7.20 6.93 5.97 6.78 7.70 6.34 4.44 2.37 2.04 2.29 2.59 4.15 2.78 1.79 2.23 2.22 3.63 3.68 5.22 5.00 2.79 2.93 2.31 5.27 2.50 2.62 4.30 2.64 5.40 1.79 4.54 6.37 5.90 6.27 4.34 4.53 4.82 4.03 4.43 4.42 4.79 2.52 5.45

4.50 6.58 6.09 5.33 6.22 6.75 5.68 5.08 2.92 2.22 2.63 2.56 4.59 3.50 2.40 2.84 2.97 4.43 4.47 6.03 5.90 3.64 3.67 2.99 5.78 3.35 3.40 4.94 3.40 6.06 2.77 5.27 5.90 4.95 5.31 5.00 5.15 5.62 4.92 5.52 4.65 5.51 2.94 5.78

5.22 5.18 5.44 4.05 4.76 5.41 4.87 5.87 3.58 2.65 3.07 3.06 5.00 4.73 3.37 3.72 3.88 5.14 5.50 6.66 6.44 4.59 4.83 3.70 6.02 4.50 4.29 5.52 4.63 6.65 4.24 5.14 4.71 3.86 4.17 5.85 5.83 6.42 5.56 5.05 4.84 6.11 3.81 6.52

5.87 3.85 4.34 2.73 3.40 4.16 3.60 6.06 5.61 4.50 4.54 3.93 4.94 6.03 4.58 5.12 5.21 6.29 6.60 7.05 6.42 5.76 6.04 4.90 5.76 5.17 5.24 5.74 6.03 6.69 5.53 5.05 3.43 2.75 3.00 6.69 6.25 6.75 6.24 5.05 5.03 6.29 4.34 6.48

7.06 2.65 3.50 1.79 2.29 3.06 2.74 5.50 4.83 3.84 4.38 4.13 4.88 6.86 5.54 5.99 6.29 7.43 7.08 6.77 6.13 6.83 6.88 5.07 5.09 5.60 5.63 5.11 6.96 5.14 6.26 4.80 2.44 1.72 1.95 7.54 5.90 6.19 7.27 4.62 4.75 5.53 4.66 6.71

7.33 2.23 3.29 1.44 1.84 2.67 2.50 4.41 5.68 4.47 4.59 4.74 4.71 7.87 6.71 7.32 7.49 7.96 6.55 4.59 4.76 8.10 7.91 4.47 4.30 5.35 5.15 4.24 7.90 3.24 6.15 4.98 2.00 1.21 1.54 7.56 4.83 4.96 7.99 4.66 3.77 4.44 4.51 6.72

6.90 2.48 3.52 1.68 2.04 2.89 2.67 4.09 5.42 4.93 5.52 5.81 5.09 7.81 6.97 7.20 7.41 7.41 5.01 3.54 4.48 7.97 7.86 4.88 4.55 4.51 4.26 4.22 7.84 3.30 5.55 4.91 2.25 1.47 1.74 6.91 4.76 4.94 7.86 4.51 4.22 4.16 4.62 6.33

6.64 3.20 4.43 2.41 2.79 3.66 3.54 4.37 4.49 4.50 5.23 4.95 5.46 7.22 6.06 6.41 6.78 6.97 4.62 3.40 4.59 7.29 7.27 5.42 4.07 4.63 4.55 4.19 7.19 2.99 4.88 4.78 2.95 2.15 2.46 6.71 4.93 4.41 7.46 4.61 3.46 4.18 4.62 6.33

6.39 4.46 5.62 3.60 3.94 4.76 4.67 4.17 4.25 3.67 4.03 4.68 5.66 6.19 5.20 5.59 5.70 6.58 5.11 4.72 4.98 6.25 6.25 3.82 4.34 4.22 3.99 4.61 6.13 4.12 4.17 4.54 4.13 3.30 3.66 6.55 4.96 4.86 6.83 4.49 3.63 4.50 4.57 6.41

5.53 5.69 6.18 4.78 5.27 6.09 5.61 4.50 3.20 3.02 3.39 4.05 5.36 4.63 3.26 3.90 4.13 5.51 4.99 5.39 4.68 4.44 4.71 2.98 4.41 3.51 3.64 4.26 4.50 4.51 3.00 4.51 5.23 4.34 4.70 5.93 4.75 4.63 5.80 4.50 3.89 4.34 3.64 6.54

4.54 6.59 6.74 5.92 6.28 7.04 6.32 4.37 2.66 2.88 2.97 3.56 4.76 3.32 2.14 2.61 2.78 4.29 4.15 5.15 4.34 3.04 3.47 2.50 4.88 2.46 2.60 4.21 3.14 4.82 1.82 4.23 6.05 5.43 5.73 4.95 4.49 4.59 4.58 3.98 4.16 4.28 3.29 5.99

3.79 6.74 6.93 6.18 6.46 7.76 6.60 4.13 2.04 2.08 2.38 2.93 4.47 2.62 1.56 2.02 2.06 3.37 3.42 4.80 4.40 2.52 2.76 2.23 5.03 2.09 2.24 4.24 2.44 5.05 1.40 4.07 6.56 5.64 6.01 4.23 4.44 4.50 3.82 3.93 4.40 4.48 3.17 5.39

5.64 4.74 5.25 3.82 4.34 5.16 4.59 4.75 3.92 3.40 4.01 4.18 5.03 5.73 4.13 4.58 4.74 5.75 5.10 5.28 5.18 5.27 5.80 4.00 4.85 4.20 4.16 4.63 5.68 4.65 4.30 4.70 4.34 3.57 3.88 6.29 5.07 5.22 6.03 4.61 4.27 4.88 3.89 6.22

Singapore Thailand Thailand Vietnam Yemen

Table 7

771 000 E 721 320 E 771 370 E 441 240 E 351 570 E 1391 380 E 1041 510 E 1251 180 E 1271 000 E 1021 350 E 351 280 E 961 090 E 1061 540 E 1011 420 E 1741 450 E 1721 370 E 1741 470 E 581 370 E 1231 540 E 1201 580 E 461 420 E 1031 000 E 1001 300 E 991 000 E 1051 540 E 451 020 E

Monthly and annual average of daily insolation values (kWh m

2

day 1) for Canada

CANADA Province

City

Lat

AB BC MB NL NS ON QC SK

Edmonton Victoria Winnipeg St. Johns Halifax Toronto Montreal Regina

531 481 491 451 441 431 451 451

340 250 540 190 390 410 280 190

N N N N N N N N

Long

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Year Avg

1131 310 W 1231 190 W 971 140 W 651 530 W 631 340 W 791 380 W 731 450 W 651 530 W

1.45 1.00 1.21 1.56 1.56 1.44 1.45 1.14

2.36 1.82 2.08 2.27 2.31 2.27 2.36 1.96

3.41 2.93 3.27 3.48 3.46 3.19 3.41 3.02

4.25 4.01 4.55 4.19 4.09 4.13 4.25 4.69

4.91 5.13 5.54 4.76 4.82 5.15 4.91 5.48

5.42 5.54 5.80 5.05 5.27 5.83 5.42 5.79

5.55 5.85 5.85 5.05 5.41 5.67 5.55 6.14

4.76 5.28 4.84 4.54 4.86 4.82 4.76 4.96

3.52 3.88 3.32 3.53 3.92 3.66 3.52 3.42

2.18 2.17 2.21 2.29 2.54 2.47 2.18 2.29

1.43 1.11 1.33 1.43 1.53 1.48 1.43 1.30

1.21 0.86 1.02 1.27 1.30 1.20 1.21 0.95

3.37 3.29 3.41 3.28 3.42 3.44 3.37 3.42

658

Solar Energy

Table 8

Monthly and annual average of daily insolation values (kWh m

2

day 1) for Europe

EUROPE Country Austria Belgium Bulgaria Cyprus Croatia Germany Germany Spain Spain Spain Spain France France France Greece Hungary Ireland Italy Italy Netherlands Norway Romania Portugal Portugal Turkey Ukraine U. Kingdom U. Kingdom Switzerland Switzerland Yugoslavia

City Vienna Bruxelles Sofija Limassol Zagreb Hamburg Munich Madrid Malaga Barcelona Alicante Lyon Paris Toulouse Athens Budapest Dublin Milan Rome Amsterdam Oslo Bucharest Lisboa Oviedo Ankara Odessa Edinburgh London Bern Lausanne Beograd

Lat 481 501 421 341 451 531 481 401 361 411 381 451 481 431 381 471 531 451 411 521 591 441 381 431 391 461 551 511 461 461 441

130 450 400 400 290 330 050 250 430 240 400 460 520 370 000 300 200 280 530 210 560 260 400 210 570 300 560 320 570 320 500

N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N

Long

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Year Avg

161 220 E 41 300 E 231 180 E 331 030 E 151 350 E 91 590 E 111 230 E 31 410 W 41 420 W 21 90 E 01 300 W 41 500 E 21 200 E 11 260 E 231 430 E 191 300 E 61 150 W 91 120 E 121 300 E 41 540 E 101 440 E 261 060 E 91 110 W 51 500 W 321 530 E 301 460 E 31 100 W 01 50 W 71 260 E 61 390 E 201 300 E

1.10 0.74 1.50 2.52 1.30 0.54 1.05 1.93 2.52 1.89 2.23 1.26 0.89 1.39 2.00 1.00 0.56 1.27 1.78 0.61 0.30 1.36 2.27 1.67 1.77 1.08 0.44 0.67 1.10 1.10 1.29

1.81 1.31 2.04 3.26 2.00 1.11 1.80 2.75 3.24 2.71 3.02 1.97 1.62 2.14 2.52 1.71 1.07 1.89 2.52 1.21 0.87 1.94 2.99 2.29 2.38 1.78 0.94 1.26 1.77 1.81 1.89

2.80 2.29 2.97 4.54 2.94 2.09 2.82 4.09 4.51 3.97 4.26 3.02 2.62 3.19 3.67 2.76 1.97 2.91 3.71 2.27 1.68 2.91 4.30 3.44 3.69 2.68 1.86 2.22 2.74 2.80 2.92

3.76 3.68 4.05 6.00 3.91 3.68 3.95 4.83 5.40 4.99 5.39 4.08 3.95 4.03 5.21 3.90 3.32 3.65 4.87 3.76 3.12 3.94 5.15 4.59 4.54 3.87 3.18 3.48 3.60 3.76 3.86

4.76 4.67 5.00 6.85 5.03 4.86 4.84 5.85 6.35 5.82 6.13 4.97 4.90 4.82 6.38 5.03 4.40 4.84 5.98 4.88 4.65 5.03 6.13 5.56 5.53 5.40 4.33 4.54 4.70 4.76 4.88

5.12 4.48 5.80 7.81 5.37 4.47 4.65 6.52 7.09 6.56 6.89 5.40 4.83 5.16 7.52 5.30 4.30 5.36 6.84 4.73 4.84 5.60 6.46 6.32 6.63 5.70 4.34 4.51 5.07 5.12 5.45

5.72 4.82 6.29 7.80 5.93 4.47 5.14 7.11 7.64 7.01 7.34 6.03 5.35 5.86 7.61 5.62 4.30 5.97 7.08 4.78 4.59 6.15 6.89 6.86 6.99 6.39 4.13 4.74 5.68 5.72 6.00

4.98 4.20 5.68 7.18 5.19 3.89 4.46 6.30 6.81 6.07 6.53 5.23 4.61 5.07 6.91 4.84 3.40 5.21 6.34 4.13 3.36 5.53 6.33 5.95 6.55 5.63 3.41 4.01 4.95 4.98 5.30

3.68 2.86 4.46 6.11 3.94 2.59 3.20 4.91 5.39 4.72 5.11 3.93 3.33 4.09 5.57 3.57 2.69 3.91 4.83 2.80 2.22 4.15 5.11 4.51 5.22 3.96 2.43 2.86 3.66 3.68 4.05

2.15 1.73 2.75 4.43 2.39 1.48 2.00 3.07 3.70 3.11 3.45 2.27 2.00 2.48 3.50 2.24 1.43 2.40 3.08 1.60 1.02 2.59 3.44 2.71 3.24 2.45 1.20 1.65 2.18 2.15 2.50

1.28 0.92 1.62 3.02 1.39 0.69 1.02 1.97 2.58 2.04 2.34 1.43 1.12 1.58 2.16 1.17 0.77 1.42 1.98 0.78 0.42 1.37 2.27 1.77 1.99 1.06 0.59 0.89 1.26 1.28 1.40

0.93 0.56 1.27 2.31 1.09 0.40 0.79 1.59 2.14 1.70 1.94 1.08 0.72 1.25 1.63 0.88 0.43 1.08 1.56 0.45 0.19 1.10 1.84 1.46 1.51 0.87 0.32 0.52 0.92 0.93 1.11

3.52 3.02 3.99 5.61 3.72 2.52 2.98 4.62 5.16 4.60 4.94 3.74 3.34 3.75 4.56 3.17 2.39 3.33 4.21 2.67 2.27 3.47 4.43 3.93 4.17 3.41 2.26 2.61 3.14 3.17 3.39

Table 7 provides the average intensity of the insolation falling on the ground for March in Halifax as 3.46 kWh m Then, the heat available from the FPC is
 25:1 MJ day 1 ¼ ð3:46 kWh m 2 day 1 Þ 3:6 MJ kWh 1  FPC Area ðm2 Þ  0:5

2

day 1.

Collector Area ¼ 4:0 m2

Again, the collector should be tilted 55 degrees from the horizontal surface facing south for Halifax (451N local latitude plus 10 degrees), Nova Scotia, Canada. As more insolation is available in Los Angeles compared to that in Halifax, much less (B32%) collector area is required to heat the same amount of water. This example gives us rough approximations for the required collector areas. For a detailed analysis, we would use the average monthly direct and diffuse components of solar radiation per square meter per day, or daily or hourly direct and diffuse components of solar radiation per square meter when available, and perform detailed calculations for the average direct, diffuse, and ground-reflected solar radiation reaching the collector surface for a given collector orientation and tilt angle. Then we would decide what the design collector area is for this application. Example 19: Find: assuming that the flat plate collector (FPC) efficiency is 50%, determine the collector size needed to heat a household for one day when the heating load is 5.86 kW. Use a mean daily insolation falling on the ground as 2.25 kWh m 2 day 1 (or 8.1 MJ m 2 day 1) and the local latitude as 401N. Solution: Remember that Q ¼Insolation  FPC Area  Efficiency. The thermal energy that is needed for a day will be 5.86 kW  (24 h day 1) (3600 s h 1)¼ 506,304 kJ day 1 ¼ 506.3 MJ day 1. The solar energy collected in one day will be (8.1 MJ m 2 d 1)  FPC Area  Efficiency. Therefore,
 Collector Area ¼ 506:3 MJ day 1 = ½ð8:1 MJ m 2 day 1 Þ  0:5Š Collector Area ¼ 125 m2

Solar Energy

Table 9

Monthly and annual average of daily insolation values (kWh m

2

659

day 1) for South America

SOUTH AMERICA Country

City

Lat

Argentina Argentina Argentina Belize Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Bolivia Bolivia Bolivia Chile Chile Chile Chile Columbia Columbia Columbia Columbia Costa Rica Cuba Ecuador Ecuador El Salvador Guatemala Guiana Guyana Honduras Jamaica Martinique Mexico Mexico Mexico Mexico Mexico Mexico Mexico Mexico Mexico Mexico Mexico Nicaragua Panama Paraguay Peru Peru Peru Puerto Rico Suriname Venezuela Venezuela Venezuela

Buenos Aires Cordoba Rio Gallegos Belize City Belem B. Horizonte Brasilia Curitiba Fortaleza Manaus Porto Alegre Recife Rio de Janeiro Salvador Sao Paulo La Paz Santa Cruz Sucre Iquique Osorno Santiago Valparaiso Bogota Cali Cartagena Medellin San Jose Havana Guayaquil Quito San Salvador City Cayenne Georgetown Tegucigalpa Kingston Fort de France Acapulco Cancun Chihuahua Guadalajara La Paz Mexico City Monterrey Oaxaca Puerto Vallarta Tijuana Veracruz Managua Panama City Asuncion Arequipa Cusco Lima San Juan Paramaribo Caracas Maracaibo Valencia

341 311 511 171 011 191 151 251 031 031 301 081 221 121 231 161 171 191 201 401 331 331 041 031 101 061 091 231 021 001 131 141 041 061 141 171 141 161 211 281 201 241 191 251 171 201 321 191 121 081 251 161 131 401 181 051 101 101 101

490 240 370 300 270 550 520 260 430 080 020 050 540 590 330 290 470 020 130 350 270 010 360 270 250 140 590 090 130 140 400 370 560 500 050 580 370 500 100 390 400 090 260 400 040 390 320 100 100 580 200 250 300 420 150 490 300 390 090

S S S N S S S S S S S S S S S S S S S S S S N N N N N N S S N N N N N N N N N N N N N N N N N N N N S S S N N N N N N

Long

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Year Avg

581 320 W 641 120 W 691 130 W 881 110 W 481 290 W 431 560 W 471 560 W 491 150 W 381 310 W 601 010 W 511 130 W 341 540 W 421 100 W 381 300 W 461 390 W 681 080 W 631 100 W 651 150 W 701 100 W 731 140 W 701 420 W 711 380 W 741 050 W 761 300 W 751 320 W 751 340 W 841 040 W 821 210 W 791 540 W 781 300 W 891 100 W 901 310 W 521 270 W 581 120 W 871 140 W 761 480 W 611 050 W 991 540 W 861 500 W 1061 050 W 1031 400 W 1101 180 W 991 080 W 1001 230 W 961 430 W 1051 140 W 1171 010 W 961 070 W 861 150 W 791 330 W 571 310 W 711 320 W 711 580 W 841 020 W 661 300 W 551 090 W 661 540 W 711 360 W 681 000 W

6.44 7.07 5.47 3.73 4.54 5.45 5.21 5.48 5.85 4.15 6.08 6.59 5.40 5.89 5.44 5.30 4.57 1.67 7.42 6.78 7.55 7.55 4.50 3.63 5.74 3.95 6.09 4.09 6.07 3.57 5.58 4.93 3.91 4.12 4.26 4.92 5.35 5.46 4.16 3.41 4.24 3.73 4.34 3.33 4.36 4.20 3.32 3.55 5.34 5.27 6.10 4.95 4.19 1.57 4.26 4.13 5.14 4.71 5.75

5.67 6.30 4.63 4.59 4.34 5.63 5.15 4.88 5.44 4.12 5.56 6.22 5.34 5.79 5.05 5.57 4.90 2.29 7.34 6.02 6.56 6.56 4.48 3.90 6.18 4.22 6.74 4.97 6.01 3.56 6.23 5.48 4.34 4.57 5.08 5.67 5.98 6.30 5.14 4.34 5.18 4.67 5.07 4.20 4.99 5.29 4.15 4.13 5.89 5.92 5.77 5.26 4.43 2.48 4.90 4.63 5.82 5.09 6.68

4.53 4.90 3.32 5.45 4.26 5.34 5.09 4.32 4.82 4.22 4.54 5.95 4.87 5.28 4.75 5.16 4.57 3.47 6.19 4.34 5.13 5.13 4.67 4.09 6.54 4.38 7.23 5.92 6.31 3.71 6.68 5.90 4.55 4.98 5.84 6.45 6.59 7.17 6.04 5.63 6.21 5.75 5.89 5.40 5.74 6.39 5.23 4.86 6.59 6.23 4.98 4.88 4.23 3.21 5.70 5.07 6.11 5.42 7.17

3.53 3.87 2.02 5.97 4.46 4.78 4.99 3.57 4.80 4.34 3.48 5.05 4.11 4.59 4.21 5.01 3.92 4.58 4.70 2.93 3.83 3.83 4.46 3.89 6.30 3.95 6.64 7.06 6.31 3.71 6.52 5.81 4.66 5.09 5.99 6.80 6.94 7.41 6.86 6.43 6.71 6.63 5.95 5.71 6.08 7.12 6.37 5.35 6.54 5.75 3.84 4.90 3.99 4.46 6.09 5.08 5.94 5.22 7.28

2.74 3.01 1.07 5.75 4.75 4.30 4.80 2.95 5.11 4.08 2.81 4.84 3.43 4.09 3.47 4.78 3.44 5.59 3.45 1.91 2.59 2.59 4.45 3.76 5.62 4.01 5.26 7.15 5.83 3.73 5.95 5.35 4.04 4.49 5.54 6.50 6.70 7.06 6.79 6.88 6.89 7.16 5.90 6.06 5.86 7.51 6.61 5.40 5.83 4.78 3.48 4.80 3.74 5.37 5.89 4.78 5.76 5.12 6.48

2.04 2.65 0.71 5.19 4.99 4.09 4.59 2.83 5.34 4.24 2.27 4.61 3.35 3.75 3.36 4.37 3.25 6.37 2.78 1.43 2.22 2.22 4.63 3.71 5.56 4.36 5.00 7.10 4.88 3.81 5.74 4.91 4.25 4.32 5.35 6.82 6.42 6.16 6.47 6.53 6.00 7.07 5.03 5.89 5.01 6.96 6.43 5.12 5.67 4.11 2.76 4.53 3.56 5.97 6.09 4.78 5.63 5.28 5.11

2.31 2.79 0.81 5.03 5.27 4.32 4.86 2.96 5.74 4.55 2.50 4.38 3.39 3.83 3.54 4.51 3.44 6.86 3.04 1.69 2.38 2.38 4.71 4.05 5.66 4.67 4.94 6.90 4.50 3.85 6.22 5.27 4.96 4.65 5.34 6.84 6.49 6.29 6.63 5.69 5.23 6.40 4.76 5.59 4.92 6.17 6.46 5.15 5.70 4.16 3.09 4.78 4.01 5.58 6.08 5.12 5.77 5.49 5.92

3.27 3.63 1.61 5.16 5.50 4.82 5.46 3.47 6.34 4.98 3.06 5.07 3.83 4.26 4.19 4.96 4.01 5.97 3.39 2.48 3.09 3.09 4.70 3.93 5.72 4.51 4.84 6.86 4.50 3.88 6.18 5.12 5.40 4.90 5.47 6.61 6.45 6.20 6.65 5.30 5.41 6.06 4.86 5.44 4.95 5.99 6.31 5.17 5.69 4.15 3.97 5.16 4.29 5.18 5.78 5.42 5.77 5.31 6.26

4.23 4.76 2.87 4.82 5.85 5.05 5.28 3.87 6.60 5.23 3.89 5.78 3.77 4.79 4.25 5.66 4.45 4.51 4.53 3.50 4.08 4.08 4.80 3.89 5.35 4.37 4.76 6.10 4.95 3.89 5.49 4.59 5.81 5.15 5.04 6.23 6.03 5.45 5.86 5.14 5.14 5.52 4.57 4.76 4.43 5.32 5.40 4.66 5.43 4.24 4.49 5.70 4.55 4.58 5.26 5.87 5.72 5.20 6.26

5.12 5.93 4.26 4.50 5.79 5.26 5.23 4.65 6.62 4.93 5.01 6.23 4.41 5.32 5.09 5.98 5.00 2.73 5.37 4.95 5.64 5.64 4.28 3.52 4.72 3.82 4.63 5.12 4.69 3.79 5.61 4.68 5.51 4.88 4.43 5.45 5.87 5.94 5.19 4.65 5.11 4.93 4.73 4.49 4.63 5.30 4.26 4.45 5.39 3.99 5.26 5.84 4.72 3.09 4.80 5.61 5.56 4.68 6.13

6.36 6.63 5.53 3.99 5.52 5.25 4.97 5.44 6.50 4.72 5.93 6.40 4.97 5.38 5.73 6.15 5.21 1.77 6.36 6.47 6.84 6.84 4.24 3.49 4.90 3.78 4.63 4.26 5.29 3.85 5.42 4.65 4.91 4.42 4.15 4.76 5.15 5.56 4.51 3.89 4.79 4.11 4.57 3.90 4.38 4.82 3.65 3.92 5.15 4.23 6.22 5.96 4.67 1.81 4.36 4.97 5.01 4.55 5.76

6.44 6.96 5.79 3.54 4.96 4.98 4.82 5.41 6.16 4.23 6.50 6.48 4.98 5.61 5.38 5.92 5.01 1.46 7.40 6.98 7.82 7.82 4.32 3.44 5.30 3.86 5.30 3.74 5.93 3.68 5.30 4.62 4.29 4.01 3.91 4.58 5.15 5.19 3.90 3.26 4.13 3.51 4.29 3.23 4.08 4.00 3.08 3.43 5.05 4.66 6.26 5.54 4.50 1.33 4.15 4.47 4.84 4.51 5.41

4.39 4.88 3.17 4.81 5.02 4.94 5.03 4.15 5.78 4.48 4.30 5.63 4.32 4.88 4.54 5.28 4.31 3.93 5.16 4.12 4.81 4.81 4.52 3.78 5.63 4.16 5.51 5.77 5.44 3.75 5.91 5.11 4.72 4.63 5.03 5.97 6.09 6.18 5.68 5.10 5.42 5.46 5.00 4.83 4.95 5.76 5.11 4.60 5.69 4.79 4.68 5.19 4.24 3.71 5.28 4.99 5.59 5.05 6.18

Solar Energy

660

Table 10

Monthly and annual average of daily insolation values (kWh m

2

day 1) for the USA

UNITED STATES OF AMERICA State

City

Lat

AL AK AR AZ CA CA CO CT DE FL GA HI IA ID IN IL KS KY LA MA MD ME MI MO MN MS MT MT NC ND NE NH NJ NM NV NY OH OK OR PA PA RI SC SD TN TX TX UT VA VT WA WI WV WY

Birmingham Anchorage Little Rock Phoenix Los Angeles San Francisco Denver Hartford Dover Miami Atlanta Honolulu Dubuque Boise Indianapolis Chicago Kansas City Louisville New Orleans Boston Annapolis Portland Detroit St. Louis Minneapolis Jackson Billings Great Falls Charlotte Fargo Omaha Manchester Trenton Albuquerque Las Vegas New York Columbus Tulsa Portland Philadelphia Pittsburgh Providence Columbia Sioux Falls Nashville San Antonio Houston Salt Lake City Washington Montpelier Seattle Milwaukee Charleston Casper

330 610 320 330 340 380 390 410 390 250 330 210 420 430 390 410 390 380 290 420 380 450 420 380 440 420 450 430 350 460 410 420 400 350 360 410 390 360 450 390 400 410 380 450 360 290 290 400 380 440 470 420 380 420

3400 1000 2500 2600 0000 3100 4500 4400 0800 4800 3900 2000 2400 3400 4400 5300 1200 1100 3700 2200 3500 3600 2500 4500 5300 1600 4800 3300 1300 5400 1800 5600 1300 0300 1800 0000 1600 1200 3200 5300 2700 4400 5800 2700 0700 3200 5900 4600 5100 1600 3200 5700 2200 5500

N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N

Long

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Year Avg

860 4500 W 1500 0100 W 940 4400 W 1120 0100 W 1180 0000 W 1210 3000 W 1040 5200 W 720 3900 W 750 2800 W 800 1600 W 840 2600 W 1570 5500 W 900 4200 W 1160 1300 W 860 1700 W 870 3800 W 940 3600 W 850 4400 W 900 0500 W 710 0200 W 760 2100 W 1220 3600 W 830 0100 W 900 2300 W 930 1300 W 840 2800 W 1080 3200 W 960 4200 W 800 5600 W 960 4800 W 950 5400 W 710 2600 W 740 4600 W 1060 3700 W 1150 1600 W 740 0000 W 850 5400 W 950 5400 W 1220 4000 W 750 1500 W 790 5700 W 710 2600 W 920 2200 W 980 2500 W 860 4100 W 980 2800 W 950 2200 W 11100 5200 W 770 0200 W 720 3500 W 1220 1800 W 870 5400 W 810 3600 W 1060 2800 W

2.29 0.21 2.36 3.25 3.09 2.35 2.25 1.70 1.85 3.72 2.31 4.38 1.64 1.73 1.67 1.50 2.06 1.71 2.64 1.66 1.96 1.38 1.43 2.02 1.60 1.47 1.55 1.30 2.22 1.44 1.92 1.66 1.71 2.92 3.02 1.67 1.64 2.33 1.38 1.85 1.59 1.70 2.14 1.72 1.94 2.57 2.47 2.23 1.95 1.58 1.14 1.43 1.75 1.93

3.31 0.76 3.39 4.41 4.25 3.33 3.20 2.43 2.62 4.61 3.37 5.15 2.58 2.72 2.59 2.45 2.89 2.65 3.73 2.50 2.80 2.33 2.33 2.82 2.61 2.41 2.57 2.36 3.17 2.39 2.76 2.50 2.39 3.97 4.13 2.37 2.57 3.22 2.33 2.62 2.40 2.46 2.91 2.71 2.90 3.70 3.50 3.15 2.80 2.54 2.04 2.41 2.64 2.80

4.04 1.68 4.01 5.17 5.09 4.42 4.32 3.48 3.60 5.42 4.08 5.99 3.34 3.77 3.28 3.20 3.62 3.32 4.67 3.51 3.71 3.49 3.19 3.52 3.30 3.22 3.52 3.41 3.95 3.36 3.45 3.51 3.43 4.92 5.05 3.41 3.26 3.90 3.49 3.60 3.26 3.53 3.62 3.31 3.54 4.43 4.40 4.09 3.66 3.50 3.23 3.29 3.34 3.79

5.14 3.12 5.32 6.76 6.58 5.95 5.61 4.07 4.33 6.40 5.20 6.69 4.57 5.22 4.67 4.48 4.92 4.73 5.80 4.13 4.55 4.57 4.34 4.97 4.55 4.33 4.82 4.84 4.98 4.79 4.74 4.13 4.04 6.30 6.57 3.93 4.63 5.25 4.57 4.33 4.07 4.20 5.03 4.65 4.76 5.54 5.59 5.57 4.46 4.05 4.26 4.48 4.26 5.13

5.92 3.98 5.71 7.42 7.29 6.84 6.11 5.14 5.44 6.61 6.02 7.05 5.54 5.90 5.46 5.56 5.58 5.38 6.60 5.11 5.54 5.46 5.44 5.56 5.44 5.46 5.63 5.56 5.80 5.62 5.60 5.11 5.26 6.68 7.25 5.11 5.40 5.58 5.46 5.44 5.05 5.17 5.56 5.61 5.57 5.94 6.03 6.26 5.42 5.00 5.19 5.60 5.20 5.90

5.98 4.58 6.19 7.70 7.62 7.39 6.71 5.58 5.91 6.29 6.01 7.48 6.06 6.57 6.11 6.07 6.17 6.08 6.15 5.47 6.03 6.09 5.98 6.21 5.86 5.93 6.45 6.18 6.01 5.82 6.14 5.47 5.67 6.94 7.69 5.48 6.08 6.32 6.09 5.91 5.53 5.67 6.22 6.10 5.90 6.62 6.45 6.98 5.88 5.24 5.75 6.09 5.67 6.68

5.81 4.25 6.15 6.99 7.45 7.55 6.50 5.38 5.64 6.26 5.81 7.37 5.81 7.17 5.79 5.68 6.21 5.79 6.09 5.44 5.77 6.64 5.64 6.05 5.77 5.57 6.39 6.44 5.76 5.94 6.11 5.44 5.39 6.66 7.37 5.26 5.73 6.40 6.64 5.64 5.27 5.48 6.13 6.04 5.86 6.49 6.36 6.86 5.63 5.37 6.27 5.74 5.49 6.50

5.70 3.16 5.85 6.11 6.72 6.51 5.86 5.04 5.30 6.08 5.59 7.07 5.26 6.12 5.37 5.27 5.59 5.35 5.70 5.05 5.34 5.78 4.99 5.63 5.12 4.99 5.75 5.53 5.27 5.14 5.46 5.05 5.14 5.80 6.42 5.01 5.29 5.80 5.78 5.30 4.94 5.08 5.64 5.42 5.62 6.28 6.07 5.98 5.22 4.92 5.46 5.21 5.19 5.90

4.80 1.98 5.25 6.02 6.11 5.75 5.47 4.13 4.38 5.47 4.76 6.51 4.33 5.28 4.76 4.51 4.90 4.80 5.13 4.12 4.48 4.80 4.25 4.91 4.12 4.30 4.67 4.40 4.58 4.01 4.74 4.12 4.18 5.68 6.08 4.05 4.74 5.08 4.80 4.38 4.05 4.21 4.95 4.47 4.63 5.70 5.46 5.39 4.38 3.79 4.43 4.34 4.26 5.13

3.93 0.98 4.17 4.44 4.42 3.92 4.01 2.91 3.23 4.84 3.95 5.46 3.03 3.29 3.33 3.07 3.49 3.42 4.48 2.84 3.40 2.79 2.73 3.55 2.90 2.78 3.19 2.90 3.75 2.83 3.34 2.84 3.00 4.18 4.26 2.85 3.29 3.80 2.79 3.23 2.88 2.97 3.57 3.20 3.53 4.67 4.61 3.68 3.36 2.46 2.50 2.90 3.19 3.59

2.96 0.37 2.95 3.52 3.43 2.65 2.59 1.81 2.21 3.96 2.98 4.41 1.72 1.74 1.97 1.69 2.20 2.10 3.49 1.74 2.37 1.41 1.52 2.21 1.62 1.55 1.77 1.53 2.76 1.59 2.00 1.74 1.98 3.16 3.18 1.82 1.96 2.62 1.41 2.21 1.86 1.80 2.25 1.78 2.45 3.43 3.30 2.29 2.34 1.52 1.21 1.60 2.15 2.06

2.25 0.12 2.25 2.75 2.72 2.06 1.98 1.42 1.66 3.46 2.33 4.01 1.35 1.46 1.46 1.26 1.75 1.56 2.68 1.40 1.81 1.10 1.14 1.73 1.34 1.17 1.30 1.11 2.21 1.31 1.57 1.40 1.48 2.50 2.60 1.40 1.45 2.06 1.10 1.66 1.41 1.43 1.82 1.43 1.82 2.62 2.44 1.97 1.79 1.28 0.90 1.20 1.62 1.65

4.34 2.09 4.46 5.38 5.40 4.89 4.55 3.59 3.84 5.26 4.37 5.96 3.77 4.24 3.87 3.72 4.11 3.90 4.76 3.58 3.98 3.82 3.58 4.09 3.68 3.59 3.96 3.79 4.20 3.68 3.98 3.58 3.63 4.97 5.30 3.53 3.83 4.36 3.82 3.84 3.53 3.64 4.15 3.87 4.04 4.83 4.72 4.53 3.90 3.43 3.53 3.69 3.73 4.25

NOTE: A useful rule of thumb is that the collector for space heating should be south facing and inclined at an angle (collector tilt angle from the horizontal) equal to the local latitude plus 10 degrees. Therefore, we would have the collector in the example facing south at 40 degrees plus 10 degrees ¼ 50 degrees. This example gives us a rough approximation for the required collector

Solar Energy

Table 11

661

Global estimates of annual solar resource availabilities and ranks

Country

Total solar resource

Rank

Country

1

30,586,340,907 29,799,042,216 27,373,606,560 25,097,791,333 24,993,114,081 24,557,081,452 21,214,183,621 9,877,095,200 8,702,766,347 8,162,220,322 7,853,433,856 7,245,440,119 6,966,439,615 6,684,341,327 6,469,155,958 5,976,855,697 5,183,911,292 4,967,990,842 4,774,191,855 4,522,957,089 4,312,187,336 4,254,446,931 4,204,499,012 4,094,804,148 3,874,754,634 3,799,653,474 3,688,671,549 3,598,925,249 3,576,841,559 3,220,149,178 3,033,492,156 3,010,691,250 2,888,939,688 2,877,063,979 2,783,723,951 2,586,860,121 2,477,570,615 2,425,883,282 2,208,294,782 2,163,991,070 2,087,670,494 1,982,757,812 1,972,640,705 1,940,406,489 1,904,631,470 1,857,790,043 1,833,110,584 1,655,035,662 1,557,506,043 1,483,722,811 1,376,540,386 1,354,153,408 1,315,121,215 1,302,865,151 1,288,799,143 1,244,136,982 1,202,370,998 1,194,990,362 1,182,610,432

Rank

1

(MWh year ) Russia Antarctica China Australia Brazil USA Canada India Sudan Algeria Argentina Congo Saudi Arabia Kazakhstan Mexico Libya Iran Indonesia Mongolia Chad Mali Niger South Africa Greenland Angola Ethiopia Egypt Mauritania Peru Bolivia Namibia Pakistan Colombia Tanzania Nigeria Venezuela Mozambique Zambia Turkey Somalia Botswana Afghanistan Chile Myanmar Madagascar Kenya Central African Republic Yemen Thailand Turkmenistan Spain Iraq Morocco Zimbabwe Cameroon Papua New Guinea Ukraine Uzbekistan France

Total solar resource (MWh year )

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59

Western Sahara Cote d’Ivoire Burkina Faso Malaysia Vietnam Japan Philippines Italy Uganda Guinea Sweden Ghana Laos Gabon Senegal Germany Ecuador New Zealand Guyana Romania Poland Cambodia Kyrgyzstan Finland Syria Uruguay Tunisia Nepal Norway Eritrea Tajikistan Azerbaijan Suriname United Kingdom Bangladesh Belarus Nicaragua Malawi Benin Cuba Guatemala Honduras Greece North Korea Jordan Portugal South Korea Bulgaria Liberia French Guiana U. Arab Emirates Serbia Sierra Leone Hungary Sri Lanka Panama Austria Togo Georgia

941,144,534 896,134,633 891,425,628 874,948,870 842,394,206 809,152,634 792,147,409 752,180,333 743,105,754 730,013,129 720,428,393 706,055,035 669,083,990 636,664,662 625,811,191 618,698,988 606,283,904 592,697,733 575,822,087 546,457,548 546,278,796 545,084,676 537,285,421 525,698,867 525,529,130 480,236,704 467,022,409 466,643,167 461,031,108 421,357,819 410,128,118 406,543,854 402,456,417 391,017,510 380,054,187 379,989,767 359,009,793 356,284,837 351,781,829 341,066,748 328,690,841 322,616,232 315,471,728 308,975,078 305,225,384 254,296,700 250,682,398 246,668,630 246,447,095 230,746,872 227,379,935 204,507,081 197,129,589 193,442,667 189,451,980 185,228,630 171,630,421 164,906,100 154,072,843

62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 (Continued )

662 Table 11

Solar Energy Continued

Country

Total solar resource

Rank

Country

1

1,112,221,024 1,082,588,294 142,782,217 138,119,861 120,526,347 118,196,504 115,235,200 113,249,947 110,893,425 107,639,065 104,597,933 93,662,159 93,612,073 92,947,587 91,030,882 79,148,789 75,639,933 74,846,821 74,554,898 74,350,170 74,269,255 70,432,530 70,010,532 66,786,632 65,682,560 64,502,359 63,641,107 63,174,808 63,107,651 61,694,537 57,659,687 56,580,281 56,301,253 53,026,489 52,957,983 51,416,631 50,516,428 41,979,985 35,113,084 33,956,864 32,966,799 31,608,742 31,428,125 30,830,444 29,087,248 27,460,529 26,310,294 20,978,817 17,239,249 16,161,174 11,763,273 11,027,846 7,431,057 6,390,168 6,128,264 4,484,426 4,226,407 4,000,504 3,348,890

Rank

1

(MWh year ) Paraguay Oman Iceland Czech Republic Bosnia & Herzegovina Croatia Latvia Lithuania Ireland Bhutan Lesotho Guinea-Bissau Slovakia Haiti Switzerland Estonia Burundi Albania Israel Moldova Armenia Djibouti Denmark Rwanda El Salvador Svalbard Equatorial Guinea Belize Solomon Is. Macedonia Netherlands New Caledonia Kuwait Swaziland Fiji Belgium Timor-Leste Slovenia Montenegro Jamaica Qatar Lebanon The Bahamas The Gambia Cyprus Puerto Rico Vanuatu Falkland Is. Brunei West Bank Trinidad & Tobago Fr. South. & Antarctic Land Cape Verde Reunion Samoa Luxembourg S. Georgia & the S. Sand. Is Mauritius Comoros

Total solar resource (MWh year )

60 61 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179

Dominican Republic Costa Rica Guam Faroe Is. Singapore Kiribati Andorra St. Lucia Mayotte Tonga Bahrain Gaza Strip Barbados Palau Antigua & Barbuda St. Vincent & the Gren. Malta Seychelles Jan Mayen St. Pierre & Miquelon Niue Virgin Isl. Brit Ind. Ocean Territ. Turks & Caicos Islands Grenada Isle of Man Heard Isl. & McD. Isl. Micronesia Cayman Is. St. Kitts & Nevis Aruba Christmas Isl. St. Helena American Samoa Northern Mariana Isl. Liechtenstein Montserrat Anguilla Jersey Wallis & Futuna Cook Isl. British Virgin Isl. Norfolk I. Guernsey Pitcairn Is. San Marino Nauru Tuvalu Wake I. Bouvet I. Bermuda Marshall Is. Cocos Is. Gibraltar Tokelau Juan De Nova Isl. Monaco Glorioso Isl. Jarvis I.

151,187,496 144,132,360 1,091,557 985,501 979,641 956,021 942,917 871,393 789,876 767,298 762,658 715,749 704,490 693,444 693,373 630,724 628,845 613,563 590,583 559,570 546,035 538,895 527,473 524,421 506,763 471,543 463,250 462,954 460,978 450,484 428,781 325,830 268,225 257,185 249,687 245,575 219,511 218,479 217,964 167,101 163,364 121,036 118,244 91,583 84,432 76,547 62,453 50,746 46,186 44,610 40,108 36,982 31,742 15,648 14,277 14,265 13,958 13,681 13,251

121 122 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240 241 242 (Continued )

Solar Energy

Table 11

663

Continued

Country

Total solar resource

Rank

Country

Total solar resource (MWh year 1)

(MWh year 1) Guadeloupe French Polynesia Martinique Sao Tome & Principe Netherlands Antilles Dominica

3,172,077 2,974,099 2,161,820 1,701,402 1,282,311 1,149,538

Rank

180 181 182 183 184 185

Midway Isl. Howland I. Johnston Atoll Baker Isl. Vatican City Maldives

11,458 6,557 1,724 1,443 801 794

243 244 245 246 247 248

area. For a detailed analysis, we would use the average monthly direct and diffuse components of solar radiation per square meter per day, or daily or hourly direct and diffuse components of solar radiation per square meter when available, and perform detailed calculations for the average direct, diffuse, and ground-reflected solar radiation reaching the collector surface for a given collector orientation and tilt angle. Then we would decide what the design collector area is for this application. Example 20: Find: now, using the flat plate collector (125 m2 surface area with an efficiency of 50%) and the household in the previous example (located at 401N latitude and having a heating load of 5.86 kW), calculate how many tons of water would be necessary to store enough thermal energy for let’s say 3 days of space heating. Assume the water in the storage tank begins providing heat at 651C and has a lower temperature limit of 301C (i.e., DT¼ 351C). Solution: The thermal storage system is required to provide heat for space heating, so this heat can be determined as Q ¼ 506:3 MJ day

1

 3 day

1

¼ 1518:9 MJ

For a given temperature difference, we have the equation Q¼ m Cp DT, where Q is the heat taken from the thermal storage system, and DT is the temperature change after lowering its temperature, Cp is the specific heat of water (4186 J kg 1 1C 1), and m is the mass of water we need to determine.
 1518:9 MJ ¼ mass of water ðkgÞ 4186 J kg 1 o C 1 ð35o CÞ m ¼ 10; 367 kg ¼ 10:4 t Example 21: Find: assuming a collector conversion efficiency of 8% and ignoring the ground reflected radiation falling on the collector, determine the collector size to be tilted from the horizontal surface facing south (for both Los Angeles (341N latitude), California, USA, and Halifax (451N latitude), Nova Scotia, Canada) needed to provide power for a community that has an average annual power requirement of 5,000,000 kWh. Solution: The required daily power output for the community is 

5;000;000 kWh year 1 3:6 MJ kWh 1 = ð1 year=365 daysÞ 1

Required daily power output ¼ 49; 315 MJ d

The power available from the collector is Insolation  Collector Area  Efficiency. Table 10 provides the annual average of daily intensity of insolation falling on the ground in Los Angeles as 5.40 kWh m 2 day 1 ( ¼ 19.44 MJ m 2 day 1). Then, the power available from the collector is Collector Area ðm2 Þ ¼ ð49; 315 MJ day

1

Þ = ½ð12:24 MJ m

2

day

1

Þ ð0:08ފ

Collector Area ¼ 50;363 m2 ¼ 5:0 ha As a useful rule of thumb, the collector should be tilted 44–45 degrees from the horizontal surface facing south for Los Angeles (341N local latitude plus 10 degrees), California, USA. Table 7 provides the annual average daily intensity of insolation falling on the ground in Halifax as 3.40 kWh m 2 day 1 ( ¼ 12.24 MJ m 2 day 1). Then, the power available from the collector is Collector Area ðm2 Þ ¼ ð49; 315 MJ day

1

Þ = ½ð12:24 MJ m 2 day

1

Þ ð0:08ފ

Collector Area ¼ 50;363 m2 ¼ 5:0 ha Again, the collector should be tilted 55 degrees from the horizontal surface facing south for Halifax (451N local latitude plus 10 degrees), Nova Scotia, Canada. As more insolation is available in Los Angeles compared to that in Halifax, much less (B38%) collector area is required to generate the same power required. For a detailed analysis, we would use the average monthly direct

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and diffuse components of solar radiation per square meter per day, or daily or hourly direct and diffuse components of solar radiation per square meter when available.

1.15.7

Concluding Remarks

Solar energy powers virtually everything in the Earth and atmosphere system. The seasonal distribution of this energy depends on the orbital characteristics of the Earth revolving around the Sun. The solar spectrum covers the range of radiation from very short wavelengths to very long wavelengths. When the Sun’s radiation passes through the Earth’s atmosphere, it is reflected, scattered, and absorbed by dust particles, gas molecules, ozone, and water vapor. The magnitude of the solar radiation’s attenuation at a given time and location is determined by atmospheric composition and length of atmospheric pathway that the solar radiation travels. And the solar radiation reaching a surface on the Earth has both direct and diffuse components. This radiant energy entering the Earth and atmosphere system is eventually transformed into a variety of other energy forms, and it is believed that it will last for approximately 5.5 billion more years, sustaining life on Earth.

References [1] [2] [3] [4] [5] [6]

McAlester AL. The earth: an introduction to the geological and geophysical sciences. Englewood Cliffs, NJ: Prentice-Hall; 1983. Robinson PJ, Sellers AH. Contemporary climatology. 2nd ed Essex, England: Pearson Education Ltd; 1999. p. 17–38. ASHRAE. Handbook of fundamentals. American society of heating. Atlanta, GA: Refrigeration and Air Conditioning Engineers, Inc.; 1989. p. 27.1–38. Threlkeld JL. Thermal environmental engineering. New York, NY: Prentice-Hall; 1962. p. 321. Taylor FW. Elementary climate physics. New York, NY: Oxford University Press Inc.; 2005. p. 29–39. NASA. Surface meteorology and Solar Energy Data Set. http://eosweb.larc.nasa.gov/sse/; 2016 [accessed 11.11.16].

Relevant Websites http://www.bp.com/content/dam/bp/pdf/energy-economics/statistical-review-2016/bp-statistical-review-of-world-energy-2016-renewable-energy.pdf BP. www.ren21.net/status-of-renewables/global-status-report/ Global Status Report. https://www.iea.org/topics/renewables/subtopics/solar/ International Energy Agency. http://eosweb.larc.nasa.gov/sse/ NASA. https://climatedataguide.ucar.edu/climate-data/surface-solar-radiation-europe-africa-and-atlantic-based-mviri-visible-channnels NCAR. http://wrdc-mgo.nrel.gov/ NREL. http://solargis.com/products/maps-and-gis-data/free/overview/ Solargis. data.un.org/Data.aspx?d=CLINO&f=ElementCode%3A33 United Nations. https://energy.gov/eere/energybasics/articles/solar-radiation-basics U.S. Department of Energy. https://en.wikipedia.org/wiki/Solar_power_by_country Wikipedia. www.wmo.int/pages/prog/arep/gaw/solar-radiation.html WMO. www.globalsolaratlas.info/knowledge-base/data-description World Bank Group. https://www.worldenergy.org/data/resources/resource/solar/ World Energy Council.

1.16 Wind Energy Craig MacEachern and Ilhami Yildiz, Dalhousie University, Halifax, NS, Canada r 2018 Elsevier Inc. All rights reserved.

1.16.1 1.16.2 1.16.2.1 1.16.2.2 1.16.2.3 1.16.2.4 1.16.2.5 1.16.2.6 1.16.2.6.1 1.16.2.6.2 1.16.3 1.16.3.1 1.16.3.2 1.16.3.3 1.16.3.4 1.16.3.5 1.16.4 1.16.4.1 1.16.4.2 1.16.4.3 1.16.4.4 1.16.4.4.1 1.16.4.4.2 1.16.4.4.3 1.16.4.4.4 1.16.4.4.5 1.16.4.4.6 1.16.4.4.7 1.16.4.5 1.16.4.5.1 1.16.4.6 1.16.5 1.16.6 1.16.6.1 1.16.6.2 1.16.6.3 1.16.6.3.1 1.16.6.3.1.1 1.16.6.3.2 1.16.6.3.2.1 1.16.6.3.2.2 1.16.6.3.2.3 1.16.6.3.2.4 1.16.6.3.2.5 1.16.6.4 1.16.7 1.16.7.1 1.16.7.2 1.16.7.2.1 1.16.7.2.1.1 1.16.7.2.1.2 1.16.7.2.1.3 1.16.8

Introduction Wind Properties Basics Sea and Elevation Breezes Seasonal Breezes – Monsoon Eddies Scales of Motion Turbulence Property Effect of turbulence on turbines Physics of Wind Lift Drag Lift-to-Drag Ratio Laminar and Turbulent Flow Wind Exergy and Thermodynamic Analyses Measurement and Analysis of Wind Properties Considerations for a Wind Monitoring Program Measurement Measurement of Wind Direction – Wind Vanes Measurement of Wind Speed – Anemometers Cup anemometer Propeller anemometer Pressure plate anemometer Pressure tube anemometers Sonic anemometer Acoustic doppler sensors (sound detection and ranging) Laser doppler sensors (light detection and ranging) Analysis of Wind Data Wind rose Global Wind Resource Availability Wind to Electricity Energy Conversion Exploitation of Wind Energy Windmills Modern Wind Turbines Classification of Modern Wind Turbines Horizontal axis wind turbines Components of a horizontal axis wind turbine Vertical axis wind turbines Darrieus rotor Musgrove rotor (variable geometry Darrieus vertical axis wind turbine) Giromill rotor (cycloturbine) H rotor Savonius rotor Power and Torque Considerations in Wind Turbines Further Wind Power Applications Hybrid Power Systems Offshore Wind Energy Site characteristics Water depth and wave characteristics Wind profile Seafloor topography and composition Wind Energy Siting, Design, and Grid Integration

Comprehensive Energy Systems, Volume 1

doi:10.1016/B978-0-12-809597-3.00118-8

667 667 667 668 668 668 669 669 669 670 670 670 670 670 671 671 672 672 672 672 673 673 673 674 674 674 675 675 675 676 676 677 681 681 682 682 682 683 684 685 685 685 686 686 687 688 688 689 689 690 690 690 690

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1.16.8.1 Siting a Wind Turbine or Farm 1.16.8.2 Wind Farm Construction and Operation 1.16.8.2.1 Preparation of the chosen site 1.16.8.2.2 Transportation of turbine components 1.16.8.2.3 Turbine assembly 1.16.8.2.4 Connection to the grid 1.16.8.2.5 Turbine monitoring and performance optimization 1.16.8.2.6 Turbine maintenance 1.16.9 Environmental Concerns for Wind Energy 1.16.9.1 Effect on Wildlife 1.16.9.1.1 Birds 1.16.9.1.2 Bats 1.16.9.1.3 Marine animals 1.16.9.2 Deforestation, Erosion, and Sensitive Ecosystems 1.16.9.3 Noise 1.16.9.4 Visual 1.16.10 Global Wind Data and Trends 1.16.11 Current and Future Trends in Wind Energy 1.16.12 Concluding Remarks References Further Readings Relevant Websites

Nomenclature

690 693 693 693 693 694 694 694 694 694 694 695 695 695 695 696 696 698 699 700 701 701

n N P pe Q R T TI V v W Z

Amount of gas Rotor rotational speed Pressure Specific potential energy Heat transfer Universal gas constant Temperature, time Turbulence intensity Volume Wind velocity Work Elevation above sea level

Greek Letters Z Energy efficiency l Tip speed ratio r Density

s t c O

Standard deviation of average wind speed Torque Exergy efficiency Angular velocity

Subscripts a avg b flow G in ke

out pe r s T t Qr W

Outlet Potential energy Across system boundaries Sound Turbine Top Associated with Qr Associated with W

A C Cd Cp Cp Ct D e E h ke m

Area Coefficient Drag coefficient Power coefficient Specific heat Torque coefficient Diameter Specific energy Exergy Specific enthalpy Specific kinetic energy Mass or mass flow

and Superscripts Air Average Bottom System flow Gas Inlet Kinetic energy

Wind Energy

1.16.1

667

Introduction

In a world with ever-growing fossil fuel demands, the need for improved methods of energy generation has never before been so apparent. Wind energy conversion represents one of the most promising options at a time when cleaner energy solutions are required to meet the demand of the exponentially growing population. In its most basic sense, wind is the large-scale movement of air masses caused by differences in atmospheric pressure along with the rotation of the Earth. There are a number of different wind variations, which are dependent on the nature and scale of these pressure differences. Most notably, short-lasting, fast moving winds are known as gusts, fast moving winds around 1 min in duration are known as squalls and long, average winds are termed breezes. These phenomena in combination with other wind flows serve to makeup the wind profile. Inherent to wind, regardless of the form, is energy. This energy is what makes wind energy conversion such an attractive option, as it is readily available and in great abundance in many parts of the globe. Through the construction of wind turbines, which take advantage of the physical forces of lift and drag, wind energy can be converted into electrical energy. This energy represents a clean alternative to fossil fuels provided production and construction was performed in an energy and emission conscious manner. For some time, Europe has been the leader in the technological development and implementation of wind energy systems. While North America has been slow to adapt, wind turbine development has seen a recent increase in response to the issues discussed above. Implementation of large-scale wind farms, such as the Alta Wind Energy Center in California, Los Vientos Wind Farm in Texas, and Shepards Flat Wind Farm in Oregon represent major wind installations constructed in the last 10 years in the United States. Similar wind installations have been commissioned throughout North America and the technology does not seem to be slowing down. The abundance of the resource along with the improved conversion efficiencies of modern turbines has served to set wind energy conversion alongside the most promising renewable energy options.

1.16.2 1.16.2.1

Wind Properties Basics

Wind is a naturally occurring phenomenon, which must be considered among the planet’s greatest resources, especially from a renewable energy standpoint. Wind can best be described as the movement of air at any velocity across the Earth’s surface. Inherent to this movement of air is energy; in fact, the energy of wind varies as the cube of wind velocity [1]. It is this energy, which can be exploited and utilized for a variety of purposes from milling of grains, to more recent advancements in wind-generated electricity. Before exploitation of the wind can properly be discussed, it must first be understood what exactly wind is and where it comes from. As with all forms of energy present on Earth, the energy inherent to wind begins with the Sun. It is well understood that warm air rises, causing cooler air to move downward toward the Earth’s surface. In addition to this, it is also known that the areas closer to the equator tend to be warmer than areas closer to the poles due to a greater absorption of solar radiation based on their proximity to the Sun. This causes the warming of the air in equatorial regions to be greater than warming effect in regions further away from the equator. As a result, warm airs move upwards at the equator and make their way to the poles, where cooler air is circulated downwards [2]. In simplest terms, based on the single-cell model, air rises at the equator and sinks at the poles causing the effect known as wind. In addition to this, the velocity of Earth’s rotation also influences wind. Based on the surface distance from the rotational axis, the velocity with which the Earth is rotating varies dependent on the distance from that axis. As a result, the velocity of Earth’s rotation varies from 1670 km h 1 at the equator to 0 km h 1 at the poles. Finally, seasonal changes will also have a great effect on wind as they play a major role in determining the temperature gradients necessary to the movement of air [2]. There are a number of factors, which affect the movement and velocity of atmospheric air, resulting in the variation seen from day to day and region to region. As a fluid, air tends to move from areas of greater concentration to areas of lower concentration and this is no different within the Earth’s atmosphere. Pressure gradients observed throughout the atmosphere cause winds, which result from the movement of air from areas of high pressure to lower pressure. In addition to this, there is also a pressure gradient force observed in the vertical direction, though the gravitational force generally cancels this out. As a result, wind is almost entirely observed in the horizontal plane, with air moving across the Earth’s surface [2]. In addition to these factors, the inertia of the air and the frictional force with the Earth’s surface also play a major role in determining wind velocity and movement. Specific to surface friction, this effect causes air turbulence, which can be described as the violent and disorderly movement of a fluid. Turbulence can be induced by surface obstructions, such as mountains, forests, and buildings and can have a great effect on a regional wind profile dependent on scale, orientation, and other climatic effects. As mentioned above, topography can have a great effect on wind and air movement, especially on a regional level. Areas on top of hills experience greater wind speeds than those in valleys protected by large hills or mountains. In addition to this, areas sheltered by forests or large buildings may also experience reductions in wind velocity. Consider a city, such as Tucson, Arizona, which in addition to its desert climate, is sheltered from the wind by a series of mountains. The Tucson Mountains lie directly west of the city, The Sierrita Mountains to the southwest, The Santa Rita Mountains lie to the south, The Rincon Mountains to the east, The Santa Catalina Mountains to the northeast, and The Tortilita Mountains to the northwest. In combination, the desert climate coupled with the almost 360-degree protection provided by the surrounding mountains results in especially low wind speeds in the region. Average daily wind speeds in Tucson range from 2 to 3 m s 1 and rarely exceed 12 m s 1 [3]. Compare this with a

668

Wind Energy

relatively exposed city, such as Boston, Massachusetts, and a far different scenario can be observed. Boston is considered to have a humid continental climate under the Köppen climate classification, and in addition, is a coastal city with relatively little in the way of windbreaks to its inland sides. As a result, the city experiences average daily wind speeds ranging from 6 to 9 m s 1 [4]. The topographic and climatic differences between the two cities serve to demonstrate the drastic effect these factors can have on wind velocity. Speaking more specifically on the relationship between topography and wind, it is often observed that areas at higher elevations experience greater wind speeds. Based on the boundary layer flow of wind over the Earth’s surface, it can be stated that wind speeds increase with elevation. This is due to aerodynamic drag introduced from surface obstructions and obstacles, which slow wind speeds closer to the surface. Based on the increased altitude of hills and mountains, these topographic formations reach into upper layers of the boundary flow, which are not previously obstructed by surface obstacles. Areas around mountains and large buildings may also experience the funneling of wind resulting in further increased wind speeds. Previously it was discussed how mountains and buildings can decrease wind speed; however, if funneling is occurring, then they can have the exact opposite effect [1]. Funneling of wind increases wind velocity by passing the air through a narrow corridor as it moves from an area of high pressure to low pressure. Consider sucking a liquid through two different straws, one of small diameter and one of larger diameter. If the goal is to drink 1 L of water with each of the straws in exactly 1 min, then the velocity with which the water enters your mouth with the smaller straw must be greater to drink the same volume in the same amount of time, and this is in essence the funnel effect. Wind, in moving from high to low pressure, passes through a narrow corridor at a greater velocity than if there were no corridor at all.

1.16.2.2

Sea and Elevation Breezes

Wind in coastal areas can also be influenced by an interesting reaction, which occurs between land and the adjacent ocean. During periods where the water is warmer than the land, warm air will rise above the water, and cool air will sink over land. This heating differential causes air to move over the land toward the sea. During periods where the land is warmer than the ocean this process is reversed causing air to move from the water toward land. This, along with the lack of obstructions, is often a major reason why coastal cites experience higher winds than inland regions. This phenomenon is particularly apparent in regions of Southern California and Mexico, where there is a drastic temperature gradient, which develops between the ocean and the inland deserts. The deserts heat up significantly during the day, creating a reliable wind source which, when coupled with the nearby mountains, creates powerful wind funnels ideal for wind turbine power generation [1]. Finally, wind can be caused by thermal gradients resulting from variations in altitude. Cooler air may follow the topography of a mountain or hill and make its way toward ground level. At the same time, warm air from ground level will rise to create a localized current. Depending on the region, this effect can be a significant source of air movement.

1.16.2.3

Seasonal Breezes – Monsoon

A monsoon can best be thought of as a seasonal shift in primary wind direction, blowing from one direction in the summer and an entirely different one in the winter. The cause of this phenomenon is not entirely dissimilar to that which causes sea breezes, but on a much larger scale. Monsoons are most commonly observed across Eastern and Southeastern Asia due to massive temperature gradients, which arise from seasonal shifts. During the winter months, the air over the continent becomes much colder than that over the Ocean. Meanwhile, a high-pressure system develops over Northern Asia creating a clockwise rotation of continental winds. This brings dry weather to Eastern and Southeastern Asia with winds blowing from land to sea. In the summer months the opposite occurs. The area over land becomes much warmer than that over the Ocean. This effect generates thermal lows over the continent, which create counter clockwise rotating continental winds. This movement brings moisture-laden winds from the ocean to land resulting in elevated precipitation levels during these months [5]. These effects in combination make monsoons primarily responsible for the “wet” and “dry” seasons experienced in these parts of the world.

1.16.2.4

Eddies

Eddies are small inconsistencies, usually observed as a swirling pattern within an airflow, which do not match the general movement of that airflow. Consider smoke billowing out of a chimney. On a windless day, the general flow of the warm air mass is to rise straight upward. However, within this airflow there also exists tinier chaotic circulation known as eddies. These eddies swirl within the larger flow pattern, raising and distributing particulate matter in an erratic fashion. Eddies are formed in one of two ways. The first, as in the smoke example, is by convection, where small discrepancies in temperature cause the air to swirl on a microscale. The second is through encountering obstructions, such as trees. As an airflow makes its way through a tree’s branches, it causes swirling much in the same way. As the air contacts the leaves, the flow is disrupted, and eddies are formed. As a result, leaves and branches within the tree can be observed to be rustling, moving in a direction that is not consistent with the general air movement. Due to their chaotic nature, eddies are usually only short lived, lasting from a split second to at most a couple of minutes [5]. Eddies may also occur on a much larger scale, such as that seen with buildings. Larger eddies may form on the downwind side of a building resulting in larger swirls, which could be as large as the contacted building itself. This phenomenon is most

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669

commonly observed in open sports stadiums. Wind flowing over the open roof of the stadium may create swirling conditions, which can create a playing environment entirely different to what would be experienced in an open field. In extreme cases, wind within the stadium may feel as though it is blowing in the complete opposite direction to the prevailing wind as a result of the generated eddies [5].

1.16.2.5

Scales of Motion

Scales of motion is a meteorological term used to describe the hierarchy of atmospheric circulations from the smallest eddies to the largest global wind currents. There are four scales of motion in which all air movements can be generally classified. The first, and smallest of these is the microscale. The microscale encompasses air movements in an area of less than 2 m. This scale is generally reserved for minor air disturbances, such as eddies, which result in disturbances in larger airflows. The next classification is the mesoscale, which tends to be reserved for small to medium, localized storms. Things, such as tornadoes and thunderstorms, likely fall into this category. The mesoscale can range from a few meters to around 100 km. The third largest classification of wind motions is the synoptic scale. The synoptic scale ranges from a few hundred to a few thousand kilometers. At the lower end of this scale is where major storms, such as hurricanes would fit. Common weather aspects, such as high and low pressure areas, which cover massive regions, are generally found toward the upper end of this scale. The final classification is the global scale. This scale is typically reserved for air movements in excess of 5000 km and is where movements, such as longwaves in the westerlies are found [5]. Ahrens et al. [5] show the scales of motion, their size, average lifespan, and where many common meteorological phenomena fit within the scales (Table 1).

1.16.2.6

Turbulence

1.16.2.6.1

Property

Wind turbulence generally refers to rapid fluctuations in wind velocity. One of two factors or a combination of both causes these fluctuations. The first comes as a result of the frictional force occurring between the moving air and the Earth’s surface. This is more generally thought of as the changes in wind speed and direction resulting from impediment from hills, mountains, forests, and buildings. The second major contributor is that of drastic thermal gradients, which cause air to move rapidly upward and downwards [1]. The property of turbulence is one, which is difficult to model given a baseline understanding of physical laws, such as the conservation of momentum, mass, and energy. While it must obey these laws, the determination of turbulence is based on a number of factors including temperature, air density, pressure, and humidity. Turbulence can also be drastically altered given only a slight change in any of these factors or even a slight topographic change. In this way, turbulence can be considered nearly chaotic and as such, any attempt to model turbulence would be best served as a statistical probability predictor rather than an absolute equation. The simplest model for turbulence is the turbulence intensity (TI) model, which is provided below: TI ¼

s vavg

ð1Þ

where TI is the turbulence intensity, measured as the overall level of turbulence, s is the standard deviation of the average wind speeds, and vavg is the average wind velocity. Both s and vavg are taken over a predefined time period in order to maintain all measurements consistent. While this formula does a reasonable job at modeling the intensity of turbulence, it does not satisfy as an accurate predictor of when a major wind gust might occur. As mentioned previously, the TI is largely controlled by thermal and topographical features. These factors are largely only a concern when it comes to near surface airflow. Once a certain altitude is reached, surface obstructions cease to influence the flow of air within the atmosphere. At these heights, wind flow is only governed by large-scale pressure differences and the rotation of the Earth along with the corresponding Coriolis effect. The airflow at this level in the atmosphere is known as geostrophic wind. This portion of the atmosphere is known as the boundary layer and is critical in the design and implementation of wind turbines [1].

Table 1

Scales of atmospheric motion with the phenomena’s average size and lifespan

Scale

Size

Duration

Phenomena

Global Synoptic Synoptic/meso Meso Micro/meso Micro

5000 km 2000 km 20–2000 km 20 km 2 m to 20 km 42 m

Days to a week or more Days to a week or more Days to a week or more Hours to days Minutes to hours Seconds to minutes

Longwaves in the westerlies High/low pressure areas and weather fronts Hurricanes and tropical storms Land/sea breeze, mountain/valley breeze, Chinook wind, and Santa Ana wind Thunderstorms, tornadoes, dust devils, and water spouts Small turbulent eddies

Source: Reproduced from Ahrens C. Essentials of meteorology today: an invitation to the atmosphere. Belmont, CA: Thomson Brook/Cole; 2005. 169 pp.

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1.16.2.6.2

Effect of turbulence on turbines

For a wind turbine to operate at maximum efficiency, it requires a consistent laminar flow of incoming wind. While this is generally accounted for during the design process, turbulence, regardless of the source, can have a major impact on turbine efficiency. In fact, it has been shown that a failure to account for incoming turbulence can result in an energy output loss in excess of 10% [6]. As a result, wind turbine installations are generally constructed in areas with very little in the way of surface obstructions, such as atop hills and mountains, large plains, or in large bodies of water. With that being said, it is not only the turbulence caused by surface obstructions, which must be considered, but also the turbulence generated in the wake of the turbine itself. As wind makes its way through the blades of the turbine, its laminar nature is disrupted, altering wind speed and wind direction, while also creating small vortices near the edges of the blades [7]. All of this in combination can have a great effect on downwind turbines if the effects are not properly accounted for. Understanding the effects of surface and wake induced turbulence is one of the greatest challenges in designing and placing turbines within a wind farm [7].

1.16.3 1.16.3.1

Physics of Wind Lift

Lift can best be described as the upward force on an object directly opposing the downward force of gravity. The lift force comes as a result of pressure differences between the top and bottom of an object, which cause the “lifting” of the object if in the proper proportions. The total lift force can be calculated using this pressure difference along with knowledge of the objects effective area perpendicular to the force of gravity. For streamline airflows, a variation of Bernoulli’s equation can be used to calculate the lift force. This equation is provided below:

Lift force ¼

1
r ðVb Þ2 2 a

 ½Vt Š2 A

ð2Þ

In this equation, ra represents the density of air, V is the velocity of air, the subscripts b and t refer to bottom and top of the object, respectively, and A represents the effective area of the object [8].

1.16.3.2

Drag

Drag can be described as a slowing effect, which occurs as a result of friction when air makes its way across a surface. The drag force serves to directly oppose the relative motion of any object making its way through the air. In the case of airplanes and wind turbines, overcoming the drag force is often the greatest challenge in optimizing performance. The drag force can be represented by the equation:

Drag force ¼ Cd



  1
ra V 2 A 2

ð3Þ

where Cd represents a drag coefficient usually determined experimentally on an individual case, ra is the density of air, V is the velocity of air, and A is the effective area of the object.

1.16.3.3

Lift-to-Drag Ratio

The lift-to-drag ratio is perhaps the most important consideration in designing airfoils, such as plane wings or wind turbine blades. In both cases, a higher lift-to-drag ratio is desired and as a results of computer modeling and wind tunnel testing, manufacturers are able to attain improved ratios. For instance, it has become common knowledge that adding a slight curvature to the front of a wing or blade drastically reduces the drag, while significantly increasing the lift. In addition to the shape of the airfoils, the attack angle is a second significant component of the lift-to-drag ratio. The attack angle is the angle at which the leading edge of the airfoil is set in relation to the flowing air. By increasing the attack angle, the lift is drastically increased; however, this strategy is only viable up to a certain point. In the case of planes, should the attack angle remain too steep, it can hinder the planes performance in other ways and therefore this strategy is only used during takeoff. In order to get a gage of the effect of the lift-to-drag ratio, one should consider a discus thrower. The distance of a discus throw is a function of three factors: the launch velocity, projection angle, and attack angle of the discus itself. One without knowledge of the lift and drag forces would likely assume that a launch angle of 45 degree and a similar attack angle would result in the furthest throw; however, this is not the case. Assuming a launch velocity of 21.3 m s 1 is held constant for a test across all launch and attack angle combinations, then it has been concluded that the maximum throw would occur at a launch angle of 35 degree and an attack angle of 25 degree. In addition to this conclusion, it is equally interesting to note that because of the lift force, a discus can be thrown much further into the wind than with the wind. This phenomenon has been tested and deemed valid for wind speeds up to 20 m s 1 [8].

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Laminar and Turbulent Flow

In general, wind flows in one of two distinct fashions, either laminar or turbulent. Laminar flow can be considered as the “smooth” flow, with parallel sheets forming to lie on top of one another to form streamlines. Turbulent flow can be thought of as just the opposite. In this case, the parallel streamlines observed in laminar flow tend to criss-cross with one another and create chaotic variations in wind speed and direction. In an obstruction free and frictionless scenario, wind, like any fluid, will always flow in a laminar nature; however, this all changes when these aspects come into the fray. Being that friction is an inevitability on Earth, there will always be some level of turbulence, which occurs. For those concerned with wing and turbine blade design, limiting this turbulence as much as possible is one of the main goals.

1.16.3.5

Wind Exergy and Thermodynamic Analyses

While exploitation of the wind resource is generally referred to in terms of energy, exergy represents an equally important branch of science and engineering when it comes to quantifying renewables. Exergy looks at the flow of matter or energy through a system and its maximum producible work as the system or flow comes into equilibrium with a reference environment [9–11]. Where exergy analysis shines is in its consideration of environmental factors, which conventional energy analysis would ignore. Many factors influence the wind resource, such as air pressure, temperature, and air composition [9]. An energy analysis would ignore these factors and deal primarily with wind speed, while an exergy analysis would take each of these factors into account in performing a location and environment specific analysis. Furthermore, unlike energy, exergy is not limited by the conservation laws (except in the case of reversible and ideal processes). Rather, exergy is exhausted as irreversible processes occur, until they reach equilibrium with their environment [9]. Energy efficiency (Z) versus exergy efficiency (c) is an important consideration when it comes to understanding and exploiting the wind resource. The two can be represented by the following simplified equation [10]: Z ¼Energy in products/total energy input c¼ Exergy in products/total exergy output What may not be immediately evident is that exergy efficiency actually gives a far greater indication of overall efficiency and performance than energy efficiency. This is a result of the exergy efficiency accounting for both irreversibilities in the system as well as external losses. By calculating these efficiencies, one can gain a better perspective of site characteristics and use it to make betterinformed decisions about renewable energy practicality. Efficiency maps can also be generated to gain further visual understanding of a specific site. Examples of such maps can be seen in the work of Sahin et al. [9]. In performing a thermodynamic analysis on the wind resource, it is essential to consider the exergy component. In looking purely at energy balance, the following equation can be derived for the flow of matter through a system [12]: X X X Qr W ¼ 0 ð4Þ ½h þ ke þ pe Šmout þ ½h þ ke þ pe Šmin r

out

in

where h is the specific enthalpy, ke is the specific kinetic energy, pe is the specific potential energy, min is the mass input across the inlet of the system, mout is the mass output across the outlet of the system, Qr is the heat transfer amount across the boundaries of the system, and W is the work transferred out of the system. Taking the reference environment as well as the energy flow into account results in the following exergy balance equation for the flow of matter through a system [12]: X X r X ein min eout mout þ EQ EW I ¼ 0 ð5Þ in

out

r

r

where ein is the specific energy at the inlet, eout is the specific energy at the outlet, EQ is the exergy associated with Qr (the heat transfer amount across the boundaries of the system), EW is the exergy associated with W (work transferred out of the system in all forms including shaft, electrical, etc.), and I is the destruction of exergy due to irreversibilities. From this point, the exergy of flow (Eflow) can be calculated by taking the physical and kinetic exergies (Eph and Eke, respectively) into account. This can be performed using the following equation [12]: Eflow ¼ Eph þ Eke

ð6Þ

Included in the physical exergy are the changes in entropy and enthalpy as they pertain to the operational turbine. In this way, it can be calculated using [12]:         Cp T0 Tavg T2 Pout Eph ¼ m Cp ðT2 T1 Þ þ T0 Cp ln ð7Þ R ln T0 T1 Pin where m is the mass flow rate in kg s 1, Cp is the specific heat for a constant pressure in kg kJ 1 K 1, T1 and T2 are the initial and outlet temperatures in K, respectively, T0 is the reference temperature in K, R is the gas constant in kJ kg 1 K 1, Pin and Pout are the inlet and outlet pressure conditions at their specific velocities (v1 and v2) in Pa and Tavg is the average temperature in K. The kinetic energy component of the flow exergy is made up of the removal kinetic energy through the turbine. It is important to note that this component is often expressed as work and therefore can be represented by [12]: Eke ¼ W

ð8Þ

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By incorporating an exergy analysis into the design and site selection process of a wind turbine or farm, there is the potential to drastically enhance the output and efficiency of an installation. While exergy analyses are not likely to be the only means of assessment, they certainly show great potential for supplementing energy analyses. A complete case study of such an exergy analysis can be attained from Redha et al. [12].

1.16.4 1.16.4.1

Measurement and Analysis of Wind Properties Considerations for a Wind Monitoring Program

Before undertaking any wind monitoring program, it is important to outline the goals of the study and to consider all the information, which will be required when making final conclusions. When it comes to wind energy installations, it is important to remember that not all sites are appropriate, therefore, understanding of a site’s characteristics is essential in determining whether or not to go ahead with the project. Following the handbook prepared by AWS Scientific [13] in partnership with the US Department of Energy and the National Renewable Energy Laboratory, the list below are considered essential components of a successful wind monitoring program:

• • • • • • • • •

Perform a comprehensive review of the wind resource assessment program. Determine infrastructure, monitoring, and labor costs. Siting considerations for monitoring equipment. Determine which parameters will be monitored. Selection of the most appropriate monitoring equipment. Installation of monitoring equipment. Station maintenance and operation considerations. Data collection and handling. Methods of processing, validating, and reporting data.

1.16.4.2

Measurement

Proper measurement and monitoring techniques are an essential component of any wind energy project. Before a project can be undertaken, aspects such as average and peak wind speeds, predominant wind direction as well as a number of ecological factors must be considered. On a larger scale, while meteorological monitoring sites can provide some of this information, it is still important to gain site-specific data [14].

1.16.4.3

Measurement of Wind Direction – Wind Vanes

The most basic device used to measure wind direction is that of the wind vane. While wind vanes are simple in their design, they still represent one of if not the best method for analyzing wind direction. Modern wind vanes are often used in combination with an anemometer in order to measure both direction and speed of the wind. Understanding the predominant wind direction at a site is essential when planning any wind energy installation. This knowledge will help in locating and orienting turbines to ensure the site achieves maximum efficiency. Fig. 1 shows a conventional wind vane, which uses a rod attached to a broad tail that rotates freely about a central axis. As the wind blows, it rotates the vane, which will always result in the tail of the vane being oriented toward the downwind side. To ensure

Fig. 1 Conventional wind vane.

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that the wind vane will react even in low winds, the pivoting axis utilizes ball bearings to reduce the frictional force on the device. Most wind vanes will respond in wind speeds as low as 1 m s 1 [2]. There are two main types of wind vanes used in modern research. While the working mechanism is largely the same, it is the method of signal production that is different. Wind vanes produce signals using either potentiometers or contact closures. While both designs work well, those that utilize potentiometers are more accurate but come at an increased cost. Selection of which to use will need to be done on a case-by-case basis based on the level of accuracy required.

1.16.4.4

Measurement of Wind Speed – Anemometers

In order to gain an understanding of the wind speed characteristics of a site, anemometers are employed. In an on-site setting, anemometers should be located atop of towers so that their height above the ground matches the hub height of the proposed turbine. For cases where there is not a proposed turbine, anemometers can be placed at specified intervals on the tower so as to gain knowledge of the sites wind speed profile. There are a number of different anemometer designs, which can be grouped into one of four categories: 1. 2. 3. 4.

rotational anemometers pressure anemometers thermoelectric anemometers phase shift anemometers

1.16.4.4.1

Cup anemometer

The cup anemometer (shown in Fig. 2) is the most widely used design in the measurement of wind speeds [15]. The cup anemometer is a rotational anemometer, which operates in combination with the physical force of drag. Cup anemometers have a vertical axis of rotation and generally utilize three or four conical of hemispherical cups to take advantage of the drag force. As the concave side of the cups experiences greater drag, the device will rotate accordingly. This process is discussed further in later sections. As the device rotates, the rate at which it does so can be monitored and correlated to wind speed. While cup anemometers do an excellent job at quickly and simply monitoring wind speeds, they do have some drawbacks. Firstly, while cup anemometers do speed up quickly to match wind speed increases, they do not slow down at a rate that always matches wind speed decreases. For this reason, they do not provide accurate readings in wind gusts as their momentum can continue to cause rotation after the gust has dissipated. In addition to this, as the drag force and air density are proportional to one another, changes in air density may cause some inconsistent readings with the cup anemometer. Despite these drawbacks, they are still a widely employed and accepted method for wind speed measurement [14].

1.16.4.4.2

Propeller anemometer

Propeller anemometers are generally comprised of four blades, which take advantage of the lift force to measure wind speed as well as the horizontal and vertical components of the wind (when three or more propeller anemometers are used in combination). When wind is experienced parallel to the axis of rotation, the blades experience a lift force, which causes them to rotate. This rotation can be correlated to wind speed. In addition to this, three propellers can be oriented on a mast so as to measure the horizontal and vertical components of the wind. Deviations in the direction of the wind follow the cosine law, which allows them to be properly accounted for [14]. Propeller anemometers are generally fitted with a tail vane to ensure that the device is properly

Fig. 2 Cup anemometer.

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oriented in relation to the wind direction. As such, the device doubles as an indicator of wind direction in addition to monitoring wind speeds [2].

1.16.4.4.3

Pressure plate anemometer

The first anemometers of any kind were pressure plate anemometers. Leon Batista Alberti first conceived the device around the year 1450. Later, Robert Hooke and Rojer Pickering (1664 and 1744, respectively) made sizeable contributions to the systems design [14]. Pressure plate anemometers are pressure type systems, which incorporate a weather vane along with a deflectable plate in order to quantify wind speed. The weather vane ensures that the device is always oriented parallel to the wind. As the oncoming wind contacts the plate, it is deflected to some degree. The degree to which the plate is deflected can be read off a gage and correlated to wind speed or more often done using a computer. These systems are somewhat more crude than other similar anemometers and as such, they struggle in conditions of low wind speed (where they are likely to read zero) as well as in gusty conditions.

1.16.4.4.4

Pressure tube anemometers

Pressure tube anemometers operate by measuring the pressure difference between two tubes. The pressure difference arises due to the orientation of the tubes, and this orientation can be observed in Fig. 3. As wind makes its way across and through the tubes, different pressures come about within the system. Within the horizontal tube, the wind creates pressure, whereas within the vertical tube it creates suction. The equations for each of the pressures can be observed below. 1 P1 ¼ PA þ C1 ra v2 2

ð9Þ

and 1 ð10Þ C2 ra v2 2 where P1 is the pressure in the tube parallel to wind flow, C1 and C2 are coefficients, ra is the density of air, and v is velocity. In combining the above listed equations and solving for v we get:   2½P1 P2 Š 0:5 ð11Þ V¼ ra ½C1 þ C2 Š P2 ¼ PA

In this way, the wind velocity can be calculated using the pressure difference between the two tubes and the specific coefficients detailed by the instrument. The major advantage of pressure tube anemometers is that there are no moving parts. This makes the likelihood of failure far less and reduces the need for maintenance. However, these systems are highly sensitive to a number of environmental factors, such as dust, moisture, and insects. All of this serves to deter from the field viability of the device [14].

1.16.4.4.5

Sonic anemometer

The speed at which sound travels in air sees small differences as wind speed changes. Sonic anemometers are able to sense this change and use it in order to determine wind speed. Sonic anemometers are comprised of three prongs oriented in a triangular shape each fitted with sound emitting transducers. Many designs incorporate two of these instruments mirrored one on top of the other. The time it takes for the ultrasonic acoustic signal to travel between the prongs can be used to determine wind speed. Consider the case where both the sound and the wind are moving in the same direction, then the speed of the sound waves (v1) can be calculated by: v1 ¼ vs þ v

ð12Þ

where vs is the speed of sound in still air and v is the wind speed. Much in the same way, if the sound is moving in a direction P2

P1 Fig. 3 Foundation for pressure tube anemometer. Reproduced from Mathew S. Wind energy: fundamentals, resource analysis and economics. Heidelbeg; Berlin: Springer; 2006.

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opposite the wind then the speed of sound in the wind can be calculated using: v2 ¼ vs

v

In combining the two equations together, wind speed can be calculated using: v1 v2 v¼ 2

ð13Þ

ð14Þ

Sonic anemometers offer one of the best solutions for monitoring wind speeds when a high level of precision is required. Sonic anemometers have no moving parts, which significantly reduce wear and tear and limits the maintenance requirement. Sonic anemometers offer highly accurate wind speed readings in the range of 0–65 m s 1. However, with this high level of accuracy comes at an equally high cost. As such, sonic anemometers are generally only employed when highly accurate readings are a necessity [14]. In addition to this, sonic anemometers can be used to measure turbulence with a relatively fine temporal resolution (20 Hz or better) [2,16].

1.16.4.4.6

Acoustic doppler sensors (sound detection and ranging)

SOund Detection And Ranging (SODAR) is a remote sensing system, which is currently employed in a number of meteorological measurements. SODAR operates on the principle of acoustic backscattering in which some of the sound emitted into the air from a transducer is reflected back to the ground and can be measured. Acoustic profiles are emitted at a slight angle to the vertical and as they travel upwards, they encounter particles and changes in the refractive index of the air. Changes in the refractive index of air can be caused by a number of factors including wind shear, temperature gradients, and humidity gradients. As the sound waves encounter these fluctuations, some of it is backscattered to the ground where microphones pick them up. Based on the received backscattered signal, frequency spectrum analysis can be used to estimate wind speeds [2]. SODAR has been used to estimate wind speeds in both onshore and offshore scenarios, creating vertical wind profiles ranging to 300 m above the sensor [17]. Despite this, SODAR for wind speed measurement is still in its infancy and a number of challenges and issues have arisen which must be considered. A study by de Noord et al. [18] summarized these issues, the most relevant of which are listed below:

• • • • • •

Further study is required on filtering techniques in SODAR, specifically when it is used for wind speed measurements. When it comes to wind energy, there are stricter requirements for uncertainty, reliability, and validity of wind speed measurements than many of the other SODAR applications. SODAR calibration has not been standardized and current processes need refinement. Wind speeds below 4 m s 1 and above 18 m s 1 have been shown to cause difficulties in accurate quantification using SODAR. This is particularly important as the cut out speed for most turbines is 25 m s 1 and understanding the wind profile up to this range is an essential step in the planning, construction and monitoring phases. SODAR technology must be reassessed for offshore applications as vibrations and a greater level of background noise has led to inaccuracies. SODAR emits a nearly vertical beam and measuring wind gusts would require a nearly horizontal beam. As such, it is not an accurate indicator of wind gusts.

Despite these issues, SODAR remains an extremely promising technology for wind speed quantification. Due to the relatively low infrastructural costs (no requirement for large towers) and monitoring requirements, SODAR seems to show a lot of potential for wind energy applications [2,18].

1.16.4.4.7

Laser doppler sensors (light detection and ranging)

LIght Detection And Ranging (LIDAR), similar to SODAR, is a remote monitoring system used to measure wind speeds in a threedimensional (3D) profile. The major difference between the two systems is that unlike SODAR, which emits sound waves, LIDAR emits a beam of light, which interacts with particles in the air and is backscattered toward the ground. The backscattered light can then be analyzed to determine the wind speed and distance from the particles that caused the scattering [2]. While LIDAR for meteorological and aerospace applications remains an expensive technology, there has been a number of developments in lower cost LIDAR systems for wind profile assessments. Furthermore, while initially there were some safety concerns surrounding LIDAR, these have been solved as the technology now widely utilizes the eye-safe wavelength of 1.5 mm in its emitters. Similar to SODAR, LIDAR has also been used in both onshore and offshore applications [19–21] to measure wind speeds at heights up to 200 m [2,21]. LIDAR devices are set at an angle of 30 degree to the vertical and rotate in a full circle, intersecting the wind at different angles as it does so. In doing this, it generates a wind speed profile in a disk shape for the scanned area. Generally, three full rotations are performed at each height of interest. These measurements can then be combined to create a full wind profile for a particular site [2].

1.16.4.5

Analysis of Wind Data

Analysis of wind data is one of the most crucial steps in the design of a wind energy system. While the instruments discussed in the previous section can help in gathering a large amount of useful data, ultimately it is up to the skill of the analyst to interpret the data. In doing so, there are a number of key aspects to consider, such as [2]:

676

• • • • • • • • • • •

Wind Energy

Average wind speeds over time. Variations in wind speed over set sampling intervals. Dominant wind direction (wind roses). Variations in wind direction over set sampling periods. Distribution of wind speed and direction. Wind speed persistence. Gust parameters. Statistical analyses – this includes: power spectral density, length and time scales, autocorrelation and time correlations with other local measurements. Steady versus fluctuating wind components. Fluctuations in the diurnal, seasonal, annual, interannual, and directional values of and of the listed parameters. Frequency of wind speeds between cut in and cut out speeds.

1.16.4.5.1

Wind rose

A wind rose is an efficient tool used to detail the wind profile (speed and direction) at a particular site. Wind roses are drafted by overlaying the data collected from anemometers and wind vanes into a 360-degree plot. A typical wind rose consists of equally spaced concentric circles as well as a series of 16 radial lines. The circles are used as a scale, which shows the percentage of wind moving in that direction away from the center reference. The 16 radial lines represent the 16 primary directions of the compass; and in addition to direction, they show the frequency of wind speed (for defined ranges) in that direction. An example of a wind rose, taken from Logan International Airport in Boston, MA, United States, can be observed in Fig. 4.

1.16.4.6

Global Wind Resource Availability

Perhaps the greatest drawback when it comes to wind energy is its highly location specific nature. As the name would imply, the technology only operates in the presence of wind. Therefore siting turbines to take best advantage of elevated average wind speeds will result in the most efficient system. To do this, engineers need to consider wind maps, which relay average, and peak wind speeds for the target area. In doing so, the best locations can be determined easily and in combination with factors, such as accessibility, environmental, social and economic considerations, so that a site can be selected. In looking at Fig. 5, it can easily be observed where the areas of greatest average wind speeds are globally. As can be expected, those areas located closer to shore as well as those areas of greater elevation generally observe higher average wind speeds. Coastal areas, such as Atlantic Canada, Southern Argentina, Greenland, Great Britain, Western Sahara, Somalia, Japan, and New Zealand, see drastically higher average wind speeds than those nearby inland areas. In the same way, major mountain regions, such as the Rockies, Andes, and Himalayas, also observe the same patterns of increased wind speeds. As is mentioned throughout this chapter,

Wind speed (m s−1) >11.05 8.49−11.05 5.40−8.49 3.30−5.40 1.80−3.30 0.51−1.80

2%

4%

6%

8%

10%

Fig. 4 A wind rose diagram example. Reproduced from West S. Wind Rose Plot, Station #14739 – Boston/Logan Int’l Arpt, MA; 1961.

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5 km Wind map Mean wind speed at 80 m

7

3

13

20 mph

6

9 m s−1

© 2015 Vaisala Inc.

Fig. 5 Global wind speed map showing average onshore wind speeds. Reproduced from Arent D, Sullivan P, Heimiller D, et al. Improved offshore wind resource assessment in global climate stabilization scenarios: Technical report NREL/TP-6A20-55049. Contract No. DE-AC3608GO28308; 2012.

these increases in wind speed and are directly related to the lack of significant surface obstructions present in the nearby environment. While Fig. 5 shows global average wind speeds, the same sort of wind maps can be produced for more localized areas when progressing toward turbine siting. By using a more strict scale, small differences may become apparent, which can lead to more efficient micrositing. In the same why that wind maps can be produced for onshore applications, they can also be produced for offshore. Fig. 6 shows a similar map, which has been produced based on offshore average wind speeds. This map is used in exactly the same way by engineers when selecting the best sites for offshore wind projects. As can quickly be seen, the general trend is that the further away from shore you go the greater the wind speeds become. Once again, this is due largely to the lack of surface obstructions but it does create an interesting challenge versus reward scenario for engineers. By siting turbines in deeper waters, the turbines will experience greater average wind speeds and therefore be able to convert more wind energy into electricity. With that being said, in doing so the project costs will be drastically increased as constructing deeper turbines in what are often much harsher environments can be a major challenge. Balancing the greatest efficiencies, with cost mitigation remains one of the most important tasks in siting wind turbines.

1.16.5

Wind to Electricity Energy Conversion

Wind to electricity conversion, as with any energy conversion process, is inherently reliant on the first law of thermodynamics, which states that energy can neither be created nor destroyed, and it can only change forms. In this way, wind turbines convert the energy inherent to wind into electricity using a turbine. Wind’s energy is what is known as kinetic energy and can be represented by the following equation: 1 2 mv ð15Þ 2 where, m is the mass and v is velocity [14]. To appropriate this better for wind, a few aspects of the equation must be altered. Firstly, mass of air is difficult to quantify directly; and for that reason, mass in the sense of wind can be thought of as density of air multiplied by the wind speed, the rotor area, and the time, which air is flowing through that area. In order to conceptualize this, consider wind blowing through an open window. Obviously, if the wind is blowing faster, then more wind (i.e., more mass) Kinetic energy ¼

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>1 4

12

−1 4

−1 2 10

8− 10

6− 8

4− 6

2− 4


10 5−10 3−5 1−3 22.1 MPa 374°C < T < 500°C Heterogenerous catalyst (supported metals)

Hydrogen-rich

Methane-rich

Fig. 8 Reaction conditions for different main products of supercritical water gasification (SCWG). Modified from Tushar MSHK, Dutta A, Xu C. Effects of reactor wall properties, operating conditions and challenges for SCWG of real wet biomass. In: Fang Z, Xu C, editors, Near-critical and supercritical water and their applications for biorefineries. Netherlands: Springer; 2014. p. 207–28.

Although hydrogen and methane may be obtained from the SCWG of biomass, their yields strongly depend on biomass feedstock and operation conditions (temperature, pressure, substrate concentration and catalyst, etc.), as shown in Fig. 8 [87]. It is well known that methane formation is exothermic whereas hydrogen formation is endothermic [88]. This entails as per the Le Chatelier’s principle, hydrogen yield increases and methane yield decreases when increasing the operation temperature, and viceversa. It was reported that when the temperature was between 374 and 5001C, methane was the major gas product, whereas beyond 5001C hydrogen became the dominant gaseous species [89]. Thus, temperature plays a vital role in determining the composition of the gas products, in accordance to the reactions thermodynamics [90]. A catalyst is usually needed for SCWG of biomass at a low temperature (o4001C) to enhance both methane formation and carbon gasification rates. Process parameters such as catalysts, operating conditions, reactor design feedstocks, etc. would directly influence the composition of the gas products, mainly consisting of hydrogen, carbon monoxide, carbon dioxide and a low concentration of C2 þ components [91]. Hydrothermal gasification temperature region may be divided into three zones based on the operating temperatures, i.e., subcritical (below 3741C), low temperature supercritical (374–5001C) and high temperature supercritical (500–8001C) operation [92]. The formation of methane is favored thermodynamically in low SCWG temperature zone [93]. However, it is imperative to have a catalyst present to achieve a higher methane yield along with higher carbon gasification efficiency [92]. Heterogeneous catalysts (supported metals) may enhance both methane and hydrogen formation whereas homogeneous catalysts mainly assist producing hydrogen [94–96]. For example, the presence of K2CO3 homogeneous catalyst catalyzes SCWG reactions in the following mechanism, leading to a higher yield of H2 and CO2 [97]. K2 CO3 þ H2 O-KHCO3 þ KOH

ð4Þ

KOH þ CO-HCOOK

ð5Þ

HCOOK þ H2 O-KHCO3 þ H2

ð6Þ

2KHCO3 -CO2 þ K2 CO3 þ H2 O

ð7Þ

In a recent work of Zhang et al. a total 17 heterogeneous catalysts, with combinations of four transition metals (Ni, Ru, Cu, and Co) and various promoters (e.g., Na, K, Mg, or Ru) supported on different materials (g-Al2O3, ZrO2, and activated carbon (AC)), were investigated with respect to their catalytic activity and stability for H2 production from glucose via SCWG [98]. The experiments were carried out at 6001C and 24 MPa in a bench-scale continuous-flow tubular reactor. Ni (in metallic form) and Ru (in both metallic and oxidized forms) supported on g-Al2O3 exhibited very high activity and H2 selectivity among all of the catalysts investigated for a time-on-stream of 5–10 h. With Ni20/g-Al2O3 (i.e., g-Al2O3 with 20 wt% Ni), a H2 yield of 38.4 mol/kg glucose was achieved and remained active for more than 10 h on stream, approximately 20 times higher than that obtained during the blank test without catalyst (1.8 mol/kg glucose), as illustrated in Fig. 9. As for the effects of catalyst support materials on activity, the following order of sequence was observed: g-Al2O34ZrO24AC. In addition, Mg and Ru were found to be effective promoters for the Ni/g-Al2O3 catalyst, suppressing coke and tar formation.

1.19.7

Anaerobic Digestion of Biomass for Biogas

Anaerobic digestion has been used as a mature technology for biogas production in municipal primary and secondary sludge for more than a century [99]. It is an efficient and sustainable technology for waste reduction and has the advantages of low sludge yield, net energy production, value-added fertilizer streams, and reduction of GHG emission, as compared to the aerobic treatment technology (which is an energy sink). In the past decades, anaerobic digestion technology has been successfully used for farm manure and industrial wastewater treatment [99,100]. More recently, anaerobic digestion has been expanded into treatment of various other lignocellulosic materials, ranging from agricultural and forest residues to food wastes and energy corps, for biogas production [101–104].

Biomass Energy

783

45

H2 yield (mol/kg glucose)

40 35 30

Ni20/y-Al2O3

25

Ni10/y-Al2O3

20

Ru10/y-Al2O3

15

Co10/y-Al2O3

10

Cu20/y-Al2O3

5 0 100

Blank 200

300

400

500

600

700

Time on stream (min) Fig. 9 Catalytic effects of different transition metals supported on g-Al2O3 on H2 yields from the supercritical water gasification (SCWG) of 50 g/L glucose (Reaction temperature: 6001C, pressure: 24 MPa, weight hourly space velocity (WHSV) ¼3 h 1). Reproduced from Zhang L, Champagne P, Xu C. Screening of supported transition metal catalysts for hydrogen production from glucose via catalytic supercritical water gasification. Int J Hydrogen Energy 2011;36:9591–601.

Several comprehensive literature review papers on anaerobic digestion of lignocellulosic materials, including agricultural, food processing and forest residues, for biogas production were published in the past 2–3 years [102–104]. The major challenge for anaerobic digestion of lignocellulosic biomass is the biodegradability of lignocellulosic materials, which are composed of cellulose, hemicellulose, and lignin. Pretreatment techniques and bio-augmentations have proved to be effective for enhancing biogas production from lignocellulosic materials [105–107]. Furthermore, the concept of solid-state anaerobic digestion of lignocellulosic materials for biogas production has received much attention in recent years, due to its advantages of handling high solids content feedstock (420% total solids) and low energy consumption [108,109]. Factors that affect and enhance the biodegradability of lignocellulosic materials for biogas production were systematically investigated in a number of individual studies [110]. The recent advance in anaerobic digestion of lignocellulosic biomass materials for biogas production is briefly overviewed below.

1.19.7.1

Fundamentals of Anaerobic Digestion

Anaerobic digestion is a process that converts organic wastes (wastewater and solids wastes) into biogas through a series of biological reactions. It is a complex biochemical process involving four steps (i.e., hydrolysis, fermentation/acidogenesis, acetogenesis, and methanogenesis) carried out by three different groups of microorganisms [99–101]. Due to the complicated metabolic pathway in anaerobic processes, the symbiotic relationship among all these microorganisms is vital to achieve process stability. In the first step, non-soluble organic wastes (i.e., suspended and colloidal biopolymers: proteins, polysaccharides, and lipids) are broken down into monomers (amino acids, sugars, and fatty acids) through hydrolysis. It is completed by the enzymes excreted by acidogenic bacteria. After the hydrolysis step, the acidogenesis uses the monomers as feed and converts into volatile fatty acids (VFA) and alcohols. Then, the acetogenesis group of bacteria further converts the VFAs and alcohols to acetate and hydrogen. Finally, the methanogenesis group uses acetate, hydrogen and carbon dioxide as feeds to produce bio-methane. Usually, the stages of hydrolysis and acidogenesis are more robust than acetogenesis and methanogenesis. The process stability of anaerobic digestion depends on a number of factors, such as temperature, pH, level of inhibitors, types of organic wastes, and operating conditions (HRT, SRT, etc.).

1.19.7.2

Anaerobic Digestion Systems and Applications

The successful application of anaerobic digestion technology for biogas production depends on the technical systems (i.e., bioreactors) used. Currently, there are six major types of bioreactor systems that are widely used: continuously stirred tank reactor (CSTR), up-flow anaerobic sludge blanket (UASB), expanded granular sludge bed (EGSB) reactor, internal circulation (IC) bioreactor, fluidized-bed reactor (FBR), and hybrid reactor. Basically, these bioreactors can be classified as “low-rate system” (CSTR or plug-flow) and “high-rate systems” (UASB, EGSB, IC, FBR attached biofilm system, and hybrid system) [99,100]. More recently, a new type of bioreactor system, anaerobic membrane bioreactor (AnMBR), has been developed and entered into the market [111]. The advantages and disadvantages of these anaerobic systems are summarized in Table 8. The anaerobic CSTR system is the basic anaerobic system for treatment of municipal sewage sludge and the organic fractions of municipal solids wastes. It has a detention time of approximately 25 days and can handle an organic loading rate (OLR) of approximately 1–4 kg chemical oxygen demand (COD)/m3/d [99,100]. The major challenge of the CSTR systems is the low

784

Table 8

Biomass Energy

Advantages and disadvantages of different anaerobic digestion systems

Anaerobic digestion systems

Advantages

Disadvantages

Low rate systems (CSTR, Plug flow bioreactors) High-rate systems (UASB, EGSB, IC, Fluidized bed, attached biofilm) AnMBR

Simple design and operation, less expensive

Low OLRs, large volume of bioreactors

De-coupling HRT from SRT, high biomass concentration, high OLRs Decoupling HRT from SRT, high biomass concentration, high OLRs, superior quality of effluent, elimination of biomass separation problems

Formation of granular sludge and biofilm, biomass separation problems (washout) Membrane fouling and replacement cost, high energy consumption

Abbreviations: AnMBR, anaerobic membrane bioreactor; CSTR, continuously stirred tank reactor; EGSB; expanded granular sludge bed; HRT, hydraulic retention time; IC, internal circulation; OLR, organic loading rate; SRT, solids retention time; UASB, up-flow anaerobic sludge blanket.

biomass concentration, long detention time (i.e., large reactor volume), and effective sludge retention or separation from liquid stream. In order to overcome the limitation of sludge retention and low OLR, considerable efforts were put to develop high-rate anaerobic treatment systems. The two major types of high-rate anaerobic systems that have been widely used in various industries are the UASB and EGSB systems [99,100]. The UASB systems were developed in the 1970s and saw extensive full-scale applications for high-strength industrial wastewater treatment and some extent of relatively low strength municipal wastewater treatment since the 1980s. The major advantages of the UASB systems are the effective sludge retention and thus effectively separation of hydraulic retention time (HRT) from solids retention time (SRT) and reduce the reactor volume significantly, and the high sludge concentration (20–50 kg sludge/m3) and OLRs (10–50 kg COD/m3/d) are achieved in the “high-rate” systems. The commercial AnMBR can handle an OLR of 10–15 kg COD/m3/d and produce superior quality of effluent with zero suspended solids for potential water reuse and system closure [111]. More recent studies indicated that the AnMBR can achieve high OLRs as well and compete with the high-rate anaerobic digestion systems [112]. Anaerobic digestion is a well-established technology for sustainable organic waste management for biogas production. It has been widely used for biogas production from municipal primary and secondary sludge, the organic fraction of MSW, farm manure, and industrial wastewater. The biogas produced contains approximately 55–75 vol% bio-methane and 25–45 vol% carbon dioxide, which can be used for heating, upgrading to the quality of natural gas and cogeneration of electricity and heat [99,100]. Energy consumption for anaerobic digestion is in the range of 0.05–0.1 kWh/m3 wastewater treated (or 0.18–0.36 MJ/m3 wastewater treated), depending on the need for pumping and recycling effluent, which is much lower as compared to the aerobic treatment systems (0.485–0.915 kWh/m3 wastewater treated) [100]. Anaerobic digestion has been considered as a net energy production technology (i.e., produce more energy than the energy consumed in the process) (net energy production of 4.3 MJ/kgCOD removed) [99,100]. The bio-methane potential of various biomass feedstocks varies. For example, the bio-methane potentials for different types of lignocellulosic materials range from 0.2 to 0.41 m3 methane/kg volatile solids removed [113]. For farm manure digestion, the biogas yield is in the range of 0.031–0.065 m3/kg manure treated. The biogas yield for MSW is 0.116–2.063 m3/kg dried solids [99]. AnMBR system as a novel technology has received much attention in anaerobic digestion of biomass for biogas production, due to its advantages of decoupled HRT from SRT, elimination of biomass separation problems, superior quality of effluent for potential system closure and water reuse. In 2008, there were 14 full-scale AnMBR plants operating in Japan, treating various types of wastes, including alcohol production stillage, municipal sludge, and a variety of residues from food processing (e.g., dairy, potato, confectionery, etc.) [111]. An example of full-scale application of anaerobic digestion of biomass for biogas production is the first installation and the largest scale AnMBR plant for food processing (production of salad dressings and barbeque sauces) wastewater treatment in the United States designed by ADI systems Inc. The full-scale AnMBR has a design capacity of handling 450 m3/d with an influent of 39 g COD/L, 18 g biological oxygen demand (BOD)/L, and 12 g total suspended solids/L. A 2-year operation of this AnMBR plant demonstrated that a consistent COD and BOD removal efficiency of 99.4% and 99.9%, respectively, were achieved with a high permeate quality of zero suspended solids and average COD and BOD concentrations of 210 mg/L and 20 mg/L, respectively. No membrane fouling was developed and the AnMBR operating expenses were reduced by 50% as compared to prior 12-month fiscal period of the sequencing batch reactors (SBR) plant before the installation of the AnMBR system. A high-rate AnMBR technology was developed by Gao et al. [112] for a petrochemical wastewater treatment for biogas production. By increasing the OLR step by step, a maximum OLR of approximately 32 kg COD/m3 d, as shown in Fig. 10, was successfully achieved, which indicates the high-rate AnMBR could compete with other conventional high-rate anaerobic systems, like UASB, and achieved better effluent quality for potential system closure [112]. Furthermore, a COD removal efficiency more than 99% was achieved and a good biogas yield with an excellent biogas quality was obtained [112].

1.19.8

Anaerobic Digestion of Biomass for Bio-Hydrogen

Hydrogen is a clean energy carrier due to its zero-emissions upon combustion. Hydrogen has a high energy density per unit mass (122 MJ/kg) and will play an important role in energy industry in this new century [114]. Among the various methods for

Biomass Energy

OLR (kg COD/m3/d )

35.0

2

30.0

4

3

785

5

1

25.0 20.0 15.0 10.0 5.0 0.0 0

40

80

120

160

200

(A)

COD (mg/L)

50,000

2

40,000

240 280 Time (d)

320

3

360

400

440

480

4

1

30,000

Permeate-HFSAnMBR

20,000

Influent

10,000 0 0

(B)

40

80

120

160

200

240 280 Time (d)

320

360

400

440

480

Fig. 10 (A) Organic loading rates (OLR) at different stages of operation and (B) influent and permeate chemical oxygen demand (COD) at different stages of operation. Reproduced from Gao WJ, Mahmoud I, Liao BQ, et al., A high-rate submerged anaerobic membrane bioreactor. Proc Water Environ Federation 2014;13:2048–56.

hydrogen production, the use of renewable biomass as feedstocks for hydrogen production through chemical and/or biological conversions has received much attention in recent years. Of particular interest is the biological conversion of biomass for hydrogen production. Biological hydrogen production is environmental friendly, relatively easy to operate, with mild operation conditions (ambient conditions), and has low energy consumption. More recently, a new approach for bio-hydrogen production (microbial electrolysis cells (MECs) has been developed [115]. In the past few years, a number of papers on microbial biomass conversion for bio-hydrogen production were published [114,115]. Various factors that could affect the bio-hydrogen yield and production rates, for example, type of inoculum, type of biomass feedstock, biomass pretreatment, temperature, pH, nutrients conditions, SRT, HRT, and OLR, were systematically investigated. Novel processes, including cell immobilization techniques, sequential dark and photo-fermentation techniques, and MECs processes, have been developed to enhance bio-hydrogen yield and its production rates [116,117]. The microbial bioconversion of biomass has shown great promise for bio-hydrogen production. However, there are still a number of bottlenecks that have to be overcome for commercial-scale application of microbial bioconversion of biomass for bio-hydrogen production [117–119]. This section overviews the recent progresses in microbial bioconversion of biomass for bio-hydrogen production. Fig. 11 shows the schematic representation of the diversity of H2 producing biocatalysts. A number of different microorganisms, including archaea, anaerobic and facultative aerobic bacteria, cyanobacteria, and lower green algae, can produce H2, as illustrated in Fig. 11 [117]. Heterotrophs are the major H2 producers in the fermentation processes. Both dark fermentation and photo-fermentation are used for H2 production. Dark fermentation does not require solar energy as an energy source and can tolerate O2 deficient conditions; while photo-fermentation needs light for H2 production [117]. These microorganisms can work singly or as a consortium for H2 production.

1.19.8.1

Fundamentals of Bio-Hydrogen Generation by Anaerobic Digestion

Bio-hydrogen production includes bio-photolysis, dark fermentation and photo-fermentation, as well as MECs. Bio-photolysis involves the use of autotrophic photosynthetic green algae and cyanobacteria to split water into hydrogen and oxygen under sunlight. The biological reactions include direct bio-photolysis (by green algae) and indirect bio-photolysis (by cyanobacteria). Dark fermentation and photo-fermentation involves heterotrophic bacteria for bio-hydrogen production from organic matters under anaerobic conditions in the absence and presence of light, respectively. Dark fermentation uses anaerobic non-photosynthetic fermentative bacteria and carbohydrate-rich substrates as sources of carbon and energy for bio-hydrogen production in the absence of light, while photo fermentation uses photosynthetic purple non-sulfur bacteria for bio-hydrogen production using organic acids in the presence of light. In dark fermentation, different groups of non-photosynthetic anaerobic bacteria, like Enterobacter, Bacillus, and Clostridium, are responsible for bio-hydrogen

786

Biomass Energy

Hydrogen producing microorganisms

Cyanobacteria

Prokaryotes

Eukaryotes

−

−

Dark fermentation Fermentative end products − Lactic acid

Temperature tolerance −

Bacteria − O2 tolerance −

Thermophiles

Butyric acid

Mesophiles

Butanol acetate

Psychrophiles

Algae

Photofermentation Purple −

Obligate anaerobes

Green −

Sulfur

Sulfur

Nonsulfur

Gliding

Facultative anaerobes Aerobes

Mixed acids

Fig. 11 Schematic representation of the diversity of H2 producing organisms. Reproduced from Chandrasekhar K, Lee Y-J, Lee D-W. Biohydrogen production: strategies to improve process efficiency through microbial routes. Int J Mol Sci 2015;16:8266–93.

production [117–119]. A representative biochemical reaction with glucose as feed and organic acid as end-product is shown below: C6 H12 O6 þ 2H2 O-2CH3 COOH þ 4H2 þ 2CO2

ð8Þ

The maximum hydrogen yield is 4 mol hydrogen/mole glucose consumed under this condition. The maximum hydrogen yield varies, depending on the type of organic matters used, fermentation pathways, and the end-products. In photo-fermentation, purple non-sulfur bacteria produces hydrogen from organic matters through bio-catalysis of nitrogenase under nitrogen-deficient conditions in the presence of light and reduced compounds (organic acids). A representative biochemical reaction with acetic acid as feed is shown below: light 2CH3 COOH þ 4H2 O-8H2 þ 4CO2

ð9Þ

Similar to dark fermentation, the maximum hydrogen yield is 4 mol hydrogen/mole acetic acid removed, and the maximum hydrogen yield depends on the types of reduced compounds (organic acids) used and fermentation pathways. Considering the limitations of dark fermentation and photo fermentation for hydrogen production, a new microbial approach, called MEC, has been developed to improve bio-hydrogen production [115]. The MEC process is an integrated device of microbial reactions for breaking down organic matters and electrochemical circuit for harvesting the energy and protons to produce hydrogen. The MEC process can achieve a high efficiency of hydrogen production that is not achievable with the conventional microbial hydrogen production (bio-photolysis, dark fermentation, and photo fermentation). In the MEC process, the microbes attached on the anode as biofilm break down organic matters such as acetic acid and glucose, producing electrons (e ) and protons (hydrogen ions, H þ ). The electrons produced in microbial reactions are transferred to an electrode (anode) and then travel through a circuit to the other electrode in the cathode compartment of the MEC. Here, with the help of the electrochemical cell, the protons produced in microbial reactions are combined with the electrons to produce hydrogen gas in the cathode compartment.

1.19.8.2

Bio-Hydrogen Production Systems and Applications

Although a number of lab-scale studies on bio-hydrogen production from various types of organic matters have been conducted, there is no full-scale commercial plant in operation yet in the world. There are several pilot-scale studies on bio-hydrogen production conducted in recent years. Table 9 provides a summary of pilot-scale studies on bio-hydrogen production. The pilotscale studies covered various technologies, different types of bioreactors, using various types of organic matters. The major type of bioreactor used was CSTR, although fluidized bed and trickle bed bioreactor were also used. The bio-hydrogen production processes include dark fermentation [20,116,120–122], two-stage hydrogen and methane fermentation [123,124], as well as MEC [125]. Biomass feedstocks used were both domestic and industrial wastewaters. In general, the COD removal efficiency is low in bio-hydrogen fermenters. The bio-hydrogen yield varied in different pilot-scale studies and was expressed in different units. Thus, the comparison of bio-hydrogen yield is difficult among these pilot-scale studies.

Biomass Energy

Table 9

787

Summary of pilot-scale studies on bio-hydrogen production

Type of bioreactor

Reactor configuration

Feed conditions

Operating conditions

Bio-hydrogen yield

COD, BOD removal

Ref.

CSTR (mixed microflora)

148 L fermentor,

Molasses wastewater,

OLR¼3.11–85.57 kg COD/m3 d T¼34–361C, pH¼4.5–5.1, VSS ¼6–8 g/L, HRT¼4–10 h T¼601C, HRT¼1.2 d, OLR¼89–138 kgCOD/m3 d

26.13 H2 mol/kg-COD

COD¼ 20%–35%

[116]

1.7–2.4 mol H2/mol Hexose

COD o30%

[123]

pH¼5.2–5.6, T ¼281C

2.76 mol H2/mol glucose

COD 60%, BOD 99%

[120]

T¼351C, OLR¼20–120 kg COD/m3 d, HRT¼4–12 h, pH¼6, VSS ¼2–6 g/L T¼601C, pH¼5.5, HRT¼15–20 h, OLR¼0.75–1.0 kg-lactose/m3 d T¼30–341C, v ¼0.5 m/d, pH¼6, OL¼ 6–50 g-COD/L OLR¼0.14 kg COD/m3 d, HRT¼1 d, T ¼13.5–221C

0.97–1.74 mol H2/mol sucrose

Effluent COD¼2–6 g/L

[20]

1.9 mol H2/mol hexose

–

[121]

0.32–9.67 L H2/h

78%–86%

[122]

0.015 L H2 /L.d

COD 34%

[125]

COD¼3000 mg/L

CSTR (mixed microflora)

200 L fermentor

CSTR (Co-culture)

100 m3 fermentor

CSTR (mixed microflora)

400 L fermentor, 400 L head space

Continuous combined fluidized and trickle bed Reactor (mixed microflora) Biofilm reactor

600 L fermentor

Microbial electrolysis cell (MEC)

Mixture of pulverized garbage and shredded paper wastes, dissolved COD¼45,400–70,700 mg/L, pH¼3.7–4.8 Sugarcane distillery effluent, COD¼101 g/L, BOD¼58.8 g/L, TSS¼8.3 g/L, pH¼4.1–4.5 Sucrose wastewater, COD¼20, 40 kg/m3

Whey wastewater,

10–15 g lactose/L 24 L working volume, 4.5 L head space 120 L

Food waste, 5.15 kg COD/L, BOD/ COD¼0.75, water content 15%–24% Domestic wastewater

Abbreviations: BOD, biological oxygen demand; COD, chemical oxygen demand; CSTR, continuously stirred tank reactor; HRT, hydraulic retention time; OLR, organic loading rate.

A number of lab-scale studies have demonstrated the advantages of bio-hydrogen production using various types of biomass feedstocks and different types of bioreactors. The bio-hydrogen yield and production rates by dark fermentation vary from 1.2 to 3.9 mol H2/mol glucose equivalent consumed [126] and from 8.2 to 121 mmol H2/L/h, respectively. Based on the promising results from lab-scale studies, a few pilot-scale studies have been conducted to verify the findings from the lab-scale studies and identify the potential problems in engineering design and operation of scale-up [124], as summarized in Table 9. The energy efficiency of bio-hydrogen production varies, depending on the types of feedstocks used and fermentation pathways. In the acetate pathway, maximum hydrogen yield is 4 mol H2/mol glucose consumed repenting only a small fraction of COD conversion (maximum COD removal efficiency of only 33%). Thus, two-stage fermentation (bio-hydrogen production followed by bio-methane production) has been proposed to increase energy efficiency and COD removal efficiency [20,123,126]. Tapia-Venegas et al. found out that the bio-hydrogen and bio-methane yield was 1.5 mol H2/mol hexose consumed and 27.56 mL CH4/g COD removed, respectively [124]. This corresponded to an increase of 12% in total energy efficiency, as compared to the single-stage of dark fermentation in bio-hydrogen production [20,124]. Ueno et al. also found out that the COD removal efficiency was increased from less than 30% in a bio-hydrogen fermentor to more than 75% in a two-stage bio-hydrogen/bio-methane production [123]. Furthermore, Lin et al. found out the ratio of energy output as bio-hydrogen to energy input (required energy to run the pilot-scale plant) was in the range of 13.65–28.68 [127]. Economic analysis of the two-phase bio-hydrogen/bio-methane production system from condensed molasses showed that the internal rate of return (IRR) was 32.24% and thus payback period was within 3.19 years and the commercialization potential was demonstrated [124]. Vatsala et al. also found that a net revenue gain of $37,070/year could be achieved in a 100 m3 scale of pilotplant for bio-hydrogen production from sugarcane distillery effluent treatment [120].

788

Biomass Energy

At present, there is no full-scale commercial plant of bio-hydrogen production from biomass, except for several pilot-scale tests of bio-hydrogen production.

1.19.9

Challenges of Biomass Energy

1.19.9.1

Challenges in Biomass Supply

A rapid growing demand of bioenergy, biofuels, and bio-products has intensified the worldwide interest and efforts in utilization of biomass resources. To date, most of biomass used to produce bioenergy and bio-products come from the by-products/residues of agricultural/forestry sectors. However, the continuously and rapidly increased interest in bioenergy and bio-products would lead to drastically increased demand that may surpass the supply of biomass. One solution to this is large-scale removal of biomass from the forest. However, from the forest management perspective, such approach could be challenging as increased removal of forest biomass (for example, through more intensive removal of biomass from harvested sites) might imbalance forest ecosystem, and impact the long-term sustainability of forests. Canadian Forest Service (CFS) researchers are undertaking research to determine how much biomass, by species of tree and by ecosystem type, can safely be removed from forests while still maintaining healthy ecological functions. The information gained from studies will help understand the limits to biomass harvesting, and determine the best approaches to harvesting biomass in a sustainable way. The other associated challenges are cost, variability/unpredictability and compatibility with existing infrastructure, social and other barriers. Therefore, although biomass is emerging to be a promising resource for bioenergy and bio-products production, the associated challenges need to be addressed for sustainable supply of biomass.

1.19.9.2 1.19.9.2.1

Challenges in Biomass Conversion Combustion and co-combustion

Although biomass combustion and co-firing technologies are ancient technologies or have been well developed and widely applied worldwide, it is still challenging for their application for large-scale power generation. For example, it is still difficult to increase the biomass co-firing ratio to over 20% [128], due to the inferior properties of biomass (e.g., higher moisture contents, low bulk densities, etc.). Direct co-combustion of biomass and coal are normally associated with some major technical challenges, including: (1) firing high-alkali herbaceous biomass fuels such as crop residues (containing potassium or sodium) would lead to increased slagging and fouling on boiler surfaces; (2) chlorine compounds in volatile ash would result in corrosion of heat transfer surfaces inside the boiler; (3) biomass materials are generally moist and strongly hydrophilic as well as non-friable, which would pose difficulties in fuel preparation, storage, and delivery; (4) depending on the quality of the biomass feedstock, co-firing might result in a reduced thermal efficiency and an increased emission (NOx). Clearly, the major challenges for direct co-combustion processes are related to fly ash behaviors (deposition, fouling and corrosion, etc.). Research is still undertaken to investigate chemistry and mechanisms of ash deposition during co-firing biomass and coal, and explore technologies for reducing ash deposition. Indirect co-firing technologies, i.e., to employ biomass gasification as pretreatment step to convert biomass into clean fuel gas followed by co-firing fuel gas with coal or other fossil fuels for heat/power generation, can be a promising technical solution to address the above challenges associated with direct combustion/co-combustion.

1.19.9.2.2

Gasification

Gasification technology is effective for conversion of carbonaceous fuels into combustible gas, which can be used for various applications including generation of heat, power or combined heat and power, or being further processed for synthesis of liquid fuel and other chemicals. The key technical issue is the development and application of cheap and efficient gas cleaning technologies. At the present, the gasification technology has been commercialized for heat or combined heat and power. For liquid fuel synthesis or production of other chemicals, large-scale plants are necessary; however, large-scale plants need a great quantity of biomass feedstock and may induce high costs for biomass collection, transportation, and storage. Co-gasification of biomass with coal or biomass with organic solid wastes should be further explored [27].

1.19.9.2.3

Pyrolysis

There are some challenges both in fundamental research and commercialization of biomass pyrolysis. Mettler et al. have identified ten fundamental research challenges, which can lay the foundations to better understand and optimize the biomass pyrolysis process with ultimate target of commercialization for production of liquid biofuels [129]. Examples of these challenges are to develop fundamental descriptions for condensed-phase pyrolysis chemistry (i.e., elementary reaction mechanisms), effect of feedstock flexibility, and accurate estimates for heat and mass transfer parameters through improved pyrolysis models. Commercialization challenges are mainly in improving economic returns, increasing target product yield and minimizing environmental impacts. These parameters are interlinked but each needs special consideration. The economic consideration is to maximize the value of products and minimize the costs for capital and operation. The target product yields need basic property data of the feedstock material, and good understanding of the pyrolysis process and the subsequent upgrading process. The major advantage of biomass pyrolysis is to achieve environmental benefits by using renewable feedstock; however, this advantage may be in doubt if pollutant streams are generated and not effectively abated through the process.

Biomass Energy 1.19.9.2.4

789

Hydrothermal liquefaction technology

The major challenges that hinder the industrialization and commercialization of HTL technology are: (1) expensive alloy requirement for the reactor; (2) feeding the biomass-water slurry feedstock into a high-pressure process, usually operating at 10–20 MPa; (3) dry matter content in the feedstock that can result in reactor clogging specially in the continuous mode; and (4) handling the aqueous waste stream generated from the process.

1.19.9.2.5

Supercritical water gasification technology

The major technical challenges for hydrogen and methane production through SCWG process are summarized below: 1. 2. 3. 4.

High pressure and temperature operating conditions; Suitable temperature for the production of either methane or hydrogen is yet to be established for various types of feedstock; Feedstock flexible catalyst is yet to be obtained; Reactor plugging is a major issue, which needs significant amount of research work on overcoming this issue.

1.19.9.2.6

Anaerobic digestion for biogas and bio-hydrogen

Anaerobic digestion is an established technology for converting low-value biomass feedstocks into various biofuels, including biogas and bio-hydrogen. The major challenge is to enhance the biodegradability of lignocellulosic materials. The application of anaerobic digestion of lignocellulosic materials for biogas production needs the development of novel pretreatment technologies, novel microbial community, and bioreactor systems to enhance the biodegradability of lignocellulosic biomass and reduce production cost of biogas. Anaerobic digestion of biomass for biogas has already played an important role in the renewable energy production. On the other hand, although fermentation of biomass for bio-hydrogen production is a promising technology, the major challenges in biological processes are the low hydrogen yield and production rates at a large-scale production. Novel biomass pretreatment techniques, microbial communities, and integrated processes are sought to enhance bio-hydrogen yield and production rate. In addition, engineering design and operating issues should be considered as well. For example, the mixing issues in the large-scale bioreactors, bio-hydrogen purification, and integration of bio-hydrogen production systems with hydrogen fuel cell systems should be considered and further investigated. More pilot-scale studies of bio-hydrogen production should be investigated to gain enough knowledge and experience to design and operate full-scale bio-hydrogen production plants.

1.19.10

Future Directions

Biomass currently represents approximately 14% of the world’s energy consumption. Biomass can be converted into bioenergy (heat/power), biofuels and bio-based chemicals and materials through various conversion technologies including combustion/cofiring with fossil fuels, gasification, pyrolysis, HTL, SCWG and biological conversions (anaerobic digestion for biogas and biohydrogen). Biomass resource is renewable, carbon neutral and abundant, so it has a great potential to become a primary energy source along with others for energy and chemicals production in the years to come. Forest biomass as given previously in Table 1, containing relatively high concentration of lignin – precursors of bio-phenols and bio-polyols, is being increasingly used for production of a wide range of high-value bio-products, for example, industrial chemicals, bio-based materials, textiles, pharmaceuticals, personal care products, etc., other than traditional forest products such as lumber and paper/pulp. For instance, Canadian researchers including some co-authors of this chapter have been endeavoring to develop cost-effective HTL and catalytic de-polymerization processes for generation of bio-oils from lignocellulosic biomass or lignin, applications of bio-oils as biophenols and bio-polyols in the synthesis of high-value bio-products (e.g., bio-based phenol formaldehyde (BPF) resins/foams, bio-based polyurethane (BPU) reins/foams and lignin-based epoxy resins) [130–132]. Table 10

Global market potential for the emerging bio-products

Bio-products

Compound annual growth rate, 2009–2015 (%)

Global market potential, 2015 (US$ billion)

Green chemicals Alcohols (ethanol) Bioplastic and plastic resins Platform chemicals (chemicals derived from biomass and used to make other chemicals, for example, 5-hydroxymethylfurfural (5-HMF)) Wood fiber composites Glass fiber composites Carbon fibers and composites

5.3 5.3 23.7 12.6

62.3 62.0 3.6 4.0

10.0 6.3a 9.5

35.0 8.4 18.6

a

Compound annual growth rate for 2010–2015. Source: Modified from Forest Bioeconomy, bioenergy and bioproducts. Available from http://www.nrcan.gc.ca/forests/industry/bioproducts/13315.

Biomass Energy

790

In fact, the growth potential and projected market size for emerging bio-products as bio-based chemicals and materials are much greater than those for traditional forest products combined (such as pulp, lumber, and newsprint). Table 10 displays seven bio-products and their approximate percentage of the compound annual growth rate for the period of 2009–2015, and their global market potential in 2015 in billions of US dollars, totaling approximately US$200 billion.

1.19.11

Concluding Remarks

In summary, biomass is an immense and environmentally friendly alternative to fossil resources for energy (or bioenergy), fuels (biofuels), and bioproducts (bio-based chemicals and materials). Increasing use of biomass resource could help ease society’s dependence on fossil fuels and, in the process, reduce net GHG emissions, and foster bio-economy. From this review chapter, the following concluding remarks are made: 1. Although biomass combustion and co-firing technologies are ancient technologies or have been well developed and widely applied worldwide, it is still challenging for their application for large-scale power generation due to many technical challenges associated with ash behaviors in combustion (deposition, fouling and corrosion, etc.), corrosive issues related to chlorine compounds in volatile, difficulties of biomass in fuel preparation, storage, and delivery. Indirect co-firing technologies, i.e., to employ biomass gasification as pretreatment step to convert biomass into clean fuel gas followed by co-firing fuel gas with coal or other fossil fuels for heat/power generation, can be a promising technical solution to address the above challenges associated with direct combustion/co-combustion. 2. Gasification technology is effective for conversion of carbonaceous fuels into combustible gas, which can be used for various applications including generation of heat, power or combined heat and power, or being further processed for synthesis of liquid fuel and other chemicals. The key technical issue is the development and application of cheap and efficient gas cleaning technologies. At the present, the gasification technology has been commercialized for heat or combined heat and power. For liquid fuel synthesis or production of other chemicals, large-scale plants are necessary; however, large-scale plants need a great quantity of biomass feedstock and may induce high costs for biomass collection, transportation and storage. Co-gasification of biomass with coal or biomass with organic solid wastes should be further explored. 3. Biomass pyrolysis as a simple conversion technology has been used at commercial scale for production of bio-oil, which is used for combustion in boilers and heavy engine. The most promising applications of the technology fall into two categories: (a) for production of liquid fuel and chemicals using woody biomass to maximize economic returns; and (b) for using low value or negative value feedstocks such as forest residues, agricultural residues, and organic solid wastes to minimize the operational costs. 4. Bio-crude oils are typical biofuels from biomass thermochemical conversion and have been considered as the promising alternatives to petroleum fuels for power or heat generation. Bio-oils can be produced by two main routes: pyrolysis or HTL. In HTL process, water is used as solvent mostly at subcritical conditions eliminating the need for drying the feedstock, which is otherwise required for other thermochemical processes and making HTL a promising method for conversion of high-water content feedstocks. 5. Compared to conventional gasification process, SCWG of biomass (at 43741C and 422.1 MPa) produces high purity of hydrogen and methane. Such high pressure and temperature are major challenges for up-scaling of the SCWG for production of renewable hydrogen and methane. 6. Although fundamentals and technical systems for anaerobic digestion have been well established, the major challenges in the biological processes for biogas and bio-hydrogen production are the low product yield and production rates at a large-scale.

Acknowledgments The authors would like to acknowledge the funding from BioFuelNet Canada, a Network of Centers of Excellence and from NSERC through the Discovery Grants, as well as the financial support from NSERC/FPInnovations Industrial Research Chair Program in Forest Biorefinery and the Ontario Research Fund-Research Excellence (ORF-RE) from Ministry of Economic Development and Innovation.

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Further Reading Basu P. Biomass gasification, pyrolysis and torrefaction: practical design and theory. Cambridge: Academic Press; 2013. Dahiya A. Bioenergy: biomass to biofuels. Cambridge: Academic Press; 2014. Li Y, Kumar Khanal S. Bioenergy: principles and applications. Hoboken, NJ: Wiley-Blackwell; 2016. Rehman Hakeem K, Jawaid M, Rahid U. Biomass and bioenergy applications. Switzerland: Springer; 2014. Seabrook H. Biomass: sustainable energy resource. New York, NY: Syrawood Publishing House; 2016. Weyland T. Bioenergy: sustainable prespectives. Forest Hills, NY: Callisto Reference; 2016. Weyland T. Bioenergy: processes and technologies. Forest Hills, NY: Callisto Reference; 2016.

Relevant Websites https://www.bio-amber.com/bioamber/en/company BioAmber. http://biofuelnet.ca/ BioFuelNet Canada. www.biomassinnovation.ca Biomass Innovation Center. http://www.bluemarblebio.com/ Blue Marble Biomaterials. https://www.canadianbiomassmagazine.ca/ Canadian Biomass. http://enerkem.com/ Enerkem. http://www.ensyn.com/ Ensyn. http://globalgreensolutionsllc.com/ Global Green Solutions.

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http://gbcorp.biz/ Green Biofuels. http://greencorenfc.com/technology.htm Greencore. http://www.greenfield.com/ Greenfield Global. http://energy.techno-science.ca/en/energy101/biomass.php Let’s Talk Energy. https://www.nrcan.gc.ca/forests/industry/bioproducts/13323 Natural Resources Canada. http://petrosun.us/ Petrosun. http://www.sapphireenergy.com/ Sapphire Energy. https://www.studentenergy.org/topics/biomass?gclid=CJepxJWYhdUCFY-MaQodY-IERQ Student Energy. http://www.suncor.com/about-us/biofuels Suncor. http://www.woodlandbiofuels.com/ Woodland Biofuels Inc.

1.20 Nuclear Energy Sümer S¸ahin and Hacı Mehmet S¸ahin, Bahçes¸ehir University, Faculty of Engineering and Natural Sciences, Department of Energy Systems Engineering, Istanbul, Turkey r 2018 Elsevier Inc. All rights reserved.

1.20.1 Fundamentals 1.20.2 Nuclear Fission 1.20.3 Nuclear Materials 1.20.3.1 Fission Reactors Fuels 1.20.3.2 Fission Fuels Assemblies 1.20.3.2.1 Molten salt fuels 1.20.3.2.2 Tristructural-isotropic type fuel 1.20.3.3 Fusion Reactors Fuels 1.20.3.3.1 Fusion reaction physics 1.20.4 Nuclear Power Reactor Types 1.20.4.1 Pressurized Water Reactors 1.20.4.2 Boiling Water Reactors 1.20.4.3 CANada Deuterium-Uranium Reactors 1.20.4.4 Light Water Graphite Reactor (Reactor Bolshoy Moshchnosty Kanalny and EGP) 1.20.4.5 Advanced Gas-Cooled Reactor 1.20.4.6 Sodium-Cooled Fast Breeders 1.20.4.7 Naval Nuclear Reactors 1.20.4.8 Generation-IV Reactors 1.20.4.8.1 Lead-cooled fast reactors 1.20.4.8.2 Gas-cooled fast reactors 1.20.4.8.3 Molten salt-cooled fast reactors 1.20.4.8.4 Gas turbine modular helium reactor 1.20.4.8.5 Pebble bed modular reactor 1.20.4.8.6 Very high temperature reactor 1.20.4.8.7 Fixed bed nuclear reactor 1.20.4.9 Space Nuclear Reactors 1.20.4.9.1 Thermoelectric reactors 1.20.4.9.2 Thermionic reactors 1.20.5 Environmental Aspects and Radiation Safety 1.20.5.1 Nuclear Radiation Release of Coal Power Plants 1.20.6 Process Heat and Nuclear Hydrogen Production 1.20.7 Sustainability of Nuclear Energy 1.20.7.1 Sustainability of Fission Energy 1.20.7.2 Sustainability of Fusion Energy 1.20.7.3 Sustainability of Fission Energy via Fusion 1.20.8 Future Prospects of Nuclear Energy 1.20.9 Conclusions References Further Reading Reports Relevant Websites

1.20.1

795 798 800 800 802 802 803 805 805 809 809 810 810 812 813 813 814 815 816 816 816 816 817 817 818 818 819 820 821 825 826 830 830 836 838 843 846 846 848 848 849

Fundamentals

Atoms are the basic stone of the matter. Fig. 1 shows the basic components of an atom including the nucleus in the center and the electrons in the orbits, adopted from Refs. [1,2]. The atomic nucleus consists of N neutrons and Z protons, where A¼ N þ Z denotes the total number of nucleons. The sum of the total mass of Z free protons, mp, and the mass of (A–Z) free neutrons, mn, are greater than the mass of the atomic nucleus, MA. This mass difference is called mass defect, DM, and is converted to the atomic binding energy, BE, keeping the nucleus in stable state. DM ¼ Z  mp þ ðA

Comprehensive Energy Systems, Volume 1

Z Þ  mn

doi:10.1016/B978-0-12-809597-3.00122-X

MA

ð1Þ

795

796

Nuclear Energy

10–13 cm Electrons

Protons Nucleus

Neutrons

10–8 cm Fig. 1 The basic components of an atom with nucleus. Reproduced from S¸ahin HM. Lecture notes in nuclear engineering. Ankara: Gazi University; 2011; S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011.

BE ¼ DM  c2 It is convenient to introduce a new mass unit for atomic dimensions, called atomic mass unit “amu.” It is defined as 1/12 of the mass of the neutral 12C6 atom.
 M 12 C ¼

12 ¼ 1:99268  10 6:022137  1023

23

g

ð2Þ

Another unit of energy that is often used in nuclear engineering is the electron volt, denoted by eV. This is defined as the increase in the kinetic energy of an electron when it falls through an electrical potential of 1 V. This is equal to the charge of the electron multiplied by the potential drop-that is, 1 eV ¼1.60219  10 19 C  1 V ¼1.60219  10 19 J. Other energy units frequently encountered are MeV (106 eV) and keV (103 eV). Any nuclear reaction occurring in the atomic nuclei and accompanied with a reduction of the total mass of all reaction products results in the conversion of mass difference to energy through the famous Einstein relation E ¼mc2. Example 1: Calculate the rest-mass energy of an electron in MeV. Solution 1: From Einstein’s relation, the rest-mass energy of an electron is E ¼ me c2 2 E ¼ 9:1095  10228 ð2:9979  1010 Þ 7 E ¼ 8:1871  10 ergs ¼ 8:1871  10214 J Expressed in MeV, this is 8.1871  10

14

J/1.6022  10

13

J/MeV ¼ 0.5110 MeV.

Example 2: Compute the energy equivalent of an atomic mass unit. Solution 2: This can easily be computed using the result of the previous example. Thus, since according to Eq. (2), 1 amu¼ 1.99268  10 23 g/12 ¼ 1.6606  10 24 g, it follows that 1 amu is equivalent to (1.6606  10 24 g/amu/9.1095  10 28 g/electron)  0.5110 MeV/electron ¼ 931.5 MeV. In a nucleus, the lost mass, called as mass defect, is converted to energy according to the famous Einstein’s relation, E¼ Dmc2, constituting the BE of the atom and keeping the nucleons together and the atom stable. BE varies from atom to atom. Fig. 2 shows the BE per nucleon of the isotopes as a function of the atomic mass number. Iron group isotopes are the most tightly bound. Higher BE is the indicator of lower mass per nucleon and vice-versa. One can distinguish four categories of nuclear energy production:

• • • •

nuclear fission (currently widely used for electricity production) nuclear fusion (future indefinitely energy candidate) radioactive decay (special applications: remote systems energy supply for satellites, etc. medical, agricultural, industrial applications, etc.) annihilation process: electron (b ) þ Positron (b þ )-g (electromagnetic energy emission)

By splitting a heavy isotope with the atomic weight A greater than 200 to two medium weight isotopes, the BE per nucleon in the daughter isotopes will be greater than that in the mother isotope. A fraction of the nuclide’s mass will be converted to energy by E¼ Dmc2, which will be released as fission energy. Elements heavier than iron are expected to yield nuclear fission energy. However, fission energy is released in practice only by elements heavier than actinium (ZAc ¼89), called actinides. For a heavy nucleus with an atomic mass of A¼approx. 240 and an average BE difference of approx. 0.8 MeV/nucleon, fission energy yield will be approx. 200 MeV.

Binding energy per nucleon (MeV/nucleon)

Nuclear Energy

797

10

8

16 8O 4 2He

19 9F 12 6C

6

56 Fe 26

31 15P

75 33As 153 63Eu

90 40Zr

39 19K

120 50Sn

209 83Bi

238 92U

14 7N

6 3Li

4 3 1H

2 2 1H

0 0

50

100

150

200

250

Nucleon number A Fig. 2 Atomic binding energy per nucleon. Reproduced from Sitton L. Chapter 31.3. The mass defect of the nucleus and nuclear binding energy. Available from: http://staff.orecity.k12.or.us/les.sitton/Nuclear/313.htm.

The BE per nucleon of ultralight atoms is very low. Hence, by the fusion of two light nuclides to a heavier one, a greater fraction of the nucleon mass will be converted to energy constituting the fusion energy. Highest energy release per nucleon occurs by the fusion of two heavy hydrogen atoms as the kinetic energy of the reaction produces an a-particle and a high energetic neutron. 2

H1 ðDÞ þ 3 H1 ðT Þ-4 He2 ða

3:5 MeVÞ þ 1 n0 ð14:1 MeV Þ þ 17:6 MeV

Example 3: Calculate the binding energy (BE) of the last neutron in

13

13

ð3Þ

C.

12

Solution 3: If the neutron is removed from C, the residual nucleus is C. M (12C) ¼ 12.00000 amu, Mn ¼ 1.00866 amu, and M (13C) ¼ 13.00335 amu. The BE or separation energy is then computed from Eq. (1) as follows: in energy MeV, equal to Es. In symbols, this is Es ¼ [Mn þ M (A–lZ) M (AZ)]  931 MeV/amu

 Es ¼ Mn þ M 12 C 2M 12 C ¼ 0:00531 amu  931 MeV ¼ 4:95 MeV For the stability of atoms, neutron and proton numbers must be kept in balance. Fig. 3 shows the neutron and proton numbers of stable nuclei, with increasing n/p ratio for heavier atoms in order to compensate the Colombian repulsion forces by increasing proton numbers [3]. In heavy nuclei with A4200, n/p ratio approaches to 1.6. In case of excessive neutrons outside the stability region, one neutron in the nucleus will be converted to proton by the emission of a negatively charged electron and an antineutrino, v e , which increases the proton number, and decreases the neutron number by one. Electrons emitted from the atomic nucleus are called b particles. n-pþ b þ v

e

ð4Þ

The reaction (5) is always observed by the fission process, where the neutron/proton ratio of the lighter fission fragments is lower than the fissionable heavy mother isotope, as well as by most of the neutron capture processes. The mass of a free neutron is higher than that of a free proton. Hence, a free neutron is always radioactive with a half-life time of approx. 10 min. It disintegrates according to Eq. (5), whereas a free proton is always stable. By excessive proton numbers, one of the protons in the nucleus will be converted to a neutron by the emission of positron, viz., a positive electron and a neutrino, increasing the neutron number, and decreasing the proton number by one. p-nþþ b þ v

ð5Þ

The reaction (6) can be observed by the artificial isotope production in accelerators, viz., cyclotron for medical applications, such as positron tomography. The conversion of the nucleons according to the reactions (3) and (4) continues until the nuclide becomes a stable isotope. Neutrons make divers reactions with materials. The most important neutronic reactions for nuclear energy productions can be cited as: Elastic and inelastic scattering (n,n) and (n,n0 ), neutron multiplication (n,2n), (n,3n), neutron capture accompanied with a g-ray emission (n,g), proton production (n,p), helium production (n,a), nuclear fission (n,f), etc. The neutron will be lost after the (n,p), (n,a), and (n,f) reactions. Hence, the sum of these reactions results with neutron absorption. The probability of a particular reaction is described in term of quantities known as cross-sections, where s denotes the microscopic cross-section for one single nucleus for a particular nuclear reaction. The unit of s is barn (b), where 1 b ¼10 24 cm2. The atomic density, viz., the number of

798

Nuclear Energy

120

184

74 W n = p 1.49

110 100 90

Neutrons

80 70 60

107 47 Ag

50

n p = 1.28

40

56 Fe 26 n p = 1.15

30 20 10

20 Ne n 10 p =2

0

10

20

30

40 50 Protons

60

70

80

Fig. 3 Neutron and proton numbers of stable nuclei. Reproduced from Bodner Reasearch Web. Available from: http://chemed.chem.purdue.edu/ genchem/topicreview/bp/ch23/modes.php.

atoms per cm3 is calculated as: N¼

r  A with A ¼ 6:022137  1023 ðAvogadro number Þ M

ð6Þ

Example 4: Calculate the atomic number density for all isotopes in natural uranium oxide, UO2, with a specific mass of r¼ 10.5 g/cm3: Solution 4: N UO2 ¼


 10:5  6:022137  1023 ¼ 2:34212  1022 number of UO2 molecules per cm3 235  0:007 þ 238  0:993 þ 2  16

Number of O atoms per cm3: 2  2.34212  1022 ¼4.68425  1022 Number of U atoms per cm3: 2.34212  1022 Number of 235U atoms per cm3: 0.0072  2.34212  1022 ¼1.6863  1020 Number of 238U atoms per cm3: 0.9928  2.34212  1022 ¼2.32526
1022 The macroscopic cross-section (S) ¼ s  N for a particular nuclear reaction of a material is calculated by the sum of the microscopic cross-sections of all atomic isotopes in 1 cm3. Hence the unit of (S) is 1/cm¼ cm 1, which physically means cm2/cm3. Suppose a uniform beam of F neutrons/cm2 impinges on a thin target and area of 1 cm2. If there are n neutrons/cm3 and v is the speed of neutrons, then the quantity F¼ n  v is called the neutron intensity or neutron flux per cm2
s. The reaction rate (RR) is given by X  RR ¼ n  v  s  N ¼ F  1=ðcm3  sÞ ð7Þ Similarly, the fission and absorption RRs are F  (S)f and F  (S)a, respectively. Absorption cross-section comprises all nuclear reactions, where a neutron will be lost, viz., (S)a ¼ (S)g þ (S)f þ (S)a, (S)p, (S)d, etc. Neutron flux, F, is a scalar quantity and denotes neutrons of all directions passing through the matter per cm2 and second, whereas neutron current, J, is a vector quantity passing through a surface per cm2 s.

1.20.2

Nuclear Fission

Nuclear fission reaction occurs when a neutron hits a target nuclear fuel, where the heavy target nucleus splits it in two medium weight nuclei, called fission fragments, accompanied by the emanation of multiple fast energy neutrons, prompt g- and prompt b -rays simultaneously [4,5]. The energy of fission neutrons ranges preeminently from 0.1 to 10 MeV with an average of approx.

Nuclear Energy Energy partition for the fission of

Table 1

799

235

U

Particle type

Emitted energy (MeV)

Recoverable energy (MeV)

Fission fragments Fission product decay b -Rays g-Rays Neutrinos Prompt g-rays Fission neutrons g-Rays from neutron captures Total fission energy

168

168

8 7 12 7 5 – 207

8 7 – 7 5 3–12 198–207

Source: Reproduced from Lamarsh JR, Baratta AJ. Introduction to nuclear engineering. 3rd ed. Upper Saddle River, NJ: Prentice Hall; 2001.

Table 2

Delayed neutron data for thermal fission in

235

U

Group

Half-life (s)

Decay constant (s 1)

Energy (keV)

Neutrons per fission

Fraction (bi)

1 2 3 4 5 6 Total

55.72 22.72 6.22 2.30 0.610 0.230

0.0124 0.0305 0.111 0.301 1.14 3.01

250 560 405 450 – –

0.00052 0.00346 0.0031 0.00624 0.00182 0.00066 0.0158

0.000215 0.001424 0.001274 0.002568 0.000748 0.000273 0.0065 (btotal) 0.0027 (b for 233U)

Source: Reproduced from Lamarsh JR, Baratta AJ. Introduction to nuclear engineering. 3rd ed. Upper Saddle River, NJ: Prentice Hall; 2001.

2 MeV. In minor quantities, the tail can reach down to thermal energies. The majority of neutrons are emitted promptly (499%). Table 1 shows the partition of the fission energy between the reaction products [4]. Fission fragments are medium weight atoms with atomic weights ranging from A ¼ around 80 up to 150. The medium weight atoms (A¼ approx. 80 to B150) have smaller n/p ratio than the original heavy fissile nuclide (A¼233 to 250 or more). Hence, the fission fragments are highly radioactive. Excess neutrons will be rapidly converted to protons by successive b emissions to reach stable state. The most important fission reaction products are Cesium (Cs), Iodine (I), Krypton (Kr), Molybdenum (Mo), Promethium (Pm), Samarium (Sm), Strontium (Sr), Technetium (Tc), and Xenon (Xe). A small fraction (o1%) of fission neutrons are produced by the radioactive decay in the b decay of certain fission products. As an example, 87Br emits b with a half-life of 55.7 s, and decays to 87Kr. The latter is evidently formed in a highly exited state, with sufficient energy to permit it immediately to eject a neutron and leave a stable 87Kr. Another delayed neutron precursor is 137I with a half-life of 22.7 s. Table 2 shows delayed neutron data for thermal fission in 235U [4]. Delayed neutrons make the reactor control possible. Example 5: A certain research reactor has a flux of 1  1013 neutrons/cm2 s and a volume of 64,000 cm3. If the fission crosssection, (S)f, in the reactor is 0.1 cm 1, what is the power of the reactor? Solution 5: The power may be obtained from the fission rate using the relationship between the energy released per fission (200 MeV) and the rate at which fissions are occurring: 1 MW 1 W s 1:60  10 13 J 200 MeV    fission rate  J MeV fission 106 W MW s ¼ 3:2  10217  fission rate fission

Power ¼

From Eq. (7), the fission rate or RR is RR ¼

P

fF

¼ 0:1 cm ¼ 1012

1

 1013 

fission cm3 s

neutrons cm2 s

800

Nuclear Energy

The reactor power/cm3 is then MW s fission 1012 fission cm3 s MW s ¼ 3:2  1025 cm3

Power=cm3 ¼ 3:2  10217

The total power is the power/cm3 times the volume of the active core. Power ¼ 3:2  10 ¼ 2 MW

5

MW s  64; 000 cm3 cm3

Consider a reactor in which the energy from the fission 235U is released at the rate of P megawatts (MW). In other words, the reactor is operating at a thermal power of P MW. With a recoverable energy per fission of 200 MeV, the rate at which fissions occur per second in the entire reactor is Fission rate ¼ P MW 

106 J fission MeV 86; 400 s   ¼ 2:70  1021 P fissions=day  MW s 200 MeV 1:60 13 J day

In order to convert this to grams per day fissioned, which is also called the burnup rate, it is merely necessary to divide by Avogadro’s number and multiply by 235.0, the gram atomic weight of 235U. This gives simply, Burnup rate ¼ 1:05 P g=day Thus, if the reactor is operating at a power of 1 MW, the 235U undergoes fission at the rate of approximately 1 g/day. To put another way, the release of 1 MW/day of energy requires the fission of 1 g of 235U. Example 6: Calculate the energy released by the fissioning of 1 g of 235U and the equivalent mass by the combustion of the fossil fuels coal and oil: 1. coal with a heat content of 3  107 J/kg and 2. oil at 4.3  107 J/kg? Solution 6: According to the prior discussion, the fissioning of 1 g of 235U releases approximately 1 MW/day ¼ 24,000 kWh ¼ 8.64  1010 J. 10 J This energy is also released by 8:6410 ¼ 2:88  103 metric tons of coal. 3107 kg 8:641010 J In terms of oil this is also 4:3107 kg ¼ 2.00  103 kg ¼ 2.00 t ¼ 12.6 barrels of oil.

1.20.3 1.20.3.1

Nuclear Materials Fission Reactors Fuels

The most important constituent of a nuclear reactor is the fuel. Uranium is the basic natural nuclear fuel. Natural uranium contains two main isotopes, namely 235U (0.72%), 238U (99.28%), and traces of 234U. Only the odd 235U isotope is a fissile fuel. Natural uranium can be used only in heavy water moderated-cooled reactors or in graphite moderated gas-cooled reactors due to the very low 235U content. Hence, uranium must be enriched in 235U for wider utilization in light water reactors (LWRs) or fast breeders (FBs). The odd uranium isotope 238U can be converted to a new artificial nuclear fuel 239Pu through a neutron capture. Here 238U plays the role of a breeder material. This is done with seasonable efficiency in a fast nuclear breeder reactor. Also, the emerging fusion nuclear reactors and accelerator-driven systems (ADS) have the potential to be operated as very efficient nuclear breeder reactors. 239Pu and 233U are the most important artificial fuels. The latter is produced though a neutron capture in 232Th. World thorium reserves are approx. 3–4 times more abundant than the natural uranium reserves, which are not in use in present. Although thorium is actually not used as nuclear fuel in conventional reactors, it has very promising potentials for utilization in CANada Deuterium-Uranium Reactor (CANDU) reactors, high temperature reactor (HTR) and fixed bed nuclear reactor (FBNR) as mixed fuel in form of nonconventional nuclear materials. This would be possible due to the excellent neutron economy of heavy water moderated reactors. Thorium cycle produces 233U, which, from a nonproliferation point of view, is preferable to plutonium for two reasons. Firstly, during the breeding process, it will be contaminated with 232U, which decays to give highly radioactive daughter products. This will lead already to high level of deterrence and would make handling and diversion difficult, even impossible for clandestine misuse of nuclear material by terrorist groups or states. Secondly, the 233U can be easily denatured with 238U by adding few fractions in natural uranium to thorium. The quantity of 238U could be fine-tuned so as to be sufficient to denature the 233U, but not so much as to produce a significant quantity of plutonium. The thorium option not only produces electricity, but also replaces the plutonium with denatured 233U as nuclear fuel material. Hence, thorium has the potential to play a large role in future nuclear energy scenarios.

Nuclear Energy

801

Uranium, plutonium, and thorium are metallic materials. They are subjected to phase changes at higher temperatures, where the lattice dimensions, crystal structure, mass and atomic densities change promptly. Each phase change is accompanied with drastic deformation of metallic structure, which results in the destruction of the fuel rod and failure and malfunction. In case of nuclear reactors, this can destroy the reactor core with unforecastable damage. Instantaneous growth of lattice dimensions would furthermore cause rapid drop of the reactor reactivity and would result in an undesired scram in the course reactor operation. Uranium is a radioactive heavy metal with the atomic number of 92 in the periodical table. 235U is the sole natural nuclear fuel. Uranium oxide (UO2) is the only uranium ore in the nature. It is called uraninite or pitchblende. 238 U is the main uranium isotope (99.28%), followed by 235U (0.72%) with half-life times of 4.5  109 and 7.1  108 years, respectively. Therefore, the isotopic fraction of 235U decreases faster than 238U. In present days, the 235U/238U ratio is 1/140 in the uranium ore. In the past, the isotopic fraction of 235U was higher. Higher radioactivity of 235U has decreased the 235U/238U ratio gradually in geological times. In the past, the isotopic fraction of 235U in natural uranium was higher (3%) approx. 2  109 years ago [6]. This can lead to criticality in uranium rich sites and in the presence of ground water as moderating medium in parallel with low level or the absence of strong neutron absorbers, such as boron, iron ore, etc. Traces of fission products in the uranium mines at different locations in South Africa indicate the presence of nuclear chain reactions by ground-water intrusion [6]. Also, the 235 U fraction in those locations is lower than in natural uranium reserves elsewhere. It is estimated that a natural reactor was critical for 100,000 years, at a total power of greater than 100 kW [6]. The most known is found in Franksville region in Gabon, Oklo [6–8]. Metallic uranium has a mass density of 19.4 g/cm3 at room temperature. At higher temperatures, uranium metal is subject to crystal transformation and reveals three allotropic forms and lower mass densities according to the lattice size of the crystal structures. The uranium allotropies are [9]:

• • •

The a-orthorhombic. Uranium is in this state up to 6681C. The lattice size or parameters of the uranium crystal in orthorhombic geometry are: a¼ 285.4 pm, b¼587 pm, and c ¼ 495.5 pm. In the temperature range 6681C4tUo7751C, uranium metal crystal becomes b-tetragonal. The tetragonal crystal lattice parameters of uranium metal will be a¼ 565.6 pm, and b ¼ c¼1075.9 pm. At higher temperatures greater than 7751C, uranium lattice becomes g-body-centered cubic with crystal lattice parameters a¼352.4 pm. This state remains up to the melting point, where the uranium metal becomes most forgeable and ductile.

Plutonium is an artificial element and is produced in nuclear reactors through neutron capture, followed by two successive b emissions. It is one of the most important nuclear fuels. At room temperature, metallic plutonium has a mass density of 19.816 g/cm3 and six allotropes in higher temperatures. The transient temperatures and the change of the mass density of plutonium are depicted in Fig. 4 [10]. These drastic changes at relatively low temperatures make metallic plutonium unsuitable for the reactor construction. Therefore, ceramic fuels PuO2 of PuC are preferred. The melting point of the plutonium metal is relatively low by 639.41C. This is also another handicap for the utilization of the plutonium metal in nuclear power reactors. Thorium is the next important nuclear material after uranium. It is a breeder material for thermal reactors. It has a mass density of 11.7 g/cm3, which is considerably less than uranium. Ergo, the atomic density of thorium is also less than that of uranium. This is a drawback with respect to breeding properties. The crystal structure of thorium metallic is face-centered cubic. At high temperatures (413601C), face-centered cubic undergoes a transition to body-centered cubic crystal. At higher pressures (approx. 100 GPa), thorium metallic crystal gains body-centered tetragonal state [11]. Due to the above mentioned reasons, metallic fuels cannot be used in nuclear power reactors. Chemical ceramic forms are the preferred form of the nuclear fissile fuels, despite of a significant sacrifice in the atomic density. The most common ceramic fuel is in the oxide form due to the stability at higher temperatures and inertness against water at high operating temperatures.

Pu density (g cm−3)

-Pu 19 -Pu

18

-Pu 17 ε-Pu 16

′-Pu

-Pu 0

100

200

300

400

500

600

Temperature (°C) Fig. 4 Change of the specific mass of the plutonium metal at different allotropic stages. Reproduced from Wikipedia. Plutonium. Available from: https://en.wikipedia.org/wiki/Plutonium.

802

Nuclear Energy

Uranium dioxide (UO2) or urania is the most common nuclear fuel in use today. It has a very high melting point of 28651C. The mass density at room temperature is 10.97 g/cm3. UO2 is a black powder. It will be sintered to fuel pellets with a density of approx. 80%. This compensates the thermal expansion at higher reactor operation temperatures to some degree. Plutonium is mostly used in oxide form (PuO2). PuO2 has a complex crystal structure, where the Pu4 þ ions are placed in a face-centered cubic array and the oxide ions fill the tetrahedral holes. The high melting point of PuO2 (23901C) and its extremely low solubility in water makes it a preferred fuel for the nuclear reactor construction. PuO2 can be chemically separated from other elements in the spent fuel of the conventional LWR and CANDU reactors. In praxis, it is used in the form of a mixed fuel as UO2/PuO2. It is important to keep the PuO2 fraction less than 20% due to shorter delayed neutron fraction of plutonium isotopes, which is the essential parameter for reliable reactor control. Thorium is used as a breeder material in oxide form (ThO2), called thoria. The specific mass of ThO2 with 10 g/cm3 is close to that of metallic thorium. Very high melting point of ThO2 (33001C) makes this material extremely resistant in case of reactor accidents. It is used to breed the very precious nuclear fuel 233U through a neutron capture in a nuclear reactor. In other terms, thorium becomes a nuclear fuel as well, but it needs two neutrons in thermal reactors for fission.

1.20.3.2

Fission Fuels Assemblies

Uranium is extracted from the ore and converted to the unique gas form UF6 for enrichment. High pressure UF6 is delivered in gas cylinders to the fuel fabrication plant, where in the first step it is converted to ceramic fuel powder, mostly to UO2. Plutonium, thorium or mixed oxide fuel must also be handled in similar manner. In the second step, fuel powder is sintered to cylindrical fuel pellets of greater than 1 cm diameter and approx. 1 cm height for utilization in conventional reactors, such as LWR, HWR, CANDU reactors and FBs, depicted in Fig. 5 [12]. In the third step, fuel rods are filled with fuel pellets, and the formers are assembled to fuel bundles for utilization in conventional nuclear LWRs (see Fig. 6 [13]). The claddings of the fuel rods are refractory metals are made of high steel alloys for LWRs and FBs, where low enriched uranium (LEU) is used and neutron absorption in steel structures is compensated with more 235 U content in the fuel, enriched to 3% to 20% according to the reactor type. For heavy water-natural uranium reactors, the fuel rod claddings must be made of Zircaloy for the sake of lower neutron absorption due to the low 235U fraction (0.72%) in the fuel. Fig. 7 shows the three-step fuel fabrication process in a chain [14]. Within the framework of the generation-IV (GEN-IV) reactors, new fuel types have been developed in particular for utilization in HTRs. The most important one are liquid molten salt fuels for reactors with liquid coolant and solid tristructural-isotropic (TRISO) fuels for reactors with gas coolant.

1.20.3.2.1

Molten salt fuels

Molten salt fuels are always mixed with a molten salt coolant. This allows continuous cleaning of the coolant/fuel mixture, removal of fission products, prevents the accumulation of reactor slugging and keeps the active fuel mass in the reactor core at minimum, which is an important safety factor. Several molten salts as reactor coolant, both for fission as well as fusion reactors have been developed and investigated. The primary candidate is FLIBE (Li2BeF4), a molten salt, made from a mixture of lithium fluoride (LiF) and beryllium fluoride (BeF2). FLIBE is transparent in liquid and solid forms, as shown in Fig. 8 [2]. However, soluble fluorides, such as UF4, ThF4, and PuF3/ PuF4, can dramatically change the salt color in both solid and liquid state. Natural lithium consists of two isotopes, highly absorbing 6Li (7.5%) and 7Li (92.5%). For fission reactor applications, lithium must be enriched in 7Li in order to avoid the parasitic neutron absorption in 6Li. Traces of the latter can be tolerated to some degree, as it will rapidly be transformed to 7Li through neutron capture reaction. On the other hand, the presence of 6Li is desirable, even enriched 6Li for tritium breeding in situ. Freezing points of fluoride salts are between 360 and 5001C, dependent on the salt composition. The eutectic mixture is slightly greater than 50% BeF2 and has a melting point of 3601C. Hence, they are not suitable for low-temperature reactors. Operation temperatures are 500 to 7501C. Very high temperatures can be achieved (411001C) if carbon composites are successfully employed. Major superiority of a molten salt reactor (MSR) can be summarized as low operation pressure (approx. 0.7 MPa), low

Fig. 5 Sintered fuel pellets. Reproduced from Wikipedia. Nuclear reactor fuel. Available from: https://www.google.com.cy/search?q=nuclear þ reactor þ fuel&rlz=1C1GKLB_en__721__721&source=lnms&tbm=isch&sa=X&ved=0ahUKEwjilYqq5eTTAhVpCcAKHR7zAhoQ_AUIBigB&biw= 1280&bih=869#imgrc=3tg1H93p2VvudM.

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Spacer grids

Nuclear fuel pellet Cladding Fuel rod Guide tube Instrument tube Fig. 6 Assemblage of fuel bundles. Reproduced from Wikipedia. Nuclear reactor fuel. Available from: https://www.google.com.cy/search?q= nuclear þ reactor þ fuel&rlz=1C1GKLB_en__721__721&source=lnms&tbm=isch&sa=X&ved=0ahUKEwjilYqq5eTTAhVpCcAKHR7zAhoQ_ AUIBigB&biw=1280&bih=869#imgrc=C7Nxm1pM853S-M.

Uranium recovery

1 cm

Incoming UF6 gas cylinders

Conversion of UF6 into UO2 powder

Powder processing and pellet manufacturing

Off-gas and waste-water treatment

4m

Pellets into fuel rods and fuel assemblies

Outgoing fuel assemblies for reactors

Fig. 7 The three-step fuel fabrication process. Reproduced from Wikipedia. Nuclear reactor fuel fabrication. Available from: https://www.google. com.cy/search?q=nuclear þ reactor þ fuel þ fabrication&rlz=1C1GKLB_en__721__721&source=lnms&tbm=isch&sa=X&ved=0ahUKEwj3v-H55TTAhVOKlAKHc0lC_UQ_AUIBigB&biw=1280&bih=869#imgrc=AxcremXoSrIGNM.

coolant volume for the required heat transfer capacity, but very high coolant temperatures. Consequently, the nuclear heat energy of molten salt-cooled reactors is most suitable to be used directly for Brayton power cycles and hydrogen production. The primary salt fuel and breeder are UF4 and ThF4. Construction of commercial MSRs will also bring the plutonium salts PuF3 and PuF4 into consideration. The melting points of salt fuels are considerably higher than reactor operation temperature. However, in mixed form with molten salts, melting points sink to reasonable temperature for reactor operation. Table 3 shows the composition and melting points of some molten salts, under for nuclear breeder reactor design studies with thorium/uranium salts [15].

1.20.3.2.2

Tristructural-isotropic type fuel

The TRISO fuel has been developed for utilization in gas-cooled HTRs. Spherical fuel kernels are coated with multiple SiC and pyrocarbon layers to provide structural stability to the fuel capsule and for very long-term containment of fission products

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Fig. 8 Transparency of FLIBE (Li2BeF4) salt in liquid and solid form. Reproduced from S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011. Table 3

Some thermo-physical properties of molten salt reactor breeder fuel-salt

Salt composition (% mol)

Liquidus temperature (1C)

UF4 (100) ThF4 (100) PuF3/PuF4 (100) LiF-BeF2-ThF4-UF4 LiF-BeF2-ThF4-UF4 LiF-BeF2-ThF4-UF4 LiF-BeF2-ThF4-UF4

960 1100 – 50075 50075 48075 50075

(73 (72 (68 (63

16 21 20 25

10.7 0.3) 6.7 0.3) 11 7 0.3) 11.7 0.3)

Source: Reproduced from Cantor S, Cooke JW, Dworkin AS, Robbins GD, Thoma RE, Watson GM. Physical properties of molten-salt reactor fuel, coolant, and flush salts. ORNL/TM-2316; 1968.

100 μm Uranium

Carbon

Silicon carbide

Fig. 9 The structure of the multilayer tristructural-isotropic (TRISO) coating with large fuel kernel. Reproduced from NGNP Alliance Blog. TRISO fuel news. Available from: http://blog.ngnpalliance.org/triso-fuel-news/; 2013.

(approx. 4 million years). TRISO particles with a large fuel kernel have a diameter of approx. 2.2 mm, and those with a small fuel kernel of approx. 0.9 mm. Fig. 9 shows the electron-microscope picture of the cross-section of a typical TRISO particle with small kernel. One can distinguish clearly the carbon and SiC coatings [16]. Such a TRISO capsule is a miniature pressure vessel and can withstand pressures up to 1000 atm. Experiments at IDAHO Laboratories have shown excellent performance of the TRISO fuel at extreme temperatures up to 18001C. Experimental studies at

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5 mm graphite layer Coated particles imbedded in graphite matrix Pyrolytic carbon 40/1000 mm Silicon carbide barrier coating 35/1000 mm Inner pyrolytic carbon 40/1000 mm Porous carbon buffer 95/1000 mm

Dia. 60 mm Fuel sphere

Section

Dia. 0.92 mm TRISO coated particle

Dia. 0.5 mm Uranium dioxide Fuel Kernel

Fig. 10 Formation steps of a spherical tristructural-isotropic (TRISO) fuel element. Reproduced from S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011.

the US Department of Energy’s Idaho National Laboratory (INL) and Oak Ridge National Laboratory (ORNL) have further found that most fission products remain inside the irradiated TRISO particles even at temperatures of 18001C, more than 2001C hotter than in postulated accident conditions [17]. TRISO fuel pellets with plutonium fuel have been irradiated in Peach Bottom Reactor and have reached burnup values in the range of approx. 740,000 MWd/t without damage of coating layers [18,19]. Within the framework of the development of GEN-IV reactors, TRISO type is foreseen for two major projects:

• •

pebble bed modular reactor (PBMR) project in South Africa; and gas turbine modular helium reactor (GT-MHR) common project between United States–Russian Federation.

Fig. 10 shows the four main formation steps of a spherical TRISO fuel element for utilization in a PBMR [2]. At the bottomright is a small fuel kernel made of either uranium or thorium or nuclear waste actinides. It is coated with carbon and SiC layers to form a TRISO particle (second right). In the third step, TRISO particles are imbedded in a graphite matrix and form a spherical fuel compact. The latter is covered with a 5-mm thick graphite layer. At the end, spherical fuel compacts are ready to fill the core of PBMR, top-left. Fig. 11 shows the four main formation steps of the fuel for the GT-MHR [2]. For that case, TRISO particles are imbedded in cylindrical fuel compact. The fuel compacts then are inserted in the holes drilled in graphite blocks for utilization in a heliumcooled modular thermal reactor or in a pin for a gas-cooled fast reactor. In all cases, TRISO fuel capsules can withstand to gigantic burnups and to temperatures expected in any type of high temperature reactor.

1.20.3.3 1.20.3.3.1

Fusion Reactors Fuels Fusion reaction physics

Fusion reactions of atomic nuclei are much more cumbersome to realize than fission due to the Coulomb repulsion forces between two atomic nuclei. This can be overcome only by increasing the kinetic energy of nuclei as charged particles. In laboratory scale, this can be achieved through an accelerator, where a positive energy gain is not compulsory. High energy gain factors are required in fusion reactors, which is possible at high temperatures and pressures with an overall increase of kinetic energy and the density of all reacting nuclei in the reaction chamber. First generation fusion reactor concepts are based on (D,T) or (D,D) fusion reactions. However, other fuel cycles may become attractive alternatives for advanced fusion systems. Fusion energy output is considerably higher than the kinetic energy of the reacting nuclei. Hence, the total reaction energy in those reactions is practically shared by two fusion products by conservation of energy and momentum as follows: Q ¼ E1 þ E2

ð8Þ

m1 E1 ¼ m2 E2

ð9Þ

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Pyrolytic carbon Silicon carbide Porous carbon buffer Fuel Kernel−TRU oxide

Fuel form/ waste form for waste

Particles

Compacts

TRISO coating

Fuel elements

Fig. 11 Tristructural-isotropic (TRISO) fuel compact for a gas-cooled high temperature reactor. Reproduced from S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011.

Fig. 12 shows the reaction cross-sections for the most important fusion reactions, a function of plasma temperature [20]. At relatively lower plasma temperatures, the (D,T) reaction has the highest reaction probability than all fusion reactions. Charged particle velocities, i.e., the ion energy, are also very important for fusion. Hence, more comprehensive information can be deduced through the energy-dependent RR parameter osV4, shown in Fig. 13 for mainline reaction cycles [21]. By approx. 10 keV, the RR of (D,T) is about two orders of magnitude higher than (D,D) reaction, whereas it is negligible for (D,3He) reaction. On the other hand, the RR of the latter increases rapidly at higher fusion plasma temperatures and surpasses (D,D) for 420 keV. The way from 10 keV to 420 keV is estimated relatively faster to be achieved than most of the challenges in the course of the development of fusion technology. The (D,T) reaction has been considered as the classical fusion fuel because of the highest reaction probability among all fusion reactions. Hence, the first generation of fusion reactors will likely be of the (D,T) mode. However, tritium is an artificial element. Furthermore, being a radioactive material, it has limited lifetime and storage capability. In a (D,T) fusion reactor, 80% of the fusion energy is carried by the neutrons. This also represents all the available energy for external use through a heat engine. In a commercial (D,T) fusion power plant, the a-particle energy (20% of the total fusion energy) serves primarily to heat the fusion plasma for sustaining the fusion reaction. Hence, only fusion neutron energy can be recuperated via a heat engine in a

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1.0–27

D−T

1.0–28

Cross section (m2)

D−3He 1.0–29 Total D−D p−11B

1.0–30

1.0–31

1.0–32 1

3He−3He

2

5

10 20 50 100 Center−of−mass energy (keV)

200

500

1000

Fig. 12 The microscopic cross-sections for the major fusion reactions (1 b ¼10 28 m2; 1 eV¼11,400K). Reproduced from Wikipedia. Fusion cross-sections of various fusion reactions. Available from: https://www.google.com.cy/search?q=Fusion þ cross-sections þ of þ various þ fusion þ reactions&rlz=1C1GKLB_en__721__721&source=lnms&tbm=isch&sa=X&ved=0ahUKEwieh_3C-vPTAhVpDcAKHX1ID-EQ_AUIBigB&biw=1280& bih=918#imgrc=jGT0PvE1bznnVM.

10–20

10–21

DD DT D3 He P6Li P11B

v0 (m3/s)

10–22

10–23

10–24

10–25

10–26 100

101

102

103

T (keV) Fig. 13 Maxwell-averaged fusion reaction rate parameter osV4 vs. ion temperature. Reproduced from Duderstadt JJ, Moses GA. Inertial confinement fusion. New York, NY: John Wiley and Sons; 1982.

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nuclear thermal power plant over the conventional thermodynamic cycle with a steam or gas turbine. A substantial waste thermal energy will be released to the environment. Another undesired phenomenon with the inevitable fusion neutron production is radioactive contamination of the structures and other materials with diverse neutron induced reactions. Detailed list of all possible primary and secondary fusion reactions to be considered in the design of early generation fusion reactors as well as those in advanced stage is given in Table 4 [22,23]. Deuterium constitutes 0.015% of natural water resources in oceans and elsewhere as heavy hydrogen, i.e., there is one atom of D (2H1) for every 6700 atoms of light hydrogen atom 1H1. This tiny amount of D in 1 L of natural water contains fusion energy equivalent to as much as 300 L of gasoline. Deuterium in the seawater can cover the world energy needs for billions of years. The relative abundance of the deuterium fuel in the Earth’s hydrosphere makes (D,D) reactors almost as attractive as (D,T) reactors. Three different (D,D) fusion reactor types have been considered for related system studies: 1. Pure (D,D) reactors: 4D-p þ T þ He3 þ nð2:45 MeV Þ þ Qð5:119 MeV Þ

ð10Þ

Q is the cumulative energy of the charged reaction products. In such a reactor, the reaction products T and He3 must be removed continuously to prevent their burnup in situ. However, in practice, it is impractical to avoid burnup of certain fraction of the T in the fusion chamber. Charged reaction products in Table 4

Pertinent fusion reactions

Deuteron-based fusion fuels Primary reactionsa D þ T-n þ 4He þ 17.856 MeV (3.517 MeV) D þ D-p þ T þ 4.032 MeV (4.302 MeV) D þ D-n þ 3He þ 3.267 MeV (0.817 MeV) D þ 3He-p þ 4He þ 18.341 MeV (18.341 MeV) D þ 6Li-24He þ 22.374 MeV (22.374 MeV) D þ 6Li-p þ 7Li þ 5.026 MeV (5.026 MeV) D þ 6Li-n þ 7Be þ 3.380 MeV (0.473 MeV) D þ 6Li-p þ T þ 4He þ 2.561 MeV (2.561 MeV) D þ 6Li-n þ 3He þ 4He þ 1.796 MeV (B1.134 MeV) D þ 7Be-2 4He þ p þ 16.5 MeV (16.5 MeV) Secondary reactions p þ T-n þ 3He 0.765 MeV (-) T þ T-2n þ 4He þ 11.327 MeV (B1.259 MeV) T þ 3He-n þ p þ 4He þ 12.092 MeV (B6.718 MeV) T þ 3He-D þ 4He þ 14.319 MeV (14.319 MeV) 3 He þ 3He-2p þ 4He þ 12.861 MeV (12.861 MeV) Proton-based fusion fuels Primary reactions p þ 6Li-3He þ 4He þ 4.022 MeV (4.022 MeV) p þ 9Be-4He þ 6Li þ 2.125 MeV (2.125 MeV) p þ 9Be-D þ 2 4He þ 0.652 MeV (0.652 MeV) p þ 11B-3 4He þ 8.664 MeV (8.664 MeV) Secondary reactions He þ 6Li-p þ 2 4He þ 16.880 MeV (16.880 MeV) 3 He þ 6Li-D þ 7Be þ 0.113 MeV (0.113 MeV) 3 He þ 3He-2p þ 4He þ 12.861 MeV (12.861 MeV) 3 He þ 9Be-3 4He þ 18.74 MeV (18.74 MeV) 4 He þ 9Be-n þ 12C þ 5.702 MeV (0.439 MeV) 4 He þ 9Be-n þ 34He 1.573 MeV ( ) 4 He þ 11B-p þ 14C þ 0.784 MeV (0.784 MeV) 4 He þ 11B-n þ 14N þ 0.158 MeV (0.011 MeV) p þ 10B-4He þ 7Be þ 1.147 MeV (1.147 MeV) 7 Be þ 6Li-3 4He þ p þ 15 MeV (15 MeV) 3

a First number: total fusion reaction energy. Note: Number in parenthesis: energy carried by charged reaction products. Sources: Reproduced from Mc Nally Jr JR. Physics of fusion fuel cycles. Nucl Technol/Fusion 1982;2/1:9–28; S¸ahin S. Candidate structural materials for fusion energy reactors. J New Türkiye; Sci Technol Spec Issue 2016;89:727–821. ISSN: 1300-4174.

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Eq. (3) carry 70% of the total fusion energy. This opens the possibility of direct energy conversion with significantly higher conversion efficiency than in case of thermal cycle. 2. Catalyzed (D,D) reactors: In a so-called catalyzed (D,D) reactor, all reaction products interact with D and contribute to fusion energy production. D þ D -p þ T D þ D -He3 þ n D þ T -He4 þ n He3 þ D-p þ He4 þ_____________________ 6 D-2p þ 2He4 þ nð2:45 MeV Þ þ nð14:1 MeV Þ þ Qð26:977 MeV Þ

ð11Þ

In catalyzed (D,D) reactors 62% of the total fusion energy is carried by charged particles, suitable for direct energy conversion. 3. Semicatalyzed (D,D) reactors: It is similar to the catalyzed (D,D) reactors, but a continuous removal of He3 is attempted for utilization in a (D,He3) reactor to produce energy in a fusion reactor with drastically reduced neutron background. 5 D-p þ He3 þ He4 þ nð2:45 MeV Þ þ nð14:1 MeV Þ þ Qð26:977 MeV Þ

ð12Þ

In the semicatalyzed (D,D) reactors, only approx. 1/3 of the fusion energy is carried by the charged fusion reaction products. This is needed to sustain continuity of the fusion reaction in the plasma chamber. (D,D) and (D,T) fusion neutron will deliver heat energy in the fusion blanket for the thermodynamic power cycle. 4. (D,He3) reactors: In a (D,He3) reactor charged fusion reaction products carry almost all of the fusion energy. There will be minor fusion neutron production through undesired secondary reaction, which carries only approx. 2% of the total fusion energy. Low neutron production reduces the radioactive contamination of the fusion chamber fist wall and other structures drastically. This is one of the major advantages of (D,He3) reactors. They are also best suited for direct energy production with high efficiency by collecting the positively charged H and He reaction products on an anode.

1.20.4

Nuclear Power Reactor Types

Nuclear power reactors have been providing commercial electricity since the early 1950s. At present, more than 400 reactors in different countries are providing more than 11% of the world’s electricity. Meantime, many reactor constructors have emerged. Fig. 14 shows the distribution of electricity generating nuclear power plants in the world [2]. Most of them are concentrated in North America, European Union, East Asia, and Russian Federation. European Union has very scarce nuclear resources and receives most of the uranium ore from Africa, while the entire African continent has not one single nuclear reactor, except down at the tip of South Africa. Presently, China and India are pursuing very progressing-aggressive nuclear reactor construction activities. Detailed information about the status of the world nuclear power reactors by December 2016 is listed in Table 5 [24]. The operating nuclear reactors can be classified on technology basis as follows:

• • • • • • • • •

pressurized water reactors (PWR, approx. 68.8%) boiling water reactors (BWR, approx. 9.5%) pressurized heavy water reactor (PHWR/CANDU, approx. 6.5%) light water graphite reactor (Reactor Bolshoy Moshchnosty Kanalny (RBMK) and energy heterogeneous direct current reactor with 6 loops of circulation of the coolant (EGP-6), approx. 2.7%) gas-graphite reactors sodium-cooled FBs floating military nuclear reactors in submarines and aircraft carriers space nuclear reactors GEN-IV reactors (in development)

If graphite or heavy water is used as moderator, it is possible to run a power reactor on natural instead of enriched uranium, commonly to 3.5%–5.0%. In this case, the moderator can be ordinary water, and such reactors are collectively called LWRs. Because the light water absorbs neutrons, as well as slowing them, and hence has smaller moderating ratio than D2O and C. On the other hand, higher moderating power of the light water leads to smaller reactor size than heavy water or graphite. Since the 1950s, the development of nuclear technology has progressed rapidly with significant improvements. One distinguishes hereby four reactor generations from GEN-I to GEN-IV. Fig. 15 depicts the reactor generations starting from the prototype GEN-I reactors to revolutionary GEN-IV reactors.

1.20.4.1

Pressurized Water Reactors

The most widespread nuclear reactors in operation are of the PWRs type. The design of PWRs originated as a submarine power plant. PWRs use ordinary water as both coolant and moderator. The design is distinguished by having a primary cooling circuit

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Fig. 14 Nuclear power plants around the world – map (March 8, 2012). Available from: https://www.theguardian.com/environment/interactive/ 2012/mar/08/nuclear-power-plants-world-map.

which flows through the core of the reactor under very high pressure, and a secondary circuit in which steam is generated to drive the turbine. In Russia these are known as VVER types – water-moderated and cooled. Main technical data of the reactor vessel and coolant system of a PWR are listed in Table 6 [2]. The reactor vessel is exposed to the high pressures and temperatures and must withstand over the entire reactor life time of more than 60 years, as expected from the GEN-III þ reactors, built and sold since the 1990s. The majority of commercial terrestrial nuclear power plants are of PLWR type with enrichment grades in the range of 3% to 5%. The weight of the fuel assembly for a PWR is typically approx. 650 kg and contains approx. 320 kg uranium in the form of UO2 pellets (see Figs. 5 and 6). The nuclear reactor, the pressurizer and the steam generator are placed in a reinforced steel–concrete building, so called containment building with a wall thickness of approx. 1 m. The containment building is built airtight and kept at 300–600 Pa under pressure to avoid radiation leaks leakage into the atmosphere. Fig. 16 shows the German Philippsburg Nuclear Power Plant with twin cooling towers and stuck as an example of PWR.

1.20.4.2

Boiling Water Reactors

BWRs are in the second range of nuclear power plants in operation. Saturated steam is generated in the core and will be directed to the turbine. There is neither a steam generator nor a secondary loop necessary, which makes the reactor design simpler. Expensive and complicated steam generator, pressurizer and secondary heat exchanger loop are saved. The machine park outside the reactor building is similar to that of a LWR. The weight of the fuel assembly for a PWR is typically approx. 320 kg and contains approx. 180 kg uranium in the form of UO2 pellets (see Figs. 5 and 6). The main features of BWR can be cited as follows:

• • • •

simplicity; higher thermal efficiency, because of higher steam temperature; easier follow-up of load. The reactor building contains only the reactor vessel as a main component; and lower investment.

1.20.4.3

CANada Deuterium-Uranium Reactors

One of the most important nuclear power plants is the heavy water (D2O) moderated and cooled called CANDU Reactor. It is a PHWR using natural uranium. The neutron absorption in both D and O atoms are extremely low, leading to a very high moderating ratio of D2O, enabling to build a nuclear reactor with natural uranium. Fuel rods, pressure, and calandria tubes are made of zirconium alloy (Zircaloy), zirconium being hard, corrosion-resistant, and transparent to neutrons. Zircaloy consists of approx. 98% Zr, þ 1.5% tin, also iron, chromium, and sometimes nickel to enhance the strength. The calandria vessel is not

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Table 5

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Overview of power reactors and nuclear share, December 31st, 2016

Country

Argentina Armenia Belarus Belgium Brazil Bulgaria Canada China Czechrep Finland France Germany Hungary India Iran, Isl.Rep Japan Korea, Rep.of Mexico The Netherlansds Pakistan Romania Russia Slovakia Slovenia South Africa Spain Sweden Switzerland Taiwan UAE United Kingdom Ukraine United States Total

Operational reactors

Reactors in long-term shutdown

Reactors under construction

Nuclear electricity in 2016

No. of units

No. of units

No. of units

Net capacity (MWel)

TWel
h

% of total

1

25

2

2,218

1

1,245

21

21,622

1 1

1,600 1,630

5

2,990

2 3

2,653 4,020

3

2,343

7 2

5,520 880

2 4

2,600 5,380

2 4 61

2,070 4,468 61,264

7.7 2.2 NA 41.4 15.0 15.1 95.7 197.8 22.7 22.3 386.5 80.1 15.2 35.0 5.9 17.5 154.3 10.3 3.7 5.4 10.4 184.1 13.7 5.4 15.2 56.1 60.6 20.3 30.5 NA 65.1 76.1 804.9 2,476.2

5.6 31.4 NA 51.7 2.9 35.0 15.6 3.6 29.4 33.7 72.3 13.1 51.3 3.4 2.1 2.2 30.3 6.2 3.4 4.4 17.1 17.1 54.1 35.2 6.6 21.4 40.0 34.4 13.7 NA 20.4 52.3 19.7 NA

3 1 7 2 2 19 36 6 4 58 8 4 22 1 42 25 2 1 4 2 35 4 1 2 7 10 5 65,052 15 15 99 448

Net capacity (MWel)

Net capacity (MWel)

1,632 375 5,913 1,884 1,926 13,554 31,384 3,930 2,764 63,130 10,799 1,889 6,240 915 39,752 23,077 1,552 482 1,005 1,300 26,111 1,814 688 1,860 7,121 9,740 3,333

8,918 13,107 99,869 391,116

1

1

2

246

446

692

Source: Reproduced from IAEA. Nuclear power reactors in the world. IAEA-RDS-2/37, Vienna, Austria. ISBN: 978-92-0-104017-6; ISSN: 1011-2642; 2017.

exposed to high temperatures or pressures and hence has a thickness of 2.86 cm and is made simply of ASTM 304L steel. A high quality refractory steel alloy is not needed. The fabrication of the reactor vessel with several meters of diameter at atmospheric pressure with few centimeters wall thickness requires only modest technology. Reactor coolant flows through the pressure tube, where the fuel rods are placed in fuel bundles. Under on-power condition, the fresh fuel bundles are pushed into the reactor through the pressure tubes with a special loading machine from one side, while the depleted fuel bundles are discharged from the other side. This leads to high plant operation factor. Unique features of the CANDU reactor can be summarized as follows:

•

•

•

The fabrication of the reactor vessel of a CANDU reactor is relatively easy compared to LWR vessels, as the former is not exposed to high pressures and temperatures. Hence, the fabrication can be made with simple carbon steel. It is predestined for countries to acquire nuclear technology, which lack the heavy industry to cast and machine the pressure vessels made of high quality refractory steel alloy with high precision, free of cracks, and other material defects. Natural uranium can be used as fuel. In CANDU the moderator is at low temperatures with lower speed of the moderator atoms. The neutron absorption in both D and O atoms are extremely low which also is an important reason. This means most of the neutrons will end up at a lower energy and be more likely to cause fission, so CANDU not only "burns" natural uranium, but it does so more effectively as well. Overall, CANDU reactors use 30%–40% less mined uranium than LWRs per unit of electricity produced. This is a major advantage to the heavy water design; it not only requires less fuel, but as the fuel does not have to be enriched, it is much less expensive as well. Delivery of natural uranium is not limited to few states. CANDU allows utilization of thorium with very low enriched (approx. 1%–2%) uranium as well as with the spent fuel of LWRs.

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Generations of nuclear energy

Generation IV

Generation III+ Generation III

Evolutionary designs

Generation II

Generation I Early prototypes

Revolutionary designs

Advanced LWRs Commercial power

−Safe −Sustainable

−ABWR −CANDU 6 −Shippingport −Dresden

1950

1960

−PWRs

−System 80+

−APWR

−BWRs

−AP600

−EPR

1970

Gen I

−Proliferation resistant and physically secure

−AP1000

−CANDU

−Magnox

−Economical

−ACR1000

−ESBWR 1980

1990

Gen II

2000

2010

Gen III

2020

Gen III+

2030

Gen IV

Fig. 15 Progress of nuclear technology from generation I to IV (GEN I–IV) reactors. Table 6

Main technical data of the reactor vessel and coolant system

Reactor coolant pressure (atm) Secondary system pressure (atm) Coolant inlet temperature (1C) Coolant outlet temperature (1C) Coolant flow rate (m3/h/loop) Pump shaft power (kW) DP (atm) Height (m) Thickness (mm) Internal diameter (m) Weight (ton) Material

B153 (max. 170 atm) B60 B288 B328 (max. 3431C) 2.01  104 for 3420 MWth 2.58  104 for 4450 MWth 4470–7460 6 11.5–13.5 180–255 3.4–5.2 240–590 Manganese–Molybdenum steel

Source: Reproduced from S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011.

• •

On-power fuel loading–unloading of the fuel makes a batch loading unnecessary and leads to a high plant power factor. Production of small-scale tritium.

1.20.4.4

Light Water Graphite Reactor (Reactor Bolshoy Moshchnosty Kanalny and EGP)

The Soviet-designed RBMK (high power channel reactor) is a pressurized water-cooled reactor. The main distinction from other commercial reactors is implication of individual fuel channels. It is a graphite moderated reactor. It is also known as the LWGR. Fig. 17 shows the main components of a Soviet-designed light water/graphite moderated reactor [25]. The combination of graphite moderator and water coolant is found in no other power reactor in the world. RBMK contains vertical pressure tubes of 7-m length passing through the graphite moderator. The water cooling is limited to 2901C the core. Fuel is LEU oxide made up into fuel assemblies 3.5 m long. With moderation largely due to the fixed graphite, excess boiling reduces the cooling and neutron absorption. This leads to a positive temperature coefficient, which is one of the main causes of uncontrolled reactor power excursion. The positive void coefficient was the main cause of the Chernobyl accident. Due to increased risk of reactor accident, they have never been built outside the Soviet Union.

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Fig. 16 Philippsburg Nuclear Power Plant, Philippsburg, Karlsruhe district, Germany.

Control rods Concrete shield

Steam generators

Graphite moderator Fuel elements

Pressure tubes Fig. 17 A Soviet-designed light water/graphite moderated reactor. Reproduced from Nuclear Power Reactors. Available from: http://www.worldnuclear.org/information-library/nuclear-fuel-cycle/nuclear-power-reactors/nuclear-power-reactors.aspx; 2017.

1.20.4.5

Advanced Gas-Cooled Reactor

Early generation AGR was developed in England from the Magnox reactor, as graphite moderated and CO2 cooled one. Secondary coolant is water. Fuel was natural uranium in metallic form. Hence, the steam pressure and temperatures were low, the plant efficiency modest. The second generation of British gas-cooled reactors uses graphite moderator and CO2 as primary coolant. The fuel is uranium oxide pellets, enriched to 2.5%–3.5%, in stainless steel tubes [25]. The CO2 coolant is heated to 6501C at a pressure of 40 atm and produces superheated steam at a temperature of approx. 6001C in the steam generator located inside the concrete and steel pressure vessel. Such high steam temperatures allow reaching thermodynamic conversion efficiencies approx. 41%. Fig. 18 shows the main components of an advanced gas-cooled reactor (AGR).

1.20.4.6

Sodium-Cooled Fast Breeders

Reactors with the fuel production-to-consumption ratio exceeds greater than 1.0 are called “breeder reactors,” where more than two neutrons are needed. Sodium-cooled FBs are connected to the grid for about 60 years with great expectation to have an important share in the world energy market after the 1980s. However, their electricity cost is still about double of the LWRs; hence, they are not yet commercially competitive. Also the actual doubling time of FBs is much longer than originally postulated

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Concrete pressure vessel

Control rods

Steam generator

Carbon dioxide

Fuel elements

Graphite moderator Fig. 18 The main components of an advanced gas-cooled reactor (AGR). Reproduced from Nuclear Power Reactors. Available from: http://www. world-nuclear.org/information-library/nuclear-fuel-cycle/nuclear-power-reactors/nuclear-power-reactors.aspx; 2017.

(approx. 50 years). Notwithstanding, FB technology is the sole established one to make use of the waste uranium resources by conversion of the main isotope 238U to the new fuel 239Pu. Whereas, LWRs can make use only about 1% of uranium with plutonium recycles. Another very important feature of fast reactors is their suitability to operate as “burners.” Water-cooled nuclear power plants are producing nuclear waste materials in substantial quantities as minor actinides (MAs) with long half-life times and high level a-radioactivity. FBs are capable to burn the MA with great efficiency and to produce energy from this nuisance nuclear waste. France has implemented PHÉNIX and SUPERPHÉNIX reactors as early as in 1973 and 1985, respectively. Russian Federation, India, and China also have ambitious programs in developing FBs. Fig. 19 shows an artistic view of the Russian BN-1200 reactor project in planning [26].

1.20.4.7

Naval Nuclear Reactors

In the present time and also in a foreseeable future, the requirements for military naval vessels are and will be dictated by the longtime independence of operation basis with respect to fuel supply, freshwater provision and dehydrated food storage. The latter needs on board seawater distillation. Economic considerations have secondary range for national defense. This is particularly important for aircraft carriers and submarines charged with nuclear warheads, which also need much more powerful systems for propulsion. Conventional fossil fuels, either coal or diesel oil, cannot meet these exigencies. Only nuclear reactors can provide high power over long periods without refueling. Due to the mobility and the dynamic nature of marine vessels, the pressurized water reactor type has been used for the first nuclear submarine USS Nautilus and the following US naval fleet. Russia has preferred to develop both PWR and lead–bismuth-cooled reactors. Also Britain, while France, Russia, China, and India have developed their own naval reactor technology. Russia has built the largest submarines, called Typhoon type (26,500 t) and Oscar-II type (24,000 t). These submarines have twin reactors of 190 MWth [27]. The US Navy has accumulated over 6200 reactor-years of accident-free experience involving 526 nuclear reactor cores for 4240 million kilometers operation experience without a single radiological incident over a period of more than 50 years. This involved 82 nuclear naval vessels (11 aircraft carriers, 71 submarines) with 103 reactors up to March 2010. In 2013, it had 10 Nimitz-class aircraft carriers in service, each designed for 50-year service life with one mid-life refueling and complex overhaul of their two Westinghouse reactors. The forthcoming Gerald Ford-class aircraft carriers will have some 800 fewer crew and two more powerful Bechtel reactors driving four shafts. Late in 2014, the US Navy had 86 nuclear-powered vessels including 75 submarines. The safety record of the US nuclear navy is excellent, this being attributed to a high level of standardization in naval power plants and their maintenance, and the high quality of the Navy’s training program. Russia built 248 nuclear submarines and five naval surface vessels (plus nine icebreakers) powered by 468 reactors between 1950 and 2003, and was then operating about 60 nuclear naval vessels. China has about 12 nuclear-powered submarines, and is building 21 more. France has a nuclear-powered aircraft carrier and 10 nuclear submarines. The United kingdom has

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Core cover plug

Intermediate exchanger Pump

Main vessel

Core Strongback Vessel support structure

Core catcher

Diagrid Vessel diameter: 12.9 m Height: 14 m

Fig. 19 Sectional view of the Russian BN-1200 reactor project. Reproduced from Parisot J-F, editor. Sodium-cooled nuclear reactors. Paris: Éditions du Moniteur; Commissariat à l’énergieatomique et aux énergies alternatives; 2016.

Table 7

Annual estimated average effective dose equivalent per person in the United States

Inhaled (radon and decay products) Other internally deposited radionuclides Terrestrial radiation Cosmic radiation Rounded total from natural source Rounded total from artificial sources (medical, industrial, etc.) Total

(mSv)

mrem

2.29 0.31 0.19 0.27 3.1 3.1 6.2

229 31 19 27 310 310 620

Source: Reproduced from The National Council on Radiation Protection and Measurements (NCRP). Ionizing radiation exposure of the population of the United States. NCRP report no. 160; 2006.

12 submarines, all nuclear powered. The United Kingdom’s new large aircraft carriers are powered by two 36 MWel gas turbines driven electric motors. The occupational radiation doses arising from US naval reactors to crew of nuclear vessels are negligible with 0.06 mSv/year and person. None of the crew has ever exceeded 20 mSv/year. The average occupational exposure of each person monitored at US Naval Reactors’ facilities since 1958 is 1.03 mSv/year [27]. This is significantly lower than the natural radiation dose received in the United States of 6.3 mSv. The natural radiation dose in the Andes is about six times higher. Table 7 shows the annual estimated average effective dose equivalent received by a member of the population of the United States [28]. For a baseline, one can assume that 1 rem (10 mSv) received in a short period or over a long period is safe. No observable health effects will be expected. Ten rem (100 mSv) received in a short period or over a long period is still safe and no immediate observable health effects are expected, although chances of getting cancer might be very slightly increased.

1.20.4.8

Generation-IV Reactors

Except few FBs, most of the reactors in operation are thermal reactors, cooled and moderated by light water and/or heavy water. For the sake of keeping the atomic density of the hydrogen or deuterium moderator in acceptable level, water temperature must be

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kept below the critical point in the reactor core. In LWRs and HWRs, water temperature does not exceed 3401C and requires very high pressures to remain in liquid state. Consequently, the thermodynamic conversion efficiency of water moderated-cooled reactors is in lower 30% region. In conventional reactor, about 2/3 of the nuclear energy will be released as waste heat to the environment. Great efforts are being done worldwide in order to increase the conversion efficiency of nuclear reactors by using alternative coolants operating at higher temperatures. Reliable reactor coolants are sodium and its eutectics (Na–K), lead and its eutectics (Pb–Bi), gas (helium or CO2), and molten salts (fluorides). There is no ideal coolant, and choices are still open, as all these options are still being investigated in relation to the fast reactor concepts retained by the GEN-IV International Forum. Since 1960s, the technological development of the sodium-cooled fast reactors made great progress, as addressed in Section 1.20.4.5. For the other three, the coolants (Pb, He, molten salts), there is still a long way to go to reach industrial level. Higher reactor safety, as well as making use of thorium resources is subject of the GEN-IV reactors. The mainline research activities are focused on:

• • • • •

lead-cooled fast reactors gas-cooled fast reactors molten salt-cooled fast reactors GT-MHR PBMR

1.20.4.8.1

Lead-cooled fast reactors

Lead is an attractive coolant candidate for fast GEN-IV reactors and ADS. LFRs operate in a fast-neutron spectrum and use a closed fuel cycle for efficient conversion of fertile uranium. Lead does not react with air, water or CO2. Hence, no vigorous exothermic reactions are expected. Lead has a high boiling temperature and hence allows reaching high temperatures at atmospheric pressure. Boiling or flashing in case of pressure reduction is eliminated. In case of the destruction of the reactor core, corium will float and the chain reaction will stop. The concept of lead–bismuth-cooled fast reactor has experienced long-time development in the USSR in relation to the naval propulsion. The coolant used was metallic lead or a lead/bismuth eutectic with very low absorption of fast neutrons. Lead-cooled fast reactors are envisioned for electricity, hydrogen production, and high level radioactive material transmutation. However, corrosion of structural materials in lead at high temperatures remains one of the main concerns.

1.20.4.8.2

Gas-cooled fast reactors

The gas-cooled fast reactor is a fast spectrum helium-cooled reactor operating with closed direct cycle. TRISO pellets are used in cylindrical fuel compacts to be inserted in fuel rods, depicted in Fig. 11. Typical core exit temperature is approx. 8501C. High exit temperatures allow using helium gas turbine to deliver electricity with high efficiency and also process heat for hydrogen production through iodine–sulfur cycle.

1.20.4.8.3

Molten salt-cooled fast reactors

Molten salt is an excellent coolant for the temperature range of 700 to 10001C. At those temperatures, superheated steam at high temperature–pressure can be produced leading to high thermodynamic conversion efficiency, as well as process heat for hydrogen production. With respect to heat exchanger size, molten salt is superior to other coolants, followed by water and sodium. Helium requires considerably greater heat size and consumes electricity for pumping power at high pressures and velocities. Several variants of MSR concepts have been investigated, and a few prototypes have been built. Most of the MSR concepts currently understudy are based on a fuel dissolved in a fluorinated salt. The coolant most considered is a mixture of lithium fluoride (LiF) and beryllium fluoride (BeF2), called FLIBE, where highly depleted lithium is used. This concept couples the reactor with an online reprocessing plant for continuous extraction of fission products and allows breeding plutonium from 238U in the uranium or 233U from thorium.

1.20.4.8.4

Gas turbine modular helium reactor

Helium is also an important coolant for HTRs. It is a chemically inert gas with practically no neutron absorption. Coolant temperature is limited only by the temperature dependent strength of the structures. The reactor can directly be coupled to a helium gas turbine operating at Brayton cycle. The most known helium-cooled reactor projects are the GT-MHR and the PBMR. Both designs use TRISO type fuel are graphite moderated thermal reactors. After the disintegration of the Soviet Union and end of the cold war, there was a tendency by nuclear weapon states to convert the megatons to megawatts and so to introduce the plutonium accumulated in the nuclear arsenals into economy. Within that framework, a high temperature nuclear fission power reactor design of GT-MHR type has been initiated as an international project between Russia (OKBM Afrikantov, Kurchatov Institute, VNIINM), United States (General Atomics), France (Framatome), and Japan (Fuji Electric) to burn the Weapon Grade (WG) plutonium. GT-MHR is a helium gas cooled, graphite moderated reactor in cylindrical geometry with a radius of 4 m and a height of 10 m with axial reflectors at top and bottom of 1 m. The reactor core is build of hexagonal graphite blocks. The core consists of internal and external reflectors in radial direction with three or four concentric rings in between. Each hexagonal block contains 108 helium coolant channels and 216 fuel pins, which makes a modular reactor. Each fuel pin contains fuel compacts with TRISO fuel particles dispersed into a graphite matrix, shown in Fig. 11. Helium gas is heated to approx. 9001C bypassing

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through the core. These high outlet helium temperatures allow to be coupled directly to a gas turbine for Brayton cycle, which increases the reactor efficiency up to 48%. Excellent neutronic economy and conversion ratio of the graphite moderated reactor make GT-MHR also suitable to implement thorium as breeder material which has also been analysed by S¸ahin et al. and addressed in Section 1.20.7.1. Detailed information can also been found in the General Atomics reports [29,30].

1.20.4.8.5

Pebble bed modular reactor

PBMR is a pebble bed reactor in a most advanced technological development stage within the framework of GEN-IV reactors (after the liquid metal cooled reactors), which are already operational and employed. The reactor design has been adopted by the South African company of PBMR (Pty) Ltd. from the German HTR, and has been under development since 1994. The main differences between the German HTR and PBMR are in the fuel quality and in power. PBMR uses LEU fuel with approx. 9% enrichment, whereas the former is fueled with high enriched uranium (LEU) of approx. 90% enrichment. The German HTR has produced 300 MWel reactor power, whereas the PBMR is designed for a modest power of 160 MWel as a small modular reactor (SMR). The PBMR is fueled with spherical graphite fuel elements of 6-cm diameter with imbedded TRISO fuel particles, shown in Fig. 11. PBMR has increased inherent safety associated with the TRISO fuel type, as demonstrated in former tests [31]. Fig. 20 shows the working schema of the PBMR [32,33]. Fresh fuel elements are loaded at the top of the core and spent fuel elements are removed at the bottom by continuous plant operation. Steam generator is located inside the reactor vault. Helium inlet/outlet temperatures are 450/9001C. Steam temperature is 5401C. Net cycle efficiency is 41%–42%. By 400 MWth, and the output to the Grid is 160 to 165 MWel at 281C cooling water temperature (CWT) and 165 to 170 MWel at 181C CWT. As a SMR, PBMR is the best trade-off between least-investment cost, climate change mitigation, diversity of supply, localization, regional development, and decentralized energy provision.

1.20.4.8.6

Very high temperature reactor

Very high temperature reactor (VHTR) is a graphite moderated helium-cooled reactor, like GT-MHR and PBMR, but the coolant temperature is significantly increased to 10001C and beyond. These high temperatures enable very high electric efficiency greater than 50% and open the door for industrial process heat production, especially for hydrogen production. In fact, primary nuclear application for the VHTR is the hydrogen production. VHTR uses TRISO fuel particles with small kernels of about 0.9 mm diameter in form of UO2. The enrichment grade depends on the core design purpose. The VHTR design has been evolved from well-established gas-cooled reactor experiences. The reactor core can be either a hexahedron prismatic like the GT-MHR or PBMR and Chinese HTR-10 [34]. For electricity production, direct cycle is the preferred version. For process heat applications in refineries, hydrogen production, and petrochemistry, the indirect cycle is considered with an intermediate heat exchanger.

New fuel pebbles Cooling gas

Heated fluid to turbine

Cold fluid from turbine

Pump

Reinforced concrete Fig. 20 Working schema of the pebble bed nuclear reactor.

Spent fuel pebbles

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1.20.4.8.7

Fixed bed nuclear reactor

The FBNR is being developed under the International Atomic Energy Agency (IAEA) Coordinated Research Project (CRP) to meet the requirements for The International Project on Innovative Nuclear Reactors and Fuel Cycles (INPRO) program on small reactors without on-site refueling [35]. The FBNR is an SMR operating at a capacity of 70 MWel and based on the conventional PWR technology, but uses GEN-IV type spherical fuel elements, where TRISO particles are imbedded in a graphite matrix. Fig. 21 shows the basic structure of the FBNR [35]. It has a capability to operate without refueling and reshuffling of fuel for a reasonably long-period in order to ensure energy security of the country that uses it, without fresh and spent fuel being stored at the site outside the reactor during its service life. It is also proliferation resistant against unauthorized access to fuel elements during the whole period of its presence at the site and transportation, because the spent fuel elements are confined in the fuel chamber where it can be sealed by IAEA for inspection in the end of fuel cycle. The fuel chamber needs to be transported from factory to the site and return, when the refueling is necessary to be done and under IAEA inspection. Therefore, the reactor has the characteristics of high level proliferation resistance. The spherical fuel elements are fixed in the suspended core by the flow of water coolant under 160 bar pressure in the reactor operation process in upwards direction. The pebbles become fluidized in the fuel chamber and leave the chamber when the velocity reaches approx. 1.4 m/s and go to the core, where they stay in a fixed position, while the flow velocity is approx. 7 m/s [35]. In the case of any malfunction, the power is cut-off and all the fuel elements immediately fall down into the fuel chamber through the gravity, where they are passively cooled. FBNR has the characteristics of being simple in design, modular, inherent safety, passive cooling, proliferation resistant, and reduced environmental impact. The FBNR is adequate for developing countries with small electric grids and limited investment capabilities, as well as with the weakness of manpower for development of nuclear power plants. FBNR can operate both with conventional nuclear fuel 235U, as well as with 233U and make use of the worldwide abundant thorium [35–38]. Utilization potential of alternative fuels, such as thorium, reactor-grade plutonium (RG-Pu), and MA, enables FBNR to have a high level of sustainability [36–38]. In summary, FBNR reveals excellent nuclear characteristics, operates with the conventional PWR technology, uses GEN-IV reactor fuel, and has outstanding safety features and high level proliferation resistance. It can build a bridge between the conventional nuclear technology and GEN-IV reactors and accelerate their commercial deployment.

1.20.4.9

Space Nuclear Reactors

The electricity production in a spacecraft must be conducted under very unconventional conditions. It is of paramount importance that a space power supply system must be small, compact, and lightweight in order to reduce the costs not only for fabrication but also for transportation into the Earth’s orbit. For large-scale projects of longer missions of period (more than few months) and

Steam to generator

Feed water

Integrated steam generator

Fine control rod and core level limiter

Water goes to the pump

Reserve fuel chamber Flange (sealed by IAEA)

Exhaust steam

Fuel chamber passively cooled

Remote controlled accumulator valves

Grid to block fuel Water from the pump Fig. 21 Basic structure of fixed bed nuclear reactor (FBNR) with main modules. IAEA, International Atomic Energy Agency.

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higher power requirement (greater than 10 kWel), nuclear reactors are the sole energy source. High power level production is essential for extended commercial exploitation and industrialization of space. Nuclear energy enables or significantly enhances space power and propulsion. Nuclear power and nuclear propulsion will be independent of proximity to the Sun or solar illumination. Constant power level will be available for thrusting and braking. Thermal radiation is the only way of transferring the waste heat of a power generator into space. Hence, the radiator surface is inversely proportional to the fourth order of the waste heat temperature. Typical waste heat temperatures in a thermoelectric device are around 500–700K (corresponding to the cold junction temperature), whereas they are in the range of 1000K (level of collector temperature) in space thermionic reactors. It is obvious that these high waste heat temperatures lead to a drastic reduction of the radiator mass. As maintenance in space will practically not be possible or extremely costly for very limited cases, a high reliability of the device is required throughout the entire mission period. For that reason, static systems have significant advantages over dynamical ones, for the problems associated with moving parts will be eliminated, such as lubrication, sealing, kinematical disturbances on the spacecraft, and maintenance in general. At present, there are two alternative ways for nuclear electricity production at high levels in a spacecraft: 1. thermoelectric energy conversion, and 2. thermionic energy conversion.

1.20.4.9.1

Thermoelectric reactors

Thermoelectric energy conversion is applied in earlier space vehicle for small-scale energy requirement from few to few hundred Watts; a radioisotope has provided the heat energy source for long range missions to Mars and beyond, where solar energy decreases with the square of the distance from the Sun. The thermoelectric conversion efficiency is very low in the range of few percent. Waste heat is removed with thermal radiators or fins. Fig. 22 shows a typical radioisotope thermoelectric generator, serving as a general purpose heat source (GPHS) [39]. Fig. 23 depicts multitudes of space missions done in the past with radioisotope thermoelectric generators [39]. For higher energy needs, thermoelectric reactors are required. The first nuclear reactor was launched into space in 1965 by the United States. It was a thermal thermoelectric reactor and was called SNAP10A with a thermal power of 38 kWth and nominal

Thermal insulation (Min-K)

Cooling tubes (A1 6063) Heat source liner (Haynes-25)

Eight GPHS module stack Thermoelectric modules (Pb Te/TAGS)

Heat distribution block (graphite)

Housing (A1 2219)

Fin (A1 6063)

Mounting interface

Thermal insulation (Min-K and Microtherm) Fig. 22 A multi-mission radioisotope thermoelectric generator. GPHS, general purpose heat source; TAGS, Te-Ag-Ge-Sb (tellurium, silver, germanium, antimony). Reproduced from S¸ahin S. A general review of space nuclear reactors. In: 7th International conference on recent advances in space technologies, 16–19 June, Istanbul, Turkey; 2015.

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Voyager 2 (1977) Neptune

Radioisotope missions

Uranus Ulysses (1990) Voyager 1 (1977)

Saturn Apollo 11 (1969) Apollo/ALSEP (5) (1969–1972)

Cassini (1997)

Moon

Pioneer 11 (1973)

Jupiter

Transit 4A (1961)

LES 9 (1976)

Mars

Galileo (1989) Pioneer 10 (1972)

Transit 4B LES 8 Viking 1&2 (1975) (1961) (1976) Mars pathfinder (1996) Transit Transit 5BN-1 Transit Nimbus III Triad-01-1x (1963) 5BN-2 (1972 (1969) (1963) Distances & planets are not to scale Fig. 23 Space radioisotope missions. Reproduced from S¸ahin S. A general review of space nuclear reactors. In: 7th International conference on recent advances in space technologies, 16–19 June, Istanbul, Turkey; 2015. hVpCcAKHR7zAhoQ_AUIBigB&biw=1280&bih=869#imgrc= 3tg1H93p2VvudM.

electric power of approx. 500 W. After an operation of 43 days, an onboard voltage regulator within the spacecraft failed due to malfunctioning of the heat rejection system, causing the reactor core to be shut down. Although the failure was not caused by nuclear system, the US space nuclear program has stagnated for some time. Around the turn of the 20th/21st century, the United States has restarted a rigorous, ambitious project for the development of a space thermoelectric nuclear reactor at the 100 kWel range within the SP-100 program. However, the US space reactor efforts are mainly concentrated on fast reactors for space applications, which requires significantly harder technology compared to thermal reactors.

1.20.4.9.2

Thermionic reactors

Thermionic reactors can achieve higher conversion efficiencies and operate at higher temperatures (approx. 2000K) than a thermoelectric reactor (approx. 1000K). Hence, a thermionic nuclear reactor system will be more compact and also have a more compact waste heat radiator for the same electrical output. Radiator is the bulkiest component in a space reactor system. For that reason, thermionic space nuclear reactors have been considered since the 1960s for space mission studies, which require high electrical power, although their development is tougher and needs more advanced technology than in case of thermoelectric space reactors. In the former Soviet Union and now in Russian Federation, space nuclear technology efforts are concentrated on moderated thermal reactors, which require a significantly benign technology than the fast reactor. Russia made significant progress and launched more than 35 nuclear reactors into space, mainly for low orbit intelligence purposes within the TOPAZ space reactor power system. TOPAZ reactor core is composed of 79 thermionic fuel elements (TFEs) with five serial connected thermionic cells each. The system has a total length of 4.7 m with major diameter of 1.3 m. The reactor cooling is done with the eutectic alkali metal NaK-78 coolant at approx. 970K via an electromagnetic pump to avoid kinematic disturbances. In the YENISEI or TOPAZ-II reactor generation, 37 single-cell TFEs are embedded in a single monolithic block of ZrH1.8 moderator. The reactor cooling is done with liquid alkali metal. Thirty-four TFEs are dedicated to the electrical load for board electricity and three TFEs are providing high-current, low-voltage DC power to the electromagnetic induction pump.

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Fig. 24 Hollow vermicelli carbide fuel configuration. Reproduced from S¸ahin S, Kennel EB. Hybrid thermionic space reactors for power and propulsion. Nucl Technol 1994;107/2:155–81. Available from: http://www.ans.org/pubs/journals/nt/a_34985.

For nuclear thermal propulsion, Russia has also developed vermicelli type carbide fuel, where hydrogen passes through the fuel to be heated to propulsion temperatures, see Fig. 24 [40]. The United States is now also pursuing to develop a fast thermionic space reactor, parallel to a fast thermoelectric reactor. For power levels exceeding 100 kWel, one single reactor can be considered to provide both electrical power and propulsion. An integrated nuclear electric power, nuclear thermal propulsion, and nuclear electric propulsion system could not only lead to a substantial cost and mass saving, but also has the potential to benefit several space missions, which require high power, high orbit, high mass, and propulsion capabilities in orbit. A typical US design of a fast hybrid reactor for space power and nuclear thermal propulsion was investigated within the framework of a research project, sponsored by the Ballistic Missile Defense Office and managed by the US Army Space and Strategic Defense Command under Contract number DASG60-93-C-0099 [40]. In that reactor, liquid hydrogen propellant from a cryogenic H2 tank is first preheated around the rocket nozzle, where the latter is cooled through this measure. Preheated hydrogen at approx. 1000K is pressed with about 10 MPa to the reactor core from the bottom and will be heated to approx. 2000K bypassing through the vermicelli fuel compact, adopted from Russian type, depicted in Fig. 24. The emitter covering the fuel compact is also heated to same temperature starts simultaneously with electron emission and direct current will be produced. A fast space reactor needs highly enriched fuel (approx. 93%), and hence the criticality loss due to burnup is minor; less than 1% over 7 years in power mode. Total propulsion time is typically few hours and is limited with the capacity of the propellant tank. The specific impulse Isp is approx. 1000 s and thrust can vary from few kilonewton to meganewton, depending on the size of the reactor. Very high rocket velocities can be reached through an electric thruster over long mission periods. Please note that the heavy Cs or Hg ions can be accelerated to very high temperatures; the specific impulse Isp can vary between 2000 and 10,000 s, and is hence significantly higher than that of the nuclear thermal thrusters. However, the thrust values are significantly lower (1–1000 N), because of much lower ion propellant mass of an electric thruster. The United States is developing carbide foam fuel for that purpose. Figs. 25 and 26 show the honeycomb foam structure of carbide ceramic fuel for space propulsion and the respective fuel element [2]. The foam fuel will possess good thermal conductivity, huge surface area, and enhanced gas permeability. It is also relatively inexpensive to fabricate (no machining) and is scalable. Ultramet produces foam structures up to 1800 in diameter and 4800 long or large batches of components that occupy the same volume. The potential clearly exists to increase reactor size and/or assemble numerous reactors for simultaneous operation [41,42]. Different examples of honeycomb foam ceramic fuels for space reactors for thermal propulsion and are presented at international conferences [43,44].

1.20.5

Environmental Aspects and Radiation Safety

Nuclear reactors are one of the cleanest energy producers. In fact, they release neither COx nor NOx gases into the atmosphere. They can be built at the immediate vicinity of urban areas, such as the Philippsburg Nuclear Power Plant, Germany, shown in Fig. 17,

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Fig. 25 Honeycomb foam structure of carbide ceramic fuel for space propulsion. Reproduced from S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011. Wikipedia. Nuclear reactor fuel. Available from: EwjilYqq5eTTAhVpCcAKHR7zAhoQ_AUIBigBamp;biw=1280amp;bih=869#imgrc=3tg1H93p2VvudM.

Fig. 26 Fuel element in foam structure for space propulsion. Reproduced from S¸ahin S. General overview on nuclear energy and renewable aspects. In: The international renewable energy congress (IREC 2011), December 20–22, 2011, Hammamet, Tunisia; 2011. EwjilYqq5eTTAhVpCcAKHR7zAhoQ_AUIBigBamp;biw=1280amp;bih=869#imgrc=3tg1H93p2VvudM.

the Doel and Tihange nuclear power plants, Belgium, shown in Fig. 27, or the Pickering Nuclear Power Station on Lake Ontario, Canada, shown in Fig. 28 [45,46]. Nuclear power plants occupy smallest land area per unit energy production. Table 8 compares the occupation area of different power plants to produce 1000 MWel, clearly showing that the nuclear plant uses the smallest area, and hence, cause the least perturbations in the landscape. We note that any change in the nature is to be considered as environmental pollution. Radioactivity arises as the main concern for the construction of new nuclear power plants. In reality, the radioactivity release of a nuclear reactor is extremely minor. A nuclear reactor is built with multiple-levels of radiation barriers, shown in Fig. 29 [47]. The sintered fuel pellets in Fig. 5 are the first radiation barrier. All radioactive elements are kept inside the fuel itself. The cladding of the fuel rods makes the second level and contains the radioactive materials. Intact fuel rods can contain the spent fuel and other radioactive fission product for more than 10,000 years safely. The reactor vessel is the third radiation barrier, provides

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Fig. 27 Doel and Tihange nuclear power plants, Belgium. Reproduced from TRACTEBEL. Doel and Tihange nuclear power plants. Available from: http://www.tractebel-engie.com/references/doel-and-tihange-nuclear-power-plants-2/.

Fig. 28 The Pickering Nuclear Power Station on Lake Ontario, Canada. Reproduced from Canadian Consulting Engineer. It’s a deal: SNC-Lavalin buys AECL’s CANDU business, magazine for professional engineers in construction. Available from: http://www.canadianconsultingengineer.com/ energy/its-a-deal-snc-lavalin-buys-aecls-candu-business/1000499717/.

physical and fire protection to fuel elements. The concrete biological shielding shown in Figs. 18 and 29 provides radiation protection and constitutes the fourth barrier. The containment building is covered inside with an airtight steel wall, which makes the fifth radiation barrier.

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Table 8

Occupation area of power plants to produce 1000 MWel

Hydro Solar Wind Biomass Nuclear

1000 km2 50 km2 150 km2 6000 km2 4 km2

Sixth barrier reinforced concrete shell Fifth barrier containment

Second barrier fuel rod cladding tube

First barrier crystal fuel lattice

Fuel rod Fourth barrier concrete shielding

Third barrier pressure boundary

Fig. 29 Multiple-levels of radiation barriers of a nuclear reactor. Reproduced from Thuma G. Basic safety concerns in nuclear engineering. In: 3rd International disaster and risk conference, Davos, Switzerland; 2010.

Finally the reinforced steel–concrete containment building is the last (fifth) radiation barrier and provides protection against missiles, airplane crash, flooding, and other external effects. The air in the containment building is continuously pumped and released through a stuck of about 150 m of height into the atmosphere, carefully controlled with a multitude of detectors, which can be seen in Figs. 17 and 27. According to the regulations imposed by the US Nuclear Regulatory Commission (US-NRC), the radiation level of the air pumped through the stuck must be less than 0.05 mSv/year. The cooling water of condenser must also have extremely low radioactivity, which is less than 0.01 mSv/year. According to IAEA reports, the radioactivity resulting of all peaceful nuclear activities starting from uranium mining until spent fuel disposal per capita of world population makes approx. 1 promil of the natural radiation [48]. With the newly developed TRISO fuel for GEN-IV reactors, the radiation safety level of nuclear reactors becomes extremely high. TRISO capsule is a miniature pressure vessel and it can withstand to pressures for up to 1000 atm. The radioactive material containment capacity of TRISO fuel can be measured in millions of years, shown in Fig. 30 [16]. TRISO can provide safe accommodation of highly radioactive fission products and fissionable elements without being damaged nor destroyed over millions of years (about 4 million years). During this period, the long living actinide isotopes will either be transformed inside the capsule to stable isotopes or uranium. The latter is a natural element. Nuclear waste materials produced by nuclear power plants can be classified as MAs, fission products, and structural materials. MAs are the most hazardous radioactive waste products because of their long-term, high level radioactivity, measured in geological

Nuclear Energy

TRISO high-strength silicon carbide/carbon layers, and graphite blocks are virtually insoluble in water and could contain residual waste radioactivity for M-years

Decay times for nuclear waste components

Pu-238

U-234

Pu-239

825

U-235

Pu-240 Cm-244

Metal-clad spent fuel expected to fail in this time

U-236

Pu-242

U-238

Stable isotopes Am-243

Am/Pu-241 Np-237

100

Radioactive daughter products

U-235

Pu-239

Natural uranium Isotopes

Np-237

1000

104

105

106

Years

107

SPENT TRISO expected to contain waste radioactivity to this time

Fig. 30 Permanent immobilization of residual radioactivity for deep burn tristructural-isotropic (TRISO) spent fuel after irradiation. Reproduced from NGNP Alliance Blog. TRISO fuel news. Available from: http://blog.ngnpalliance.org/triso-fuel-news/; 2013.

time frames. Fission products range on the second range with respect to radio activity, but die out relatively rapid in few centuries or millennia. Neutron induced radioactivity in the structures comes in the third range. The amount of high level radioactive waste of world nuclear power plants is approx. 500 m3/year. Whereas high level toxic and highly carcinogenic industrial waste amount is approx. 10,000,000 m3/year. Other industrial waste is approx. 1,000,000,000 m3/year [2].

1.20.5.1

Nuclear Radiation Release of Coal Power Plants

It is a striking and widely ignored fact that the nuclear radiation emission of coal power plants is approx. 100 times higher than those of the nuclear power plants [49]. The former is totally ignored and disregarded by public. This is also confirmed by National Council on Radiation Protection (NCRP) Reports No. 92 [50] and No. 95 [51]. Accordingly, the population exposure from the operation of 1000 MWel nuclear and coal-fired power plants amounts to 490 person-rem/year for coal plants and 4.8 person-rem/ year for nuclear plants. Thus, the population effective dose equivalent from coal plants is 100 times that from nuclear plants. For the complete nuclear fuel cycle, from mining to reactor operation to waste disposal, the radiation dose is cited as 136 person-rem/year. Fig. 31 shows the coal combustion in the United States and worldwide in millions of tons with a release of billions of tons of CO2 directly into the atmosphere in addition to hundreds of millions of tons of ash [50]. Let us remember that the combustion of 12 kg C produces 44 kg CO2. World coal resources contain radioactive uranium between 0.1 and 10 ppm, depending on the site with an average value of 1.3 ppm. Thorium content in coal is even higher being a lighter element and is 3.4 ppm in average. Both elements are radioactive, though at low level, but not negligible. Fig. 32 depicts the release of uranium and thorium in the United States and world coal plants since 1937, extrapolated up to year 2060. This makes a total of cumulative releases for the 100 years of coal combustion following 1937, predicable to: US release (from combustion of 111,716 million tons of coal):

• •

Uranium: 145,230 t (containing 1031 t of 235U), sufficient to provide initial fuel charge for about 1000 nuclear power plants of 1000 MWel each. Thorium: 357,491 t. Worldwide release (from combustion of 637,409 million tons of coal):

• •

Uranium: 828,632 t (containing 5883 t of 235U), sufficient to provide initial fuel charge for about 6000 nuclear power plants of 1000 MWel each. Thorium: 2,039,709 t (comparable to world thorium reserves known).

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US and world coal combustion (millions of tons) 1937 10,000

1960

1980

2000

9000

2020

2040

2060

World coal production

8000 7000 6000 5000 4000

US coal production

3000 2000 1000 0

US and world combustion of coal (in millions of metric tons) has increased steadily from 1937 to the present. It is expected to increase even more between now and beyond 2040 Fig. 31 Coal combustion in the United States and worldwide. Reproduced from National Council on Radiation Protection. Public radiation exposure from nuclear power generation in the U.S. Report no. 92; 1987. p. 72–112.

1.20.6

Process Heat and Nuclear Hydrogen Production

Reactors operating at high temperatures can open new windows for industrial applications through bypassing a thermodynamically cycle for electricity production. In latter case, most of the energy must be released as waste energy to environment causing significant thermal pollution. Nuclear process heat has application potential on a wide spectrum, ranging from seawater desalination at relatively low temperatures to the production of divers hydrocarbons compounds and hydrogen by around 9001C up to 12001C gasification of coal and direct reduction with blast furnace. Fig. 33 reflects the temperature windows for miscellaneous application possibilities of nuclear process heat between 200 and 16001C. Hydrogen is an important clean energy carrier. The output is pure water or steam. At present, the US hydrogen production is approx. 12 million tons H2/year, of which about 95% is produced from natural gas (methane) through steam-methane reformation, which is the primary hydrogen source, where approx. 80 million tons CO2/year is released into the atmosphere according to Eq. (13) [52,53]: CH4 þ 2H2 O þ energy-4H2 þ CO2

ð13Þ

If heat energy is supplied from CH4, more CO2 will be released. Presently, the United States annual hydrogen consumption growth rate is approx. 10%. A well-functioning hydrogen economy will need much more than that. Hydrogen need for transportation is 200 million tons H2/year, corresponding to approx. 900 GWth/year, and that for nonelectric applications is greater than 400 million tons H2/year. It is obvious that much hydrogen production with current conversion methods will increase the global warming considerably, and also cause serious international conflicts. Nuclear hydrogen production remains the unique way for worldwide hydrogen economy in great scale.

•

Direct thermolysis of water would give a clean way of hydrogen production, but the process requires extremely high temperatures. H2 O-H2 þ ½O2

•

At this temperature, only 10% of the water is decomposed.

ð25001C minÞ

ð14Þ

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US and world release of uranium and thorium 1937 30,000

1960

1980

2000

2020

2040

2060

World thorium release

25,000

20,000

15,000

World uranium release

10,000 US thorium release

5000

US uranium release

0

US and world release of uranium and thorium (in metric tons) from coal combustion has risen steadily since 1937. It is projected to continue to increase through 2040 and beyond. Fig. 32 Release of uranium and thorium in the United States and world coal plants.

200

400

600

800

1000

1200

1400

1600

Glass manufacture Cement manufacture Iron manufacture Direct reduction with blast furnace Electricity generation (gas turbine) Gasification of coal Hydrogen (IS process) Hydrogen (steam reforming) Ethylene (naphtha, ethane) Styrene (ethylbenzene) Town gas Petroleum refineries Desulfurization of heavy oil Wood pulp manufacture Desalination, district heating HTR, - VHTR

800

LMFBR LWR

500

--

1200

-- 700

320

Fig. 33 Temperature windows for application possibilities of nuclear process heat. HTR, high temperature reactor; LMFBR, liquid metal fast breeder reactor; LWR, light water reactor; VHTR, very high temperature reactor.

Te

828

•

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An elegant clean way of hydrogen production would be possible through thermochemical water-splitting at temperatures of about 850–9001C in three steps: H2 SO4

→ SO2 þ H2 O þ ½O2

ð8501CÞ

ð15Þ

I2 þ SO2 þ 2H2 O

→ 2HI þ H2 SO4

ð1201CÞ

ð16Þ

2HI

→ I2 þ H2

ð4501CÞ

ð17Þ

þ ______________________________________________ H2 O→H2 þ ½O2

ð18Þ

The sum of all chemical reactions in the Eqs. (15)–(17) gives the Eq. (18). The net inputs in the entire process are pure water and heat energy, and the net outputs are hydrogen and oxygen gases. Sulfur (S) and iodine (I) play the role of catalysts. They ae not consumed. Hence this process is called (I–S) process. Fig. 34 depicts the schematic of the “I–S” process for hydrogen production [52,53]. In this process, iodine and sulfur play the role of chemical catalysts and will not be consumed. The input is process heat and water, the output is hydrogen and oxygen. The required temperatures for this process are about 850–9001C, technologically achievable with HTRs. Very high temperature can produce heat in the temperature range of 1000 to 12001C, suitable for a multitude of industrial applications, as shown in Fig. 33. However, primary nuclear application for the VHTR is foreseen for the hydrogen production. Fig. 35 shows the schematic of a VHTR system connected with a hydrogen production plant, adopted from [23,27]. A 600 MWth VHTR, dedicated to hydrogen production can yield 2  106 NM3/day [47], where otherwise about 1000 t CO2/day would be released via methane forming. A general view of a water/thermochemical hydrogen production system coupled with a nuclear reactor is shown in Fig. 36. Again, the entry has two components, process heat energy and water, where H2 and O2 make the net output. The catalysts remain in the closed loop.

•

Electrolysis is the classical way for hydrogen production. Electrolysis at room temperature, called cold electrolysis is applied close to the invention of the electricity.

At higher electrolyte temperatures, the need for electrical energy decreases. The heat energy content of H2 is 120 MJ/kg. Fig. 37 depicts the overall energy requirement for high temperature electrolysis by neglecting all losses and assuming a hypothetical efficiency of 100%. Total energy needs remain the same [52,53]. However, electrical energy is much more precious than thermal energy. Note that about three units of thermal energy are spent to produce one unit of electrical energy. Hence, high temperature electrolysis is beneficial with respect to energy balance. Fig. 38 shows the temperature dependent efficiencies for hydrogen production through electrolysis and electricity production [52,53]. Higher operation temperatures increase both the electrical efficiency, as well as the hydrogen production efficiency. Higher temperature affects both efficiencies positively in the same direction. This makes the VHTR operation at temperatures higher than 9001C very attractive for hydrogen production.

Hydrogen

Oxygen Nuclear heat 1O 2 2

H2 400°C H2 + I2

I2

H2SO4

Rejected heat 100°C

2HI

I (iodine) circulation

900°C

2HI I2

+

H2SO4

+ H2O + SO2+H2O H2O

1 2 O2 + SO2 + H2O

S (sulfur) circulation SO2 + H2O

Water Fig. 34 Schematic of the I–S process for hydrogen production. Reproduced from S¸ahin S. Hydrogen production from nuclear energy. In: International hydrogen energy congress and exhibition, Istanbul, Turkey; 2005; S¸ahin S. Nuclear based hydrogen production, coupled with incineration of nuclear waste transuranium products. In: International conference on hydrogen production 2012 (ICH2P-2012), Renaissance Seoul Hotel, Seoul, Republic of Korea; 2012.

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Control rods

Graphite reactor core

Pump

Graphite reflector

Water

Blower Oxygen Heat exchanger

Reactor

Heat sink Hydrogen

Helium coolant

Hydrogen production plant

Fig. 35 A very high temperature reactor system for hydrogen production. Reproduced from Tsoulfanidis N, editor. Nuclear energy: selected entries from the encyclopedia of sustainability science and technology. New York: Springer; 2013.

Intermediate He loop O2 Reactor Hydrogen facility 900°C

850°C

Hydrogen Water Heat exchangers Fig. 36 A nuclear reactor with a water/thermochemical hydrogen production system.

830

Nuclear Energy

120

Energy input (MJ/kg H2)

100 80 Thermal energy input 60

Electrical energy input

40 20 0 100

300

500 Temperature (°C)

700

900

Fig. 37 Overall energy requirement for high temperature electrolysis.

55

Efficiency (%)

50

45

40 Electrical generation efficiency Hydrogen production efficiency 35 500

600

700

800

900

Reactor outlet temperature (°C) Fig. 38 Efficiencies of electricity and hydrogen production by high temperature electrolysis.

1.20.7 1.20.7.1

Sustainability of Nuclear Energy Sustainability of Fission Energy

The sustainability of the nuclear fuel cycle and the burning of RG-Pu and other MAs in the spent nuclear waste of the present day nuclear reactors are key issues in the future of nuclear energy [28]. Over the decades, civilian nuclear power plants have produced nearly 1700 t of RG-Pu, of which about 274 t have been separated and the rest is stored at reactor sites embedded in spent fuel [54,55]. Also, the nuclear weapons nations have accumulated an estimated 250 t of weapons-grade plutonium, most of it in the United States and Russia [54,55]. It is clear that precautions to keep plutonium under strong security and to reduce their amounts have paramount importance for public with respect to the proliferation concerns, as well as their very high radio toxicity. Reutilization of nuclear waste actinides and implementation of 238U and thorium into the energy vector will extend the availability of nuclear fuel resources over 10 thousand years will provide high grade of sustainability to fission energy. The superior neutron economy of heavy water moderated CANDU reactors and graphite moderated HTRs have instigated different workers to investigate the potential of utilization of the RG-Pu and MA stockpiles as alternative fuels to produce additional energy from those nuclear wastes. Fig. 39 shows all possible nuclear transformation processes occurred to actinides in nuclear reactors under consideration of all radioactive decay and neutron interactions, where main thorium, uranium, and plutonium isotopes are double-framed due to their importance. CANDU reactor technology is very well developed and operational worldwide in different countries. A series of generic work have studied the suitability WG-Pu, RG-Pu, and MA as alternative fuels in conventional CANDU reactors with the help of the SNSCALE code package in 1-D geometry [56–60]. Recent criticality and fuel burnup calculations have been conducted with the

Nuclear Energy

235U

(n,)

245Cm 9.3×103 y

237U 6.75 days

(n,)

236U

831

(n,) 244Cm

(,) 233U 1.62×105 y

(n,) (n,2n)

17.6 y 242Cm

27 days

(n,)

(n,)

242mAm

243Am 7400 y

152 y

237Np

239U 23.5 min

(n,)

2.14×106 y

(n,) (%35)

–

(n,)

–

– (%84)

241Am 239Np

232Th

163 days 

– 233Pa

(n,2n)  –

238U

234U

2.35 days



(n,) (%65)

1.45×1010 y

–

238Pu 86.4 y

243Pu 4.956 h

433 y

(n,)

238Np 2.1 days

–

242Am

β–

(n,)

16 h EC (%16)

(n,2n)

(n,) (n,)

239Pu

2.44×104

y

(n,2n)

240Pu

(n,)

241Pu

(n,)

6850 y

(n,2n)

144 y

(n,2n)

242Pu 3.76×105 y

Fig. 39 Nuclear transformation processes of actinides in nuclear reactors.

Fig. 40 Monte Carlo N-Particle eXtended (MCNPX) modeling of the CANada Deuterium-Uranium Reactor (CANDU) reactor (vertical section). Reproduced from S¸ahin S, S¸arer B, Çelik Y. Utilization of nuclear waste plutonium and thorium mixed fuel in CANDU reactors. Int J Energy Res 2016;40/14:1901–7.

Monte Carlo computer code package Monte Carlo N-Particle eXtended (MCNPX)/CINDER in 3-D, separately, showing each fuel bundle and moderator/coolant region, as well as the radial reflector for an authentic modeling of the reactor geometry (see Fig. 40) [61]. The loading machine will be coupled on both axial sides for online fuel charge-discharge operation. Hence, axial reflector is omitted here.

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80 1.6 70

4

3 1.5

60 3

1.4 keff

50

2

2

40

1

1.3

30

Burnup (GW.d/t)

4

1.2 20 1 1.1

10 0

1.0 0

500

1000

1500

2000

2500

3000

3500

Operation time (day) Fig. 41 The reactor critically keff and the fuel burnup of a CANada Deuterium-Uranium Reactor (CANDU) reactor over plant operation fueled with RG-Pu/Th mixed fuel. Mode 1: 95%232 ThO2 þ 5% RG Mode 3: 85%232 ThO2 þ 15% RG

PuO2 PuO2

Mode 2: 90%232 ThO2 þ 10% RG Mode 4: 80%232 ThO2 þ 20% RG

PuO2 PuO2

RG-Pu has revealed high performance with high initial reactor criticality. This allowed using thorium/plutonium mixed oxide as reactor fuel. Fig. 41 depicts variation of the reactor critically keff and the fuel burnup over full power reactor operation period, evaluated under consideration of all nuclear reactions, depicted in Fig. 39. Even a small fraction of 5% plutonium mixed with 95% thorium reveals better performance than the original natural uranium CANDU fuel with respect to operation periods (approx. 3 years vs. 7–9 months) and burnup (approx. 25 GWd/t vs. approx. 7 GWd/t), which is close to the burnup level in LWRs. Higher plutonium fraction in the mixed fuel increases both the plant operation time, as well as the burnup level rapidly. It should be noted at that point to use stainless steel cladding for the fuel rods for higher burnups rather than zircaloy cladding for stability! A reasonable option among the investigated cases will be a mixed fuel consisting of 10% plutonium mixed with 90% thorium. This allows reaching burnups near to 55 GWd/t, much higher than those attainable in conventional LWRs and full power plant operation for approx. 7 years with the same fuel charge. Introduction of nuclear waste into energy production means sustainability and renewability of nuclear energy. Nuclear waste mass per unit total energy production is reduced drastically for final disposal, which relieves the repository needs considerably. Thorium can be included in the energy scenario, increasing the nuclear fuel resources considerably. The actinides are subject to various transformation processes. Fig. 42 shows the variation of the plutonium isotopes and the buildup of 233U. The main driving fission fuel 239Pu burns up rapidly. The buildup of 233U cannot compensate the reduction in 239 Pu; however, contributes to the extension of the reactor operation period. At end-of-life (EOL), the even no-fissile plutonium isotopes overweight, not any more suitable for thermal reactors. The final spent can further be used either in the blankets of fast reactors or stored to wait the technology development of fusion–fission hybrids and in ADS for utilization. The technology development and deployment of GEN-IV reactors in the energy sector have paramount importance for the sustainability and renewability of nuclear energy. Within this category, the South African PBMRs are in the most advanced stage. It can incinerate both RG-Pu and MA due to its unique and unsurpassed safety features [28,62]. Recently, Adem et al. have investigated the utilization of RG-Pu, WG-Pu, MA for PBMR [63,64]. Alternative fuels are mixed with natural uranium as breeder material criticality calculations with Monte Carlo computer codes MCNP/MONTEBURNS led to an initial reactor multiplication factor, keff ¼ 1.2395 for the original fuel, which has 9.6% enriched uranium, as benchmark. Similar keff values could be attained with 30% RG-PuO2 þ 70% nat-UO2, 24% WG-PuO2 þ 76% nat-UO2 and 37% MAO2 þ 63% nat-UO2 mixed oxide fuels. Reactor operation periods with these mixed fuel charges are evaluated as 3.2, 5.5, and 6.5 years with burnups of 99,000, 166,000, and 190,000 MWd/t, respectively (see Fig. 43). Again, in PBMR, the 239Pu acts as the driving fuel. The plant operation times and burnup levels with alternative fuels are significantly higher than those with 9.6% enriched uranium, although they all start with the same initial reactor criticality by keff ¼ approx. 1.25 due to more efficient conversion of the even U and Pu isotopes to the fissile odd Pu isotopes. Calculations using MAs as the driver fuel in a PBMR have also given similar long plant operation times and high fuel burnups [63,64]. Other investigators performed similar studies investigating the potential of RG-Pu and MA as nuclear fuel in PBMR, and followed the transmutation chain of plutonium isotopes and some other actinides [31]. Fig. 44 shows the nuclide density

Nuclear Energy

833

0.6

Fissile isotopes density (gr/cm3)

233U 239Pu 240Pu

0.4

241Pu 242Pu

0.2

0.0 0

500

1000

1500

2000

2500

Operation time (day) Fig. 42 Density variations of the main fissile and fissionable isotopes for the mixed fuel of 10% RG-PuO2 þ 90% ThO2.

2

300 275

1.75 250

200 1.25

2

175

keff

keff= 1.08

150

1 3

125 0.75 1

100

Fuel burnup grade (GW.d/MT)

225

1.5

75

0.5

50 0.25 25 0 0

550

1100

1650

2200

2750

0 3300

Operation time (days) Fig. 43 Temporal variation of the reactor criticality, keff, and the fuel burnup grade of a PBMR with ➀30% RG-PuO2 þ 70% nat-UO2; ➁24% WG-PuO2 þ 76% nat-UO2; ➂37% MAO2 þ 63% nat-UO2.

evolution of the RG-PuO1.7 fuel during irradiation. The fissile odd isotopes, 239Pu and 241Pu, are totally burnt out. The rest consists mainly of no-fissile even plutonium isotopes. Investigations of a (Y, Zr, MA)O2 fuel with the composition of ((ZrO2)0.84(YO1.5)0.16)0.90(MAO2)0.10 has also given similar results, depicted in Fig. 45.

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0.014

Pu-238 Pu-239 Pu-240 Pu-241 Pu-242

0.012

Nuclide density (b/cm)

0.01

0.008

0.006

0.004

0.002

0

0

100

200

300

400

500

600

700

Burnup (MW.d/kg HM) Fig. 44 Nuclide density evolution of the PuO1.7 fuel during irradiation. Reproduced from Jonnet J, Kloosterman JL, Boer B. Performance of TRISO particles fueled with plutonium and minor actinides in a PBMR-400 core design. Nucl Eng Des 2010;240:1320–31.

0.0014

Np-237 Pu-238 Pu-239 Pu-240 Pu-241 Pu-242 Am-241 Am-243

Nuclide density (b/cm)

0.0012

0.001

0.0008

0.0006

0.0004

0.0002 0 0

100

200

300

400

500

600

Burnup (MW.d/kg HM)

Fig. 45 Nuclide density evolution of the (Y, Zr, MA)O2 fuel during irradiation. Reproduced from Jonnet J, Kloosterman JL, Boer B. Performance of TRISO particles fueled with plutonium and minor actinides in a PBMR-400 core design. Nucl Eng Des 2010;240:1320–31.

A recent work has studied the possibility of fueling a GT-MHR of General Atomics design with RG-Pu in order to assess the sustainability potential of this reactor [65]. A fuel compact containing ¾ of TRISO particles with RG-PuO2 as fuel and ¼ of them with ¼ ThO2 (or ¼ nat-UO2) as breeder material has attained the same initial reactor criticality of keff ¼ 1.27 as the GA-design fueled with LEU of 9.6% 235U. With RG-Pu fuel, however, the full power plant operation periods of approx. 10 years are considerably longer and the fuel burnup grades of about 170 GW.d/t are higher than those of the LEU fuel [65], Fig. 46. Calculations conducted with the same MCNP calculations by exactly the same 3-D geometrical modeling with 9.6% enriched LEU had resulted in approx. 500 days of plant operation and about 60 GW.d/t burnup [66]. Higher performance of RG-Pu is a direct result of the continuous production of 233U, 239Pu, 241Pu, Americium isotopes and other actinides, which extend the plant operation periods and the fuel burnup [66]. Whereas, 235U is continuously depleted in case of LEU and the generation of 239Pu proceeds slow.

Nuclear Energy

1.3

835

200

1.25

keff

1.2

100

1.15

1.1 k-eff (Th)

Burnup value (GW.d/t)

150

50

k-eff (NU) 1.05

Burnup (Th) Burnup (NU) 0

1 0

500

1000

1500

2500

2000

3000

Operation time (days) Fig. 46 The variation of the reactor critically, keff, and the fuel burnup of a gas turbine modular helium reactor (GT-MHR) reactor over the plant operation fueled with reactor-grade plutonium (RG-Pu) and Thor nat-U as breeder material. Reproduced from S¸ahin S, Erol Ö, S¸ahin HM. Investigation of a gas turbine-modular helium reactor using reactor grade plutonium with 232Th and 238U. Prog Nucl Energy 2016;89:110–9.

240Pu

2500

(nat-U)

(Th)

239Pu

amount (kg)

239Pu

2000

(nat-U)

5000 239Pu

(Th)

1500 232Th

4000

(Th) 238U

(nat-U)

232Th, 238U, 240Pu

240Pu

amount (kg)

6000

1000 3000 0

500

1000

1500

2000

2500

3000

Operation time (days) Fig. 47 Depletion of the major isotopes in a gas turbine modular helium reactor (GT-MHR).

The transmutation history of actinides in a GT-MHR can be followed in Figs. 47–48(A) and (B). One can observe a continuous depletion of the main fissile isotope 239Pu and the initial breeders, 232Th and 238U, while other fissile isotopes, 233U, 235U, 241Pu and MAs building up and extend the reactor operation time with the same fuel charge [65]. Fig. 49(A) and (B) depicts the development history of MAs in the mixed fuel with thorium and natural uranium as breeder material [65].

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300

900 850

241-Pu, 242-Pu amount (kg)

241-Pu 750

200

241-Am

700 150

238-Pu

650

100

600 550 243-Am

242-Pu

238-Pu, 241-Am, 243-Am amount (kg)

250 800

50

500 0

450 0

500

1000

1500

2500

2000

3000

Operation time (days)

(A)

300

900 241-Pu 850

241-Pu, 242-Pu amount (kg)

750

200

241-Am

700 150 650

238-Pu 100

600 550

243-Am

238-Pu, 241-Am, 243-Am amount (kg)

250 800

50

242-Pu 500

0

450 0

500

(B)

1000

1500

2000

2500

3000

Operation time (days)

Fig. 48 (A) Temporal variation of intermediate level actinides in a gas turbine modular helium reactor (GT-MHR) with thorium breeder. (B) Temporal variation of intermediate level actinides in a GT-MHR with nat-U breeder.

Similar studies have been conducted for the utilization of RG-Pu and MAs in FBNR concept have also shown high performance [36,37]. Utilization potential of the nuclear reactor waste in conventional CANDU or in the GEN-IV and other reactors makes the fission nuclear energy quasi-sustainable.

1.20.7.2

Sustainability of Fusion Energy

The development of fusion energy is envisaged on (D,T)-, (D,D)-, and (D,3He)-reactors. While D is a natural element, T and 3He are artificial. Alone the deuterium in the sea water can cover world energy needs for billions of years. T is produced by neutron

Nuclear Energy

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100 10 234-U 8

60 6

245-Cm 233-U

40

4 235-U 244-Cm 20

Other isotope amounts (kg)

233-U, 244-Cm amount (kg)

80

2 237-Np 0

0 0

500

1000

1500

2000

2500

3000

Operation time (days)

(A)

100 10 235-U 80

245-Cm

60

6

40

244-Cm 4 234-U

236-U

20

Other isotope amounts (kg)

244-Cm amount (kg)

8

2

237-Np 0

0 0

500

1000

1500

2000

2500

3000

Operation time (days)

(B)

Fig. 49 (A) Temporal variation of minor actinides in a gas turbine modular helium reactor (GT-MHR) with thorium breeder. (B) Temporal variation of minor actinides in a GT-MHR with Nat-Uranium breeder.

capture in lithium through the following reactions: 6 3 Li 7 3 Li

þ n-31 T þ 42 He þ 4:8 MeV

ð19Þ

þ nð2:5MeV Þ-31 T þ 42 He þ n

ð20Þ

Lithium in the seawater can cover world tritium needs for about 3.4 millions of years. In that sense, fusion energy is fully sustainable. 3He is a rare element in Earth. However, 3He in the solar wind is accumulated on the Moon’s surface over billions

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Nuclear Energy

of years. Measurements on the Moon dust surface probes indicate a 3He content of 109 kg in the upper 50 cm [67–69]. The atmospheres of Jupiter and Saturn contain 1022 kg 3He, and those of Uranus and Neptune 1020 kg 3He. Solar system provides full sustainability with respect to fusion energy, subject to the deployment of fusion reactors [12].

1.20.7.3

Sustainability of Fission Energy via Fusion

The sustainability and renewability of nuclear energy are closely connected with fissionability of the nuclear waste actinides and the breeding of new nuclear fuel from the nuclear waste actinide isotopes, which requires a neutron rich environment. (D,T) Fusion process produces one high energetic 14 MeV-neutron per 17.6 MeV energy release, whereas the fission process produces only 2.5–3 neutrons per 200 MeV energy. Hence, the former is significantly richer in neutrons. All non-fissile higher actinides at thermal neutron energies become fissionable under high energetic neutron irradiations. A fusion–fission (hybrid) reactor (HR) can produce up to 30 times more fissile fuel than a FBR per unit of energy. Comparison of the breeding ratio (BR) of a hybrid reactor with suppressed fission and a FBR per unit energy (E) leads to [70–73]:
BR 1
1:8 1
BRE 1 HR ¼
1:227 1 ¼ 30 E

ð21Þ

200

FBR

This becomes obvious when the fusion neutron spectrum in Fig. 50 [74] is compared with the fission reaction cross-sections of U (threshold by 0.8 MeV) and 232Th (noticeable threshold by 1.4 MeV) in Figs. 51 and 52 [75,76], respectively. High energetic 14 MeV fusion neutrons can initiate multiple fission reactions in these fertile isotopes with high neutron yield at high energies, which themselves Initiate secondary fission reactions in cascades. Table 9 depicts the fissile fuel breeding limits and fission energy production in infinite medium by one single incident 14 MeV neutron [74], which gives a clear indication for the high energy multiplication potential of fusion–fission (hybrid) reactors. Consider that each fissile fuel isotopes contains approx. 200 MeV itself, leading to the multiplication of the fusion energy by two orders of magnitude. This provides high level of sustainability to nuclear energy through the introduction of the abundant and passive 232Th and 238U resources into the energy vector, extending the fissile fuel availability to about 20,000 years. The fission cross-sections of the major nuclear waste 240Pu and other higher actinides are depicted in Fig. 53 [77] and Fig. 54 [78]. Their threshold fission energies lay lower than those of 232Th and 238U, down to less than 0.1 MeV. They also have higher fission cross-sections in MeV energy region, even higher than that of the principal fission fuel 235U. This opens prospects of renewability to nuclear energy in combination of fusion and fission. The most hazardous nuclear waste can be included into the energy scenario for additional energy production along with their transmutation and burning processes, where nuclear waste amount per unit energy will be reduced drastically. CANDU reactors operate with natural uranium and can make use of a very small fraction of uranium with burnup levels of only as low as 7000 MW.d/t and produce substantial amount of RG-Pu as nuclear waste. The 235U level of 0.71% in natural uranium falls to approx. 0.4%. Earlier work has investigated the performance of CANDU spent fuel in a (D,T) hybrid reactor design concept [79]. 238

Alpha particles

D−D neutrons D−T neutrons

0

2

4

6

8

10

12

14

16

18

Energy, E (MeV) Fig. 50 Neutron spectrum of fusion neutrons (Plasma temperature 70 keV). Reproduced from S¸ahin S. Physics of the fusion-fission (hybrid) reactors. In: 8th International summer college on physics and contemporary needs, Islamabad, Pakistan; 1983.

Nuclear Energy

Cross section (b)

10–1 2.0

1

10

2.0

1.5

1.5

1.0

1.0

0.5

0.5

10–1

1

839

10

Incident energy (MeV) Fig. 51 Fission cross-sections of ENDF request 42438; 2011.

238

U less than 40 MeV. Reproduced from Evaluated Neutron Data Libraries, Brookhaven National Laboratory.

1

10–1

10

Cross section (b)

1

1

10–1

10–1

10–2

10–2

10–3

10–3

10–4

10–4

10–5 10–1

10–5 1

10

Incident energy (MeV) Fig. 52 Fission cross-sections of ENDF request 42432; 2011.

232

Th less than 40 MeV. Reproduced from Evaluated Neutron Data Libraries, Brookhaven National Laboratory.

Table 9

Infinite medium results per incident 14 MeV neutron

Medium 238

U Natural uranium 232 Th 6 Li 7 Li Natural lithium (7.56% 6Li)

Product 239

4.18 Pu 5.0 239Pu 2.49 233U 1.08 T 0.89 T 1.90 T

Energy release (MeV) 199 300 50.5 16.5 12.3 16.3

Source: Reproduced from S¸ahin S. Physics of the fusion-fission (hybrid) reactors. In: 8th International summer college on physics and contemporary needs, Islamabad, Pakistan; 1983.

Fig. 55 shows the basic conceptual design of (D,T)-neutrons driven hybrid reactor blanket. A 14.1-MeV fusion neutron flux of 1014 neutron/(cm2 s) with an energy flux of 2.25 MW/m2 produced in the fusion chamber on the left side passing the stainless steel enter into the fuel zone, where the CANDU spent fuel rods arranged in hexagonal geometry. The blanket contains a tritium breeding zone (Li2O) and a graphite neutron reflector on right side [79].

840

Nuclear Energy

1

Cross section (b)

1

10–1

10–1

10–2

10–2 10–1

10

1 Incident energy (MeV)

Fig. 53 Fission cross-sections of ENDF request 42481; 2011.

240

Pu less than 40 MeV. Reproduced from Evaluated Neutron Data Libraries, Brookhaven National Laboratory.

Fission cross-section (b)

3

244Cm

240Pu

2 237Np

243Am

1

241Am

0 0.1

0.5

1

5

Incident neutron energy (MeV) Fig. 54 Fission cross-sections of higher actinides. Reproduced from Colonna N, Belloni F, Berthoumieux E, et al. Advanced nuclear energy systems and the need of accurate nuclear data: the n_TOF project at CERN. Energy Environ Sci 2010;3/12:1910–7. doi:10.1039/C0EE00108B.

High energetic fusion neutrons initiate multiple fission reactions in the hybrid reactor blanket and produce substantial fission energy, coupled with the transmutation and burning of nuclear waste actinides, which in turn significantly multiplies the fusion energy. Fission reactions produce a great number of high energetic fission neutrons, which in turn partially convert no-fissile even actinides to odd fissile fuel. In fact, fissile fuel breeding overrides the fission fuel burn process. Fig. 56 shows the cumulative fissile fuel enrichment (CFFE) grade in the CANDU spent fuel for a reactor operation period of 24 months, which is the sum of all essential fissile elements (235U, 239Pu, and 241Pu) in the fuel rods in percent [79]. The fuel enrichment proceeds slower toward the external rods due to exponentially fall of the neutron flux in the subcritical blanket. One can observe that in less than 1 year, the fuel quality becomes superior to the fresh natural uranium throughout the blanket. After about 2 years, fuel becomes utilizable in an advanced light-water-cooled, heavy water moderated CANDU reactor. The fuel quality continues to increase linearly for longer reactor operation.

Nuclear Energy

r= 18.7 cm

841

15 cm ne Fuel zo

1.3 cm

Stainless steel

Neutron source

Li2O

1

2

3

4

5

6

7

8

9

10

Row number Fig. 55 CANada Deuterium-Uranium Reactor (CANDU) spent fuel rods in a (D,T) hybrid reactor blanket.

2.0

CFFE (%)

1.5 I

II

Subzones III IV

V

1.0 0.71 0.5

0 0

2

4

6

8

10

12

14

16

18

20

22

24

Plant operation period (months) Fig. 56 Enrichment history of CANada Deuterium-Uranium Reactor (CANDU) spent fuel in a fusion–fission (hybrid) reactor blanket. CFFE, cumulative fissile fuel enrichment. Reproduced from S¸ahin S, Yapıcı H. Investigation of the neutronic potential of moderated and fast (D,T) hybrid blankets for rejuvenation of CANDU spent fuel. Fusion Technol 1989;16:331–45.

The increase of the nuclear fuel quality under fusion neutrons irradiation of the spent fuel has been observed also in a (D,D) catalyzed fusion–fission (hybrid) reactor blanket. In this design concept, CANDU spent fuel rods are placed in the three internal rows and the LWR spent fuel rods in the rows four to 10 beyond the first wall of the fusion chamber, Fig. 57 [80]. LWR spent fuel contains more 235U (approx. 2.17%) and plutonium than the CANDU spent fuel with only about 0.4%235U. Higher fissile element content of the LWR spent fuel compensates to some degree the exponential decrease of the fission power density in the fuel zone. The latter is surrounded by tritium breeding zones (Li2O) and graphite (C) neutron reflectors. The sandwich structure of the Li2O and graphite multi-zones helps to moderate the escaping fast neutrons from the first Li2O zone in graphite to be caught in the following scavenger Li2O zones for more efficient tritium breeding. Fig. 58 shows the rejuvenation history of CANDU and LWR spent fuel in a hybrid reactor blanket over 48 months. The CANDU LWR spent fuel rods in front of the LWR rods provides quasi-uniform fission power density in radial direction. Therefore, fuel regeneration occurs more or less balanced in the respective CANDU and LWR spent fuel rods, compared to Fig. 55. In 48 months, CANDU spent fuel gains LWR fresh fuel charge quality and LWR spent fuel becomes suitable to charge HTRs. A recent study has investigated Laser Inertial Confinement Fusion Energy (LIFE) engine [81]. It is a spherical reactor. The fusion chamber is surrounded by an ODS first wall made of ODS (2 cm) and followed by a Li17Pb83 zone (10 cm), acting as neutron multiplier, tritium breeding and front coolant zone, which is separated by an ODS layer (2 cm) from the main molten salt coolant FLIBE and fission zone. TRISO particles, containing RG-Pu as fissile carbide fuel, PuC, are suspended with increasing volume fractions from 2% to 6% in the molten salt coolant. All fission products remain encapsulated TRISO particles, which prevents the radioactive contamination

Nuclear Energy

Line neutron source

842

(D,T) 14.1 MeV

300

SS-304

1.3

14.1

12

4

5 Li2O

Fuel

16

C

14.1

Fuel zone

1 2 3 4

6 7 8 9 10 Row number

rd ri h

ri rd h

CANDU LWR 0.608 0.465 0.654 0.425 1.768 1.253

Fig. 57 Conceptual design a fusion–fission hybrid reactor for spent fuel rejuvenation. Reproduced from S¸ahin S, Baltacıogˇlu E, Yapıcı H. Potential of a catalyzed fusion driven hybrid reactor for the regeneration of CANDU spent fuel. Fusion Technol 1991;20:26–39.

of the coolant. Burnup level and time calculations were conducted for a constant fusion power of 500 MWth. High energetic fusion neutrons can burn all plutonium isotopes with high efficiency with gigantic burnup levels, as depicted in Fig. 59 [81], which is never attainable even with GEN-IV fission reactors. Fusion reactors can open the path of renewability to fission energy through the nuclear power production with nuclear waste actinides. Fig. 60 shows the time evolution of plutonium isotopes. Main plutonium isotope 239Pu is burnt up rapidly. 240Pu builds up gradually in the 3 years, but it begins to decline thereafter. Higher plutonium isotopes, specifically 241Pu and 242Pu, accumulate slightly over long time. 238Pu content remains insignificant throughout the plant operation. Fig. 61 shows the temporal variation of the trans plutonium isotopes, such as Americium and Curium isotopes [81]. One can observe a continuous build up of higher actinides through successive neutron capture reactions, except 241Am. The main source of the latter is the successive b decay of 241Pu, which begins to decrease slowly by approx. the seventh year. As a direct reflection, the generation of 241Am cannot compensate the burnup after approx. 7 years. The odd Americium isotopes, 241Am, 243Am and even the Curium isotope, 244Cm, are excellent fission fuels for fast reactors, fusion–fission hybrids and ADSs [81]. 242mAm and 245Cm are new type of fission fuels with superior nuclear properties with thermal fission cross-sections of sf ¼ 6600 barn and 2020 b, respectively. The critical masses of 242mAm and 245Cm in thermal assemblies are at least one order of magnitude lower than required for 239Pu [82,83]. The critical mass of 245Cm is approx. 3.5 times less than that of 239Pu in fast assemblies [84]. 242mAm and 245Cm are excellent fuel candidates for super-compact spacecraft nuclear reactors [83–86]. ADS with hard neutron spectrum show similar performance as fusion hybrids for burning and transmutation of actinide nuclear waste [87]. The reutilization possibility of nuclear waste makes nuclear energy renewable.

Nuclear Energy

843

8

7

10

Row 6

4

Row

CFFE (%)

5

1

Row

4 LWR

3

Row

3

2

CANDU

1

0 0

6

12

18

24

30

36

42

48

Operation period (month) Fig. 58 Rejuvenation of CANada Deuterium-Uranium Reactor (CANDU) and light water reactor (LWR) spent fuel in a hybrid reactor blanket. CFFE, cumulative fissile fuel enrichment. Reproduced from S¸ahin S, Baltacıogˇlu E, Yapıcı H. Potential of a catalyzed fusion driven hybrid reactor for the regeneration of CANDU spent fuel. Fusion Technol 1991;20:26–39.

600

Fuel burnup grade (GW.d/MT)

500

3 4 5

400

2

300 1

200

100

0 0

2

4

6

8

10

Operation time (years) Fig. 59 Burnup level of RG-PuC in the blanket of a laser fusion driven hybrid blanket ➀%2 PuC þ %98 FLIBE; ➁%3 PuC þ %97 FLIBE; ➂%4 PuC þ %96 FLIBE; ➃%5 PuC þ %95 FLIBE; ➄%6 PuC þ %94 FLIBE. FLIBE, Li2BeF4. Reproduced from S¸ahin S, S¸ahin HM, Acır A. Life hybrid reactor as reactor grade plutonium burner. Energy Convers Manag Nov. 2012;63:44–50.

1.20.8

Future Prospects of Nuclear Energy

The role of nuclear energy in energy sector will continue increasingly in the 21st century and thereafter. Presently, they produce substantial electrical energy with water moderated reactors. LWRs will be the dominating the nuclear reactor in the 21st century. However, they can make use of only a small fraction of the uranium resources (1%). Thorium and 99% of uranium resources

844

Nuclear Energy

Fissile isotopes density (g/cm3)

0.25

0.2 239Pu

0.15

240Pu

0.1

241Pu

242Pu

0.05

238Pu

0 0

2

4

6

8

10

Operation time (years) Fig. 60 Time evolution of Pu isotopes (6 RG-PuC þ %94 FLIBE). FLIBE, Li2BeF4. Reproduced from S¸ahin S, S¸ahin HM, Acır A. Life hybrid reactor as reactor grade plutonium burner. Energy Convers Manag Nov. 2012;63:44–50.

Fissile isotopes density (g/cm3)

0.008

0.006 243Am

241Am

0.004

244Cm 245Cm

0.002

242mAm

0 0

2

4 6 Operation time (years)

8

10

Fig. 61 Time evolution of Americium and Curium isotopes (6 RG-PuC þ %94 FLIBE). FLIBE, Li2BeF4. Reproduced from S¸ahin S, S¸ahin HM, Acır A. Life hybrid reactor as reactor grade plutonium burner. Energy Convers Manag Nov. 2012;63:44–50.

cannot be used. Hence, intensive research and development activities have been initiated by 10 nations within the program of GEN-IV reactors in order to extend the exploitation of the entire nuclear resources, shown in Fig. 62. Soon thereafter GEN-IV reactor activities have been started in many other countries, such as China, India, Russia, Turkey, etc. Today progress on GEN-IV reactor development in China and India has reached even more advanced stages than those in most of the initiating countries, shown in Fig. 62. With the introduction of thorium and 238U isotope, the availability of fissile fuel will be extended to more than 10,000 years. Another important feature of the GEN-IV reactor will be to make it possible to use the accumulated nuclear waste actinides of LWR and CANDU reactors as nuclear fuel. This will relax the final nuclear waste disposal to a great degree. There is an increasing tendency to replace internal combustion vehicles with electric cars. Norway has made an important decision to ban internal combustion vehicles. With this decision, it plans to disseminate environmentally friendly solutions such

Nuclear Energy

845

Ten nations preparing today for tomorrow’s energy needs

Argentina

Brazil

Canada

France

Japan

Korea

South Africa

Switzerland

United Kingdom

United States

Fig. 62 The initiating nations of generation-IV (GEN-IV) reactor program.

as electric cars. The Norwegian political parties have largely agreed on the draft bill on the ban on the use of internal combustion vehicles in the country after 2025. Currently, 30% of the country is using electric and hybrid cars [88]. The proposed law to prohibit the sale of cars with internal combustion engines after 2030 was passed by Germany’s legislative body, the Bundesrat. Legislative bodies in Germany are advised to prohibit the use of engines that use internal combustion engines after 2030 in roads of the European Union that will fall as a nightmare to the automobile industry. Germany is also pressuring the EU to reduce taxes on nonemissions vehicles [89]. France considers banning the sale of combustion engine vehicles by 2040 [90]. Similar tendencies are observed by other EU states. One can expect a boom in electrical vehicles toward the end of the next decade. This will imply progress in high technology on one hand and increased demand on electrical energy, on the other hand. Fission nuclear reactors of GEN-III þ type are the sole clean energy producers for higher base load. They are not subject to daily or seasonal fluctuations, and are the most reliable energy suppliers. Hence, we expect a new renaissance of nuclear energy in the foreseeable future. Besides the terrestrial reactors, the research and development activities on space nuclear reactors will increase. Implementation of the space nuclear reactors on exploration and commercialization of solar planets and their satellites will be accelerated in the second half of the 21st century, based on direct conversion fission nuclear energy into electricity with higher and higher power requirements. Nuclear reactors will supply the energy needs in the space colonies on the Moon, Mars and the satellites of Jupiter and Saturn. Fusion is the ultimate energy of the universe, because all stars are in fact nuclear fusion reactors, where fusion reaction occurs through gravitational confinement. Controlled nuclear fusion is the hardest technological challenge, mankind is facing. At present, fusion reactor development is pursued on two promising mainlines based on (D,T) fuel: inertial confined fusion; and magnetic confined fusion. Muon catalyzed fusion at low temperatures is also a very attractive option. However, the production of one single muon by the collision of high energetic protons requires more than 6 GeV of energy. A muon can catalyze approx. 100 (D,T) fusion reaction, where in total 1.76 GeV energy will be released [91,92]. Hence, this option fails for energy production at the present level of high energy physics. Taming the fusion power requires development of hard technologies with the implication of large human and material resources. On the other hand, the reward is very high. One can easily forecast that the development of first generation (D,T) fusion

846

Nuclear Energy

power reactors will soon be followed by (D,D) fusion power reactors. Seawater contains enough deuterium to cover the world energy needs for billions of years. 3He in the solar system has the potential to cover the energy needs indefinitely, allowing building extremely clean fusion reactors with very minor neutron background. The development of fusion and space technologies will proceed contemporaneous. In a realistic vision, we can forecast 3He collecting industry on the surface of the Moon, Uranus and Neptune. As a last note, we can say that the higher our knowledge is the higher will be the benefit we can extract from the same matter. For example, water as kinetic energy carrier in hydro dams and windmills requires relatively modest knowledge and has been applied since the medieval age. Water as thermal energy carrier in coal, gas and conventional nuclear reactors needs knowledge at much higher levels and was only possible to generate in the industrial era. Water as fusion nuclear energy carrier requires supreme knowledge.

1.20.9

Conclusions

Increased life standard ambitions in technologically developed countries, and higher life standard expectancies in the developing countries require more and more energy. Furthermore, massive emigration tendencies in the underdeveloped countries toward more developed countries cause serious social tensions and human tragedies. The latter can be mitigated and even eliminated by increasing the life standards and employments in underdeveloped countries. Hence, the increase of energy production is indispensable for the promotion and stability of human civilization. Nuclear energy is the only known, clean, available, reliable, and stable energy source for that purpose. There is a great variety of nuclear reactor types. The most conventional ones are the light water or heavy water-cooled reactors. The technology is well understood and well established. However, the thermodynamic conversion efficiency of the water-cooled reactors are modest, namely in the range of only 30% to 35% due to the relatively low critical temperature of water by 3741C at 225 atm. About 2/3 of nuclear energy must be released to the environment as waste heat. At present, they operate on once-through basis and can only make use of approx. 1% of the uranium resource under consideration of plutonium recycle. In order to overcome these shortcomings, research on development of advanced nuclear reactors is pursued worldwide intensively. A variety of advanced reactor concepts are proposed within the framework of GEN-IV reactor. A group of them uses high temperature, low pressure coolants, such as molten salt or liquid metal, to generate superheated steam at high enthalpy. Other concepts use helium coolant at high temperature and pressure to couple directly to a gas turbine, bypassing the steam cycle. They are also predestined to generate high temperature process heat for hydrogen production. Common feature is operating at high temperatures for high conversion efficiencies of 50% and beyond. There is also a wide application area of mobile reactors. Floating reactors in submarines and aircraft carriers allow fully independent operation for years. They distill on-board freshwater from seawater. Space nuclear reactors can open new dimensions in the exploitation of the solar planets and moons for commercial purposes and allow wide-range space industry by providing high electrical power in space. Finally, nuclear reactors are the locomotive of high technology. They will play major roles in the formations of intellectual assets of mankind in this century and beyond.

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A general review of space nuclear reactors. In: 7th International conference on recent advances in space technologies, 16–19 June, Istanbul, Turkey; 2015. [40] S¸ahin S, Kennel EB. Hybrid thermionic space reactors for power and propulsion. Nucl Technol 1994;107/2:155–81. Available from: http://www.ans.org/pubs/journals/nt/ a_34985.. [41] Youchison DL, Lenard RX, Williams BE, Anghaie S. The development of a tricarbide foam fuel matrix for nuclear propulsion. In: Proceedings of the space nuclear conference, June 5–9, 2005, San Diego, CA; 2005. [42] Lenard RX, Youchison DL, Williams BE, Anghaie S. Conceptual mechanical and neutronic design of a tricarbide foam fuel matrix for nuclear thermal propulsion. In: Proceedings of the space nuclear conference, June 5–9, 2005, San Diego, CA; 2005. [43] Forsberg CW, Burchell TD, Williams DF, et al. Carbon–carbon-composite salt-cooled electric space reactors. In: Proceedings of the space nuclear conference, June 5–9, 2005, San Diego, CA; 2005. [44] Gouw R, Anghaie S. Nuclear design characteristics of ultrahigh temperature space reactors with thermal spectrum. In: Proceedings of the space nuclear conference, June 5–9, 2005, San Diego, CA, Paper 1196; 2005. [45] TRACTEBEL. Doel and Tihange nuclear power plants. Available from: http://www.tractebel-engie.com/references/doel-and-tihange-nuclear-power-plants-2/. [46] Canadian Consulting Engineer. It’s a deal: SNC-Lavalin buys AECL’s CANDU business, magazine for professional engineers in construction. Available from: http://www. canadianconsultingengineer.com/energy/its-a-deal-snc-lavalin-buys-aecls-candu-business/1000499717/. [47] Thuma G. Basic safety concerns in nuclear engineering. In: 3rd International disaster and risk conference, Davos, Switzerland; 2010. [48] Gonzalez AJ. Global levels of radiation exposure: latest international findings. IAEA Bull, 4#.; 1993. p. 49–51. Available from: https://www.iaea.org/sites/default/files/ 35402044951.pdf. [49] Gabbard A. Coal combustion: nuclear resource or danger? Emissions from burning coal include uranium and other nuclear materials-potential hazards and resources. Oak Ridge Nat Lab Rev 1993;26/3–4:18–25. [50] National Council on Radiation Protection. Public radiation exposure from nuclear power generation in the U.S. Report no. 92; 1987. p. 72–112. [51] National Council on Radiation Protection. Radiation exposure of the U.S. population from consumer products and miscellaneous sources. Report no. 95; 1987. p. 32–6, 62–4. [52] S¸ahin S. Hydrogen production from nuclear energy. In: International hydrogen energy congress and exhibition, Istanbul, Turkey; 2005. [53] S¸ahin S. Nuclear based hydrogen production, coupled with incineration of nuclear waste transuranium products. In: International conference on hydrogen production 2012 (ICH2P-2012), Renaissance Seoul Hotel, Seoul, Republic of Korea; 2012. [54] NEI Nuclear Notes. India unveils thorium reactor. Available from: http://neinuclearnotes.blogspot.com/2005/08/india-unveils-thorium-reactor.html; 2005. [55] DiRicco DJ. Thorium fuels safer reactor hopes. Available from: http://www.trendsimwatching.com/2005/07/thorium_fuels_s.html. Novastar Resources Ltd.; 2006. [56] S¸ahin S, S¸ahin HM, Alkan M, Yıldız K. An assessment of thorium and spent LWR-fuel utilization potential in CANDU reactors. Energy Convers Manag 2004;45/7-8:1067–85. [57] S¸ahin S, Yıldız K, S¸ahin HM, Acır A, S¸ahin N, Altınok T. Minor actinide burning in a CANDU thorium reactor. Kerntechnik 2006;71/5–6:247–57. [58] S¸ahin S, S¸ahin HM, Acır A. Utilization of TRISO fuel with reactor grade plutonium in CANDU reactors. Nuclear Eng Des 2010;240/8:2066–74. [59] S¸ahin S, Khan MJ, Ahmed R. CANDU reactors with reactor grade plutonium/thorium carbide fuel. Kerntechnik 2011;76/4:268–72. [60] S¸ahin S, Khan MJ, Ahmed R. Assessment of criticality and burnup behaviour of CANDU reactors with nuclear waste transuranium fuel. Prog Nucl Energy 2012;60:19–26. [61] S¸ahin S, S¸arer B, Çelik Y. Utilization of nuclear waste plutonium and thorium mixed fuel in CANDU reactors. Int J Energy Res 2016;40/14:1901–7. [62] Moses DL. Nuclear safeguards considerations for pebble bed reactors (PBRs). Nucl Eng Des 2012;251:216–21. [63] Acır A, Cos¸kun H. Neutronic analysis of the PBMR-400 full core using thorium fuel mixed with plutonium or minor actinides. Ann Nucl Energy 2012;48:45–50. [64] Acır A, Cos¸kun H. Monte Carlo calculations on transmutation of plutonium and minor actinides of pebble bed high temperature reactor. Prog Nucl Energy 2015;78:380–7. [65] S¸ahin S, Erol Ö, S¸ahin HM. Investigation of a gas turbine-modular helium reactor using reactor grade plutonium with 232Th and 238U. Prog Nucl Energy 2016;89:110–9. [66] S¸ahin HM, Erol Ö. Utilization of thorium in a gas turbine – modular helium reactor with alternative fuels. Energy Convers Manag 2012;53:224–9. [67] Wittenberg LJ, Santarius JF, Kulsinski GL. Lunar source of 3He for commercial fusion power. Fusion Technol 1986;10:167. [68] Epstein GL, Plescia JL, Garbis EA. Fusion Technology. In: Summary of the National Aeronautics and Space Administration Lunar He-3/Fusion Power Workshop, Cleveland, OH, April 25–26, 1988; 1989. p. 15, 67. [69] S¸ahin S. Potential of a catalyzed fusion driven hybrid reactor for the regeneration of CANDU spent fuel. Fusion Technol 1991;20:26–39. [70] Teller E. Fusion, volume 1: magnetic confinement. Part B. New York, NY: Academic Press; 1981. [71] S¸ahin S, Yapıcı H. Neutronic analysis of a thorium fusion breeder with enhanced protection against nuclear weapon proliferation. Ann Nucl Energy 1998;26/1:13–27.

848 [72] [73] [74] [75] [76] [77] [78] [79] [80] [81] [82] [83] [84] [85] [86] [87] [88] [89] [90] [91] [92]

Nuclear Energy S¸ahin S, Yapıcı H, Bayrak M. Spent mixed oxide fuel rejuvenation in fusion breeders. Fusion Eng Des 1999;47/1:9–23. S¸ahin S, Yapıcı H, S¸ahin N. Neutronic performance of proliferation hardened thorium fusion breeders. Fusion Eng Des 2001;54/1:63–77. S¸ahin S. Physics of the fusion-fission (hybrid) reactors. In: 8th International summer college on physics and contemporary needs, Islamabad, Pakistan; 1983. Evaluated Neutron Data Libraries, Brookhaven National Laboratory. ENDF request 42438; 2011. Evaluated Neutron Data Libraries, Brookhaven National Laboratory. ENDF request 42432; 2011. Evaluated Neutron Data Libraries, Brookhaven National Laboratory. ENDF request 42481; 2011. Colonna N, Belloni F, Berthoumieux E, et al. Advanced nuclear energy systems and the need of accurate nuclear data: the n_TOF project at CERN. Energy Environ Sci 2010;3/12.1910–7. doi:10.1039/C0EE00108B. S¸ahin S, Yapıcı H. Investigation of the neutronic potential of moderated and fast (D,T) hybrid blankets for rejuvenation of CANDU spent fuel. Fusion Technol 1989;16:331–45. S¸ahin S, Baltacıog˘lu E, Yapıcı H. Potential of a catalyzed fusion driven hybrid reactor for the regeneration of CANDU spent fuel. Fusion Technol 1991;20:26–39. S¸ahin S, S¸ahin HM, Acır A. Life hybrid reactor as reactor grade plutonium burner. Energy Convers Manag Nov. 2012;63:44–50. Clayton ED. Fissionability and criticality: from protactinium to Californium and beyond. Nucl Sci Eng 1973;52:417. S¸ahin S, Kumar A. Fast hybrid thermionic blankets with actinide waste fuel. Nucl Technol/Fusion 1984;5:374–81. S¸ahin S, Calinon R. Criticality of curium assemblies. Atomkernenergie/Kerntechnik 1985;46:45–9. S¸ahin S, Übeyli M. LWR spent fuel transmutation in a high power density fusion reactor. Ann Nucl Energy 2004;31/8:871–90. S¸ahin S, Khan MJ, Ahmed R. Fissile fuel breeding and actinide transmutation in the LIFE engine. Fusion Eng Des 2011;86/1–2:227–37. Maschek W, Chen X, Delage F, et al. Accelerator driven systems for transmutation: fuel development, design and safety. Prog Nucl Energy 2008;50:333–40. Staufenberg J. Norway to ’completely ban petrol powered cars by 2025. Available from: http://www.independent.co.uk/environment/climate-change/norway-to-ban-the-saleof-all-fossil-fuel-based-cars-by-2025-and-replace-with-electric-vehicles-a7065616.html; 2016. Böll S. Bundesländer wollen Benzin- und Dieselautos verbieten. Available from: http://www.spiegel.de/auto/aktuell/bundeslaender-wollen-benzin-und-dieselautos-ab-2030verbieten-a-1115671.html; 2016. Theguardian. France to ban sales of petrol and diesel cars by 2040. Available from: https://www.theguardian.com/business/2017/jul/06/france-ban-petrol-diesel-cars-2040emmanuel-macron-volvo; 2017. S. S¸ahin, A. Kumar, Preliminary conceptual design for muon catalyzed (D,T)-hybrid reactors. In: Transactions of the American Nuclear Society 1982 international conference, vol. 3, Washington, D.C; 1982. p. 215–216. S¸ahin S, Kumar A. Potential of Muon catalyzed cold fusion-fission (hybrid) reactors. In: 5th Miami international conference on alternative energy sources, Miami Beach, FL (December 3–15, 1982). Alternative energy sources V, part E. Amsterdam Elsevier Science Publishers; 1983. p. 59–94.

Further Reading Arya AP. Elementary modern physics. Reading, MA: Addison-Wesley; 1974. Beiser A. Concepts of modern physics. 5th ed. New York, NY: McGraw-Hill; 1995. Bejan A. Convection heat transfer. New York, NY: John Wiley & Sons; 1994. Cember H. Introduction to Health Physics. 3rd ed. New York, NY: McGraw-Hill; 1996. Chilton AB. Principles of radiation shielding. Paramus, NJ: Prentice Hall; 1983. Eisenbud M. Environmental radioactivity, from natural, industrial, and military sources. 4th ed. San Francisco, CA: Morgan Kaufman; 1997. EI-Wakil MM. Nuclear heat transport. La Grange Park, IL.: American Nuclear Society; 1981. EI-Wakil MM. Nuclear energy conversion. La Grange Park, IL: American Nuclear Society; 1982. Foderaro A. The elements of neutron interaction theory. Cambridge, MA.: MIT Press; 1971. Foster AR, Wright Jr. RL. Basic nuclear engineering. 4th ed. Paramus, NJ: Prentice Hall; 1982. Garwin RL, Charpak G. Megawatts and megatons: the future of nuclear power and nuclear weapons. Chicago, IL: University of Chicago Press; 2001. ISBN-13: 9780226284279; ISBN-10: 0226284271. Glasstone S, Sesonske A. Nuclear reactor engineering. 4th ed. New York, NY: Chapman & Hall; 1994. Hallenbeck WH. Radiation protection. Boca Raton, FL: Lewis Publishers; 1994. Lahey RT, Moody FJ. The thermal hydraulics of a boiling water nuclear reactor. 2nd ed. La Grange Park, IL: American Nuclear Society; 1993. Lamarsh JR. Introduction to nuclear reactor theory. Reading, MA.: Addison-Wesley; 1966. Oldenberg 0, Rasmussen NC. . Modern physics for engineers. Marietta, GA: Technical Books; 1992. Ozisik MN. Boundary value problems of heat conduction. New York, NY: Dover Publications; 1989. Todreas NE, Kazimi MS. Nuclear systems. Washington, D.C.: Hemisphere Publishing; 1989. Tong LS. Boiling heat transfer and two-phase flow. Bristol: Taylor & Francis; 1997. Wills JG. Nuclear power plant technology. Marietta, GA: Technical Books; 1992.

Reports Cameron IR. Nuclear fission reactors. New York, NY: Springer US; 1982. Crossland I, editor. Nuclear fuel cycle science and engineering. Oxford: Woodhead Publishing; 2012. Dahl PF. From nuclear transmutation to nuclear fission, 1932–1939. Boca Raton, FL: CRC Press; 2002. Duderstadt JJ, Hamilton LJ. Nuclear reactor analysis. Hoboken, NJ: Wiley; 1976. IAEA. The safety of nuclear power plants: strategy for the future. Vienna: IAEA; 1992. IAEA. Uranium: resources, production, and demand. Periodic reports of the OECD. Paris; Vienna: Nuclear Energy Agency; International Atomic Energy Agency; 1995. Krappe HJ, Pomorski K. Theory of nuclear fission: lecture notes in physics, vol. 838. Berlin; Haidelberg: Springer Verlag; 2012. Mahaffey JA. Nuclear power: nuclear fission reactors. New York, NY: Facts on File Inc.; 2011. OECD Nuclear Energy Agency. Achieving nuclear safety improvements in reactor safety design and operation. Paris: OECD; 1993. Sanctis ED, Monti S, Ripani M. Energy from nuclear fission: an introduction. Cham: Springer; 2016. Sesonske A. Nuclear power plant analysis. U.S. DOE report TID-26241, Oak Ridge; 1973. UNESDOC. Nuclear Energy and its fuel cycle: prospects to 2025. Paris: OECD, Nuclear Energy Agency; 1982. U.S. Atomic Energy Commission. Nuclear fuel supply. Report WASH-1242; 1973. Vandenbosch R, Huizenga JR. Nuclear fission. New York, NY: Academic Press Inc; 1973.

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Wagemans C, editor. The nuclear fission process Boca Raton, FL: CRC Press; 1991. White RS. Energy for the public: the case for increased nuclear fission energy. San Diego, CA: Tecolote Publications; 2006.

Relevant Websites http://www.ans.org/store/item-690054/ American Nuclear Society. https://www.britannica.com/science/nuclear-fission Britannica. http://www.nndc.bnl.gov/chart/ Brookhaven National Laboratory. http://www.nndc.bnl.gov/content/elements.html Brookhaven National Laboratory. https://www.iaea.org/ International Atomic Agency. https://www.boundless.com/physics/textbooks/boundless-physics-textbook/nuclear-physics-and-radioactivity-30/applications-of-nuclear-physics-192/nuclear-fission-in-reactors723-6317/ Lumen Learning. http://www.nuclear-power.net/nuclear-power/fission/ Nuclear Power. https://rsicc.ornl.gov/rsic.html Oakridge National Laboratory. http://www.science.uwaterloo.ca/Bcchieh/cact/nuctek/fissionreactor.html University of Waterloo. https://en.wikipedia.org/wiki/Megatons_to_Megawatts_Program Wikipedia – Megatons to Megawatts Program. https://en.wikipedia.org/wiki/Nuclear_fission Wikipedia – Nuclear fission. http://www.world-nuclear.org/information-library/nuclear-fuel-cycle/introduction/physics-of-nuclear-energy.aspx World Nuclear Association.

1.21 Food and Energy İlhami Yıldız and Craig MacEachern, Dalhousie University, Halifax, NS, Canada r 2018 Elsevier Inc. All rights reserved.

1.21.1 1.21.2 1.21.2.1 1.21.2.2 1.21.2.3 1.21.2.3.1 1.21.2.4 1.21.2.4.1 1.21.2.4.2 1.21.2.4.3 1.21.2.4.4 1.21.3 1.21.3.1 1.21.4 1.21.4.1 1.21.4.1.1 1.21.4.1.1.1 1.21.4.1.1.2 1.21.4.1.2 1.21.4.1.2.1 1.21.4.1.3 1.21.4.1.3.1 1.21.4.1.3.2 1.21.4.1.3.3 1.21.4.1.4 1.21.4.1.4.1 1.21.4.1.4.2 1.21.4.1.4.3 1.21.4.1.5 1.21.4.1.5.1 1.21.4.1.5.2 1.21.4.1.6 1.21.4.1.6.1 1.21.4.1.6.2 1.21.4.1.6.3 1.21.5 1.21.5.1 1.21.5.2 1.21.6 1.21.6.1 1.21.6.1.1 1.21.6.1.2 1.21.6.1.3 1.21.6.1.3.1 1.21.6.1.4 1.21.6.2 1.21.6.2.1 1.21.6.2.1.1 1.21.6.2.1.2 1.21.6.2.1.3 1.21.7 1.21.7.1 1.21.7.2

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Introduction The Plant Classification of Plants Growth of a Plant Conversion of Energy Into Food and Feed Photosynthesis Acquisition and Transfer of Energy Within the Plant Environment Conduction Convection Latent energy in plants Electromagnetic radiation Conversion of Food to Energy Thermodynamics of Food Energy in Food Production On Farm Energy Use Direct energy use Liquid fuel Electricity Indirect energy use Fertilizer and pesticides Effect of fertilizer on crops Macro- and micronutrients Effect and environmental concerns of fertilizers Engineered nanoparticle fertilizers Energy in livestock production Heating Cooling Other contributors to energy use in livestock production Energy in transportation of agricultural goods Food miles Energy use in transportation Energy in food processing, packaging, and storage Canning Freezing and refrigeration Drying Food Waste and the New Cost of Food Production Quantifying Energy Lost Through Food Waste Approaches to Solving the Food Waste Issue Food for Biofuels First Generation Biofuels Bioethanol Biodiesel Corn as a first generation biofuel feedstock Conversion of corn to bioethanol Social impact of first generation biofuels Second Generation Biofuels Emerging second generation biofuel feedstocks Camelina Jatropha Castor bean Case Study: The Energy Cost of a Hamburger Bread Ground Beef

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Food and Energy 1.21.7.3 Sauce 1.21.7.4 Lettuce 1.21.7.5 Onions 1.21.7.6 Pickles 1.21.7.7 Cheese 1.21.7.8 Total Energy Profile 1.21.8 Closing Remarks References Relevant Websites

1.21.1

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Introduction

The law of conservation of energy dictates that energy can neither be created nor destroyed but may experience changes in form. Perhaps nowhere are these changes more apparent than in the production, digestion, and waste handling of foods. Regardless of the type of food, where it came from, or how calorically dense it is, the energy inherent to that food was derived from the Sun. This energy was transferred into plants and microorganisms, who, based on their place in the food web, were consumed, passing their energy onto higher organisms. Consider the human system; we consume plant and animal tissues, which are broken down into their basic components and used to power the machine that is the human body. Consider that the food we eat is used to maintain our body temperature, fuel our brains, and power the ability for movement, and the link between food and energy can be quickly observed. However, it is not only the human system where this can be observed. Biofuels, organic soil amendments, and photosynthesis all represent drastic changes in energy within the food system. Another crucial component to the food and energy sector is the energy required in the production, processing, and distribution of the food humans consume. Field crops, greenhouse operations, and livestock production all represent massive consumers of energy on a global scale. With an exponentially growing global population, the need to feed this ever-growing population has never before been so paramount. This demand cannot be met without increases in energy expenditure. Whether it is clearing new land for agricultural activity, building and maintenance of greenhouses, powering the increase in farm machinery and associated practices, building and running processing facilities, or fueling the increase in transportation, food and energy will be inseparably linked moving toward a world of food parity.

1.21.2 1.21.2.1

The Plant Classification of Plants

The general classification of plants is one that will vary depending on the field for which they are being discussed. For the botanist, almost all of the agriculturally grown and produced food crops fall under the broad category of seed plants, with this group being further subdivided into a number of other groups outlined by their life history. For instance, most agricultural crops can be classified as either annuals, biennials, or perennials. Annuals include those crops that undergo their entire growth cycle from seed germination to full maturity and seed production within a single growing season [1]. Commonly produced annuals include corn, cereals, and beans. Biennials are a group of plants that require two full growing seasons to go from seed germination of full maturity and seed production. With that being said, many biennials are grown and harvested in the first growing season as the aspects of the plants most important for food production are already established at this time. Examples of such production techniques include the production of carrots, beets, kale, cabbage, celery, and Brussels sprouts to name a few. In these instances, the desirable, edible parts of the crop are produced in the first season and harvested before the crops reach full maturity and flower. Finally, perennials are those crops that will live and produce seed for more than two growing seasons. Depending on the nature of the perennial, it may take multiple growing seasons for the crop to establish its reproductive organs and subsequent seeding can occur. This is typically the case for woodier orchard crops such as apples, pears, and oranges. With that being said, there are a number of herbaceous perennials such as clover and alfalfa that reach maturity and seed in a single growing season [1]. A second means for the classifications of plants is through the knowledge of their preferred growth environment and how they respond to changes within this environment. Perhaps the most drastic changes are those of a climatic nature. Climatic factors can include light intensity, light availability, precipitation, air movement, and temperature. Perhaps of equal importance are those factors of an edaphic nature. Physical, chemical, and biological factors to include are soil compaction, biologic activity, soil pH, soil moisture content, soil nutrient availability and movement, soil temperature, and soil air composition. Finally, there are also biotic factors to consider. For instance, classifications made in this category might include the ways in which certain plants respond to limitations or overabundances of selected climatic or edaphic factors. In addition, classifications may also be formed based on hereditary characteristics such as root and leaf development, transpiration control, as well as susceptibility to pollutants and parasites [1].

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Finally, classification of plants can be made based on structure. The most general structural divide begins with the seeds, which can be split into monocotyledons and dicotyledons. Monocotyledons generally grow in a more erect fashion with the veins of the plant being formed parallel to one another. This sort of growth is most commonly observed in grasses. Dicotyledons, on the other hand, generally propagate a stalk with flat leaves being attached to this stalk. The veins in dicotyledons run throughout the leaf and do not follow the same parallel structure as monocotyledons. In addition to this major distinction, differences in vascular tissue relating to the way in which water and nutrients are moved, stored, and utilized within the plant can all form the basis for classification [1].

1.21.2.2

Growth of a Plant

Generally speaking, all agriculturally significant green plants develop from seeds. With that being said, not all seeds are equal, and there are two major categories that crop seeds fall into namely, monocotyledons and dicotyledons. Regardless, both seed types are comprised of embryos, which contain all the necessary components needed for the plant’s development toward maturity. However, these components will remain inactive until seed germination. The embryo consists of the epicotyl from which the plumule will develop to form all of the aboveground components of the plant, the hypocotyl from which the radicle will develop to form all of the belowground portions of the plant, and either one or two cotyledons (seed leaves) depending on the type of seed. Cotyledons are primarily responsible for the digestion, absorption, and storage of food attained from the endosperm. The endosperm is a tissue that serves as an energy source for the developing plant and surrounds all of the components of the embryo within the seed. Depending on the nature of the seed, this endosperm may be completely consumed during embryo maturation or it may not be consumed until the initiation of germination [1].

1.21.2.3

Conversion of Energy Into Food and Feed

Regardless of its end form, all agriculturally grown and produced food on Earth is a derivative of the Sun. Whether it is fruits, vegetables, meat, or fish, the Sun is primarily responsible for producing the end product. This is due to the fact that it is the Sun’s energy that is transferred to plants and converted into biomass. This biomass may be harvested and consumed directly in the case of fruits and vegetables or used to feed livestock and seafood. Approximately 4.3  1020 J of the Sun’s energy makes its way to the Earth’s surface every hour. This is more than the total amount of energy utilized by humans in an entire year (B4.1  1020 J) [2]. As such, it must be considered among our greatest resources, if not our greatest resource.

1.21.2.3.1

Photosynthesis

In its simplest form, plants utilize the Sun’s energy and convert it to chemical energy, which is used to generate biomass through a process known as photosynthesis. Photosynthesis is a process that occurs within the plant and is often represented by the following equation: 6CO2 þ 6H2 O þ hv-C6 H12 O6 þ 6O2 where hv represents energy in the form of light, usually obtained from the Sun. This depiction of carbon dioxide, water, and light in, equals glucose and oxygen out, while accurate, is a dramatically simplified version of the actual process. The process of photosynthesis occurs in two phases, the light cycle and the dark cycle. The light cycle begins in the chloroplasts where chlorophyll, which is a light harvesting pigment, absorbs electromagnetic radiation (light). Upon absorbing this light, the chlorophyll becomes excited to a high-energy state where a series of enzymes known as an electron transport system store this energy in the form of chemical bonds. From this point there are two different reactions that occur. The first involves the energy from the absorbed light, water, and nicotinamide adenine dinucleotide phosphate (NADP þ ). The reaction which subsequently occurs results in NADPH, a reduced form of NADP þ that has an extra electron, which forms a new, highly energized chemical bond. It is important to note that the energy required to perform this reaction is greater than a single photon of light and to compensate for this the plant has two light harvesting photosystems, photosystem I and photosystem II. The numbers associated with these systems refer to the order in which they were discovered and do not have any relation to their importance or order of operation. The major difference between the two photosystems is the wavelength of light that they prefer to absorb. Photosystem I observes optimal absorption at a wavelength of 700 nm whereas photosystem II sees optimal photon absorption at a wavelength of 680 nm. The second reaction is one that occurs as a result of a proton concentration gradient. Specific enzymes within the plant are able to use this gradient to convert adenosine diphosphate (ADP) into adenosine triphosphate (ATP). Following the production of the two high-energy molecules, NADPH and ATP, the light cycle of photosynthesis is complete. The process then enters the dark cycle, which as the name would suggest does not require light to complete. The first stage of the dark cycle is known as the Calvin cycle, which converts some of the NADPH and ATP into glyceraldehyde-3-phosphate (GAP). The second part of the Calvin cycle sees multiple enzyme-catalyzed reactions form larger 5- and 6-carbon carbohydrates, which in turn aid in the formation of further GAP thus continuing the cycle [3,4].

1.21.2.4 1.21.2.4.1

Acquisition and Transfer of Energy Within the Plant Environment Conduction

One of the most critical means of energy transfer within the plant is that of conduction. Energy transfer via conduction operates through the vibration of molecules, which serve to transfer their energy to adjacent molecules without the transfer of any mass. In

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this way, energy can be transferred throughout the plant via this network of molecules [5]. Conduction operates as a “source and sink” type system whereby areas of high energy such as sun-exposed leaves will conduct their energy toward those lower energy areas such as the belowground roots. In this way, energy is readily available throughout the plant.

1.21.2.4.2

Convection

Another substantial means of energy transfer within the plant is that of convection. Convection involves the transfer of energy either to or from the plant toward a fluid, which, in the case of the plant, is the surrounding air. Convection involves the movement of molecules themselves and their linked kinetic energy as opposed to conduction, which simply deals with energy transfer [5]. For the plant, convection is primarily employed as a means of temperature regulation. As heat wants to move from areas of high energy (hot) toward areas of lower energy (cool) the plant is able to give off much of its excess heat into the surrounding air via convection. In addition to this, warm air is less dense than cool air and as a result tends to rise and sit above cool air. This is particularly important in areas of dense vegetation where the convection of energy from the plant to the air causes the warmed air to rise and leave the canopy [1]. This has the beneficial effect of maintaining the area below the canopy at a desirable level for the plants. For areas of less dense vegetation, this effect is also observed albeit on a much smaller scale. For plants there are two means by which convection can occur; these are known as forced and free convection. Forced convection is the more common of the two and comes into play as a result of the wind. Wind in the immediate environment of plants causes this convection to occur with heat energy being moved from the plant into the surrounding air. Free convection, on the other hand, occurs as a result of temperature gradients within the air. Free convection will only occur under low wind velocities and when the temperature difference between the canopy and surrounding air exceeds around 101C. In both cases, the efficiency and degree of the heat transfer will vary greatly dependent on the level of turbulence in the air stream and the degree of temperature difference between the canopy and surrounding environment. As the degree of turbulence increases, the rate and amount of heat transfer increases as well. Much in the same way, as the temperature difference between canopy and surrounding air increases the rate of heat transfer will proportionally increase [5].

1.21.2.4.3

Latent energy in plants

While conduction and convection of heat within the plant deal with sensible heat, there is a significant reaction involving latent heat, which occurs in all plants. This reaction is known as evapotranspiration and is a naturally occurring process essential to the function of plants. In comparison to sensible heat, latent heat is the heat gained or lost during the phase change of a substance, such as water moving from solid to liquid, liquid to gas, or vice versa. In its simplest sense, evapotranspiration refers to a combined process involving water evaporated from the soil as well as water vapor emitted by plant tissues through transpiration. Focusing on the plant itself, water is taken up from the soil by the roots of the plant. It then makes its way up the stalk of the plant and into the leaves where it is volatilized and emitted to the surrounding air via the stomata [6]. The stomata operate as tiny pores used in the exchange of gases in and out of the plant. The general function involves the intake of carbon dioxide and the output of oxygen and water vapor.

1.21.2.4.4

Electromagnetic radiation

The primary form of energy that the plant receives, is in the form of electromagnetic radiation. Electromagnetic radiation makes its way from the Sun in the form of light and it is this light that the plant collects and utilizes to grow, generate seeds, and reproduce [1,3,4]. The light harvesting and conversion process is known as photosynthesis, which was discussed in detail in a previous section.

1.21.3

Conversion of Food to Energy

The composition of the majority of foods that humans consume can be broken down into three main categories: proteins, lipids, and carbohydrates. The molecules that make up these three components however are too large to be used by our cells directly. Therefore, the first step in the conversion of food to energy, following ingestion, is the breakdown of the food molecules. This is a process better known as digestion. Through a combination of organs including the stomach and intestines, larger food molecules are broken down into their monomer components. Proteins are broken down into amino acids, lipids are broken down into fatty acids and glycerol, and carbohydrates are broken down into simple sugars such as glucose through the actions of enzymes within the digestive organs [7]. In stage two, the paths of the three food-derived components diverge slightly. The glucose molecule then goes through a process known as glycolysis, which converts the molecules of glucose into two smaller molecules known as pyruvate. Other sugars are similarly converted to pyruvate following their transformation to one of the other sugar intermediates on the glycolytic pathway. The pyruvate then makes its way into the mitochondria where it is converted into CO2 as well as a two-carbon acetyl group. The acetyl group then becomes attached to coenzyme A (CoA) forming acetyl CoA. The fatty acids derived from the breakdown of lipid molecules are also converted to acetyl CoA. They arrive as fatty acids from the bloodstream, into the mitochondria where the conversion takes place. Additionally some of the amino acids that make their way into the cytosol are also converted into acetyl CoA or another intermediate of the citric acid cycle [7].

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Stage three takes place entirely within the mitochondria of the cell. The acetyl group and CoA, which are joined to form acetyl CoA, are linked via a high-energy linkage. It is this linkage that allows for the acetyl group to be easily transferred to other molecules. The acetyl group is then transferred to the four-carbon molecule oxaloacetate where it begins a series of reactions known as the citric acid cycle. This reaction oxidizes the acetyl group into CO2 and large amounts of nicotinamide adenine dinucleotide (NADH). The electrons present in NADH are highly energized and are passed down an electron transport chain within the inner membrane of the mitochondria. The energy released during this transfer is used to power the reaction, which generates ATP by consuming oxygen (O2). It is this ATP that is used to power many of the functions of the human body [7].

1.21.3.1

Thermodynamics of Food

The energy component of the food we eat is generally presented as calories. Calories are a unit of energy equivalent to 4.184 J. However, what is often misunderstood is the fact that what is on a package’s label is not actually in calories but rather “food calories.” A food calorie is a unit of energy equivalent to 1000 cal, meaning that a product labeled as having 20 food calories per serving in fact has 20,000 cal per serving. To get some perspective on this, one food calorie is the amount of energy required to raise 1 L of water from 15 to 161C [8]. Based on our current understanding of physics, all processes must adhere to the three laws of thermodynamics and the function of the body is no different. The first law states that energy can neither be created nor destroyed, it can only change forms. This is certainly the case for our bodies as well. Energy in the form of food calories is consumed, broken down, altered, and in the end used to power everything from the brain to our muscles and organs. This change in the form of energy can be easily observed in the way our bodies generate heat for instance. Our bodies require a temperature of around 371C in order to operate in a healthy manner; however, the source of this heat was the topic of much discussion for many of history’s greatest scientists and philosophers. We now know that a great portion of the calories we consume are converted into heat in order to maintain our bodies at a comfortable temperature. This was not always the case, however, as the laws of thermodynamics were not fully understood nor was the requirement to consume food. Plato, Aristotle, Hippocrates, and Galen all failed to explain this phenomenon, which we can now attribute to basic thermodynamics [8]. Despite the laws of thermodynamics, the human body is not a perfect converter of energy and this is where the concept of “metabolizable energy” comes into play. Metabolizable energy is the difference between the caloric content of the food we eat and the caloric content of the feces and urine we excrete [9]. The value we are left with makes up the usable portion of the energy we consume. The caloric contents of the foods we eat can be easily determined via a bomb calorimeter and the result is what is known as energy density. Based on previous works we can now know the energy densities for various components within the food we eat. For instance, dietary fat has an energy density of around 9.3 kcal g 1, in comparison with dietary carbohydrates, which have an energy density of 4.1 kcal g 1 [10].

1.21.4

Energy in Food Production

Food and energy will be forever linked, as after all, food production is simply converting one form of energy into another, more desirable form. By taking advantage of photosynthesis, the Sun’s energy can be converted into desirable plant material. Since the advent of agriculture, man has continually strived to increase crop and animal yields while streamlining and making the entire process more efficient. Where at one time agriculture simply meant tilling and planting, modern agriculture has risen to an optimized, highly energy-dependent industry. Creative use of energy has allowed modern farmers to plant more cropland, grow larger, fuller crops, grow animals to sizes previously unimaginable, and overall achieve higher crop and animal yields. Modern agriculture truly began as a response to the drastic changes observed during the industrial revolution. Prior to this event, agriculture was still being performed by hand, tools, and animals by a large number of workers. Tilling, planting, maintenance, and harvesting was all performed by numerous farmers working in combination with one another. As the industrial revolution came about and more and more people became attracted to the better paying jobs in large city centers, farms were left with fewer and fewer employees. They needed to adapt, and ironically it was those same workers who left to work in the factories of the big cities who ended up spurring this change. With the decrease in manpower there was an increased reliance placed on mechanization in order to perform the same amount of work as before. Farmers began to use tractors to till and harvest certain crops, fertilizers were now readily available, and irrigation water could easily be pumped using the newly invented steam engines. This created a link where what was being produced in the factories was now becoming essential to the understaffed farms. While the initial push toward mechanization in agriculture may have come from the promise of better pay elsewhere, the end result was a drastically improved farming practice whose basis remains the norm today [11]. Fewer employees and more mechanization on farms means greater efficiency and cheaper production leading to an overall decrease in global food costs and an increase in global food supply.

1.21.4.1

On Farm Energy Use

When considering farm energy use, the term can be broadly split into two main categories: direct and indirect use. Direct energy use refers to the combustion of fuels whether petro or bio in origin as well as the use of electricity, once again regardless of the

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generation source. Indirect energy use refers to the use of energy intensive inputs such as fertilizers, pesticides, and irrigation water [11,12]. Direct energy inputs on farms account for approximately two-thirds of the total energy inputs, with indirect uses making up the rest of the profile [12].

1.21.4.1.1

Direct energy use

1.21.4.1.1.1 Liquid fuel The primary use of energy on farms is through fuel consumption (including gasoline and diesel). This fuel is primarily used to power machinery to till land, plant seeds, and harvest crops. What often goes unconsidered however is the additional fuel costs incurred during the drying of crops and the transport of harvested goods and livestock. While there has been little fluctuation remarked recently when it comes to on farm fuel consumption, as expected there is a relationship between fuel prices and consumption. When fuel prices are low, farmers tend to utilize more and vice versa [12]. While for instance, the United States Department of Agriculture (USDA) does not release numbers on volume of fuel consumed by agricultural practices, it does releases dollar figures for the total amount spent by agriculture on liquid fuels. Based on these numbers the total amount of annual energy use in the form of liquid fuels by agriculture in the United States has been estimated to be between 0.9 and 1 quadrillion kJ [13,14]. It is important to note that this is an estimate based on available information. Looking at the food supply chain as a whole, combustion of liquid fuels during the production stage of agriculture accounts for around 9% of the total energy consumed [13]. 1.21.4.1.1.2 Electricity While electricity use is not as large of a component as liquid fuels in the agriculture energy profile, it certainly is still a large contributor. Electricity is used in frequently for heating and cooling of dairy and livestock operations depending on the climate and time of year [15]. In addition, if a crop producer is irrigating land for improved production then electric pumps can also play a large role in the energy profile of that farm [12].

1.21.4.1.2

Indirect energy use

1.21.4.1.2.1 Fertilizer and pesticides Fertilizer inputs are the largest contributor to indirect energy use on farms, accounting for just over half of all indirect use. With that being said, there has been an observed decline in on farm indirect energy use which is attributed to fertilizers. While the same amount of fertilizer is being used the efficiency with which it is being produced has drastically improved. This is largely the result of better production efficiency and the use of natural gas feedstocks in the production of modern fertilizers [16]. Once again, as expected, there is a direct linkage between fertilizer prices and consumption, similar to what is observed with the price of liquid fuels [12]. Pesticides are the second largest indirect energy user on farms, accounting for slightly less than half of all indirect energy use. Pesticides are a broad category, which includes herbicides (plant and weed management), insecticides (insect management), and fungicides (fungi management). From 2001 to 2010, global pesticide use saw a sizeable increase due largely to the increased use of herbicides in cropland agriculture. During the same time period however, the use of insecticides and fungicides observed a decrease in usage [12]. Total on-farm energy use in the form of fertilizers and pesticides has been stated as being in the range of 1.1 to 1.5 quadrillion kJ per year in the United States [13,17]. In 2012, 179 million metric tonnes of fertilizer were spread globally. This fertilizer was comprised of 109 million metric tonnes of nitrogen (N), 41 million metric tonnes of phosphate (P2O5), and 29 million metric tonnes of potash (K2O) [18]. As far as energy consumption is concerned, nitrogen is of greatest concern. This is due to the highly energy intensive Haber–Bosch process, which is used to harvest nitrogen from the atmosphere. More specifically, the Haber–Bosch process is one of artificial nitrogen fixation, converting atmospheric nitrogen into ammonia through a reaction with hydrogen and a catalyst. The process is highly energy intensive as it requires elevated temperatures and pressures in order to properly perform the reaction [19]. These temperatures and pressures do not come cheaply, however; they often require large engines, driven by fossil fuels (typically natural gas) to power the process [13]. Despite all of this, the Haber–Bosch process is often considered as the most important advent in modern agriculture due to the comparative difficulties in attaining reliable nitrogen sources using conventional methods. The easiest way to make the process more energy efficient and environmentally friendly would be to incorporate renewable energy sources. Currently, hydrogen, ammonia, wind, and solar are all being explored as possible methods for improving the highly energy-dependent Haber–Bosch process [13,20].

1.21.4.1.3

Effect of fertilizer on crops

1.21.4.1.3.1 Macro- and micronutrients Perhaps nothing has had a more profound effect on modern agriculture as fertilization. Fertilization drastically increases plant productivity by providing essential macro- and micronutrients that stimulate plant growth and result in higher yields. In all there are 16 essential macro- and micronutrients that are necessary for proper plant growth. While all nutrients may not be necessary for all plants, the following 16 nutrients are generally considered essential. The first three nutrients of note are hydrogen, oxygen, and carbon, which are derived directly from water and soil and are generally not supplemented by fertilizers as it is assumed there is an adequate amount already present should the cropland be suitable for agricultural practices. If the cropland is not suitable, then this can be remedied by providing carbon-based soil amendments and irrigation. The next group of nutrients to note are the primary

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macronutrients. This group includes nitrogen, phosphorous, and potassium, which are the most important nutrients for proper plant growth and development. Additionally, these are the primary nutrients listed when selecting a fertilizer. For example, should a farmer wish to spread a 20-10-5 fertilizer then he/she would be utilizing a fertilizer containing 20% total nitrogen, 10% available phosphoric acid, and 5% soluble potash. The remaining 65% would then be made up of other macro- and micronutrients as well as inactive “filler” compounds. The third group of nutrients are known as the secondary macronutrients, which include calcium, magnesium, and sulfur. While these nutrients are essential to proper plant growth they provide less of a direct contribution than the primary macronutrients. As a result, they are not needed in as large of doses for optimal plant development. The fourth group of nutrients are the micronutrients, which include boron, chlorine, copper, iron, manganese, molybdenum, and zinc. The micronutrients are used in considerably smaller doses than the macronutrients; however, they are no less important to the proper development of the plant. Micronutrients perform a variety of functions including improving photosynthetic efficiency, transporting oxygen, aiding in the uptake of macronutrients, and cell development and maintenance to name a few. While the previously listed 16 nutrients are essential to the proper development of all plants, there are other nutrients that can have a great effect on some plants. These include sodium, silicon, cobalt, and aluminum. While they are not considered essential, the presence of these nutrients may aid in the development of certain crops [21]. With all of this being said, simply applying a fertilizer may not have the desired effect. This is due to the reality that there are a number of other factors that will affect nutrient mobility, availability, and uptake from and within the soil. These factors include, but are not limited to, soil moisture content, soil pH, soil oxidation potential, soil electrical conductivity, chemical activity of soil components, amount of organic material, biological activity of surrounding microorganisms, nutrient balance of applied fertilizer, responsiveness of a particular crop to an applied fertilizer, amount of irrigation, environmental exposure, crop density, and presence of weeds [21]. While there are numerous factors to consider, with better management strategies and precision agriculture practices the hope is that all of these factors can be accounted for appropriately. 1.21.4.1.3.2 Effect and environmental concerns of fertilizers Nitrogen-based fertilizers are directly responsible for one third of US total crop productivity. Additionally one unit of nitrogen fertilizer energy input can result in as much as six units of energy output in terms of crop productivity. This is due to the way in which nitrogen-based fertilizers aid in improving photosynthetic efficiency [21]. However, there will come a point of diminishing returns. Being that a single plant can only consume so much of a nutrient, any excess will run off with rainwater, and in the case of nutrients such as nitrogen and phosphorous they have the potential to cause massive environmental damage [22]. In fact, it has been suggested that nontargeted fertilizers have surprisingly low uptake efficiencies of 50% for nitrogen, 10% for phosphorous, and 40% for potassium [23,24]. In order to better manage this, a number of factors must be taken into consideration. By taking into consideration the targeted crop requirements along with the source, rate, timing, and placement of fertilizers the fertilizer use efficiency can be dramatically improved [25]. Ensuring that spreading equipment is in good working order as well as keeping up with the latest in fertilization technology can also have a major effect on decreasing the chance of overfertilizing. 1.21.4.1.3.3 Engineered nanoparticle fertilizers Nanoparticles are constructed of nanomaterials that meet the requirement of being between 1 and 100 nm in at least one of their dimensions. To fully understand nanoparticle fertilizers it must first be understood that they come in two distinct forms. The first form is nanofertilizers themselves. Nanofertilizers are nanoparticles that deliver one or more macro- or micronutrients directly to the plant. Comparatively, there are also nanomaterial-enhanced fertilizers that do not directly provide the plant with nutrients but rather serve to enhance the performance and uptake of conventional fertilizers. Compared with conventional fertilization practices, nanoparticle fertilization is expected to significantly improve crop yields and development, improve upon fertilizer use efficiency, reduce the amount of lost nutrients to runoff, as well as reduce the potential for environmental degradation. Due to their small size, nanofertilizers may have the ability to pass through cell wall pores which have a size ranging from 5 to 20 nm [26]. With that being said, the reactions once the nanofertilizers make their way into the plant are still largely not understood [26,27]. The small size of the nanoparticles also provides a higher specific surface area, which means that more fertilizer can be delivered more effectively to the plant [26]. In lab scale, nanoparticle fertilizers have already been shown to enhance the growth of a variety of crops including tomatoes [28] as well as soybeans [29]. The overall hope is that delivering nutrients to the plant more efficiently will result in improved plant growth and drastically enhanced fertilizer use efficiency. This will have the end effect of producing greater crop yields and reducing the potential for environmental degradation as a result of agricultural runoff.

1.21.4.1.4

Energy in livestock production

When dealing with livestock production in an on-farm setting the largest incurred cost and energy expenditure will be in the form of heating and cooling. Despite the fact that many livestock species are being grown in their local environment does not mean that this same local environment provides ideal growth conditions 12 months of the year. Domestic livestock are homeothermic, meaning that in spite of external environmental pressures they attempt to maintain a constant internal temperature. This process becomes far simpler if the exterior temperature is more favorable. If the exterior temperature is too hot or too cold then the animal must expend too much energy regulating body temperature, energy that does not go into producing more biomass. The optimal exterior temperature range for each animal is known as the “thermoneutral zone.” Temperatures within this zone will provide the highest overall biomass yields [30]. A list of thermoneutral zones for various livestock species is presented below (Table 1).

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Table 1 Thermoneutral zones for various livestock species showing the lower critical temperature (LCT) and upper critical temperature (UCT) in degrees celsius Livestock

LCT (1C)

UCT (1C)

Cattle Dairy Beef Calf

0

23 26 30

Swine Sow Piglet Growing/finishing

5 20 7–15

27 30 25–27

Sheep Ewe Poultry Chicken

26 17

15 18–34

32 24–36

Source: Fluck RC. Energy in farm production. Amsterdam: Elsevier; 2012 and Scott N, De Shazer J, Roller W. Effects of thermal and gaseous environment on livestock. In: Hellickson MA, Walker JN. editors. Ventilation of agricultural structures. St. Joseph, MI: American Society of Agricultural Engineers; 1983. p.121–65.

In areas where the temperature fluctuates beyond or below the thermoneutral zone of the livestock being produced then an adequate amount of heating or cooling must be provided for best growth. While animals are capable of maintaining their body temperature beyond and below this zone it requires the redirection of too much feed energy to maintain, subsequently hindering the accumulation of biomass. 1.21.4.1.4.1 Heating There are two methods of heating used to provide warmth to livestock during the colder months. These two forms of heating are known as cold or warm heating and are used to describe the method with which the building is maintained within the thermoneutral zone. During cold heating, animals are contained within an insulated building where their bodies naturally let off a certain amount of heat. This heat is trapped within the building and used to maintain the thermoneutral zone. Design of cold heating buildings requires meticulous attention to detail and knowledge of heat flows in the form of radiation, conduction, and convection for best results. These systems are also dependent on housing a certain number of animals making changes in the system more of a challenge to implement. Cold heating is much less expensive as there is no external energy expenditure in the form of electricity or liquid fuel-driven heaters. With that being said, cold heating is not as reliable and will become less effective the further the outside temperature drops. Additionally, cold heating has the issue of moisture buildup which must be accounted for with proper ventilation. This comes as a challenge in that, as the warm moist air is evacuated from the building, it is also heat that is being lost. Balancing this ventilation while maintaining an appropriate temperature within the building is one of the greatest challenges with cold heating. Despite all of this, a properly designed and maintained system can drastically reduce production costs and help to reduce on-farm overheads [30]. During warm heating, supplemental heat is provided through the use of an external heater. This process utilizes large amounts of fuel, be that electricity or liquid fuel. While there is the potential for this fuel to be provided via biofuels generated on farm, this is often not the case. The amount of fuel expended will vary considerably based on a few key aspects. The first is the difference between the inside and outside temperatures. The first two laws of thermodynamics govern the rate and direction of the heat transfer. Heat always wants to move from an area of high energy (warm environment inside the barn) to an area of low energy (cold outdoor environment) and the speed at which the heat will move is controlled by the difference in temperatures between the indoor and outdoor environment. The greater the temperature difference is, then the faster heat will transfer. This should be of primary concern when providing heat to a livestock environment as the amount of fuel consumption will be high if the temperature difference is also high. The best way to account for this is through insulation. Insulation can help to mitigate the amount of heat that is being transferred from the indoor to outdoor environment. While greater insulation does come at a higher upfront cost, in the long run it will save heating fuel and as a result money. Another consideration is moisture buildup within the building. As with cold heating, moisture generated from the contained livestock must be removed to maintain a comfortable environment. Proper attention must be paid to optimization of the ventilation process as escaping heat means more fuel and greater expense. Finally, there will still be a considerable amount of cold heating provided by the livestock. Being able to properly use this heat can have the dramatic effect of reducing the amount of fuel consumed by the heater. Given the design of the system along with the environmental conditions it is possible to design a system that will only require warm heating during the coldest days of the year. The control and ability to easily attain higher temperatures makes warm heating preferential for younger livestock, which generally have higher thermoneutral zones [30].

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Warm heating has a number of options when it comes to the design of the system. Forced air and hot water systems are the most commonly employed means of providing heat for livestock. Forced air systems are either centralized heaters that send heat through ductwork and into the containment area or they may be set up to blow warm air directly into the desired area itself such as a wall mounted heater. Regardless of the design, forced air heaters take in outside air (known as a heat sink), heat the air, and then transfer that heat to the desired location. While a recirculating heater (whose sink would be the warm air of the containment area) would be a more efficient option in terms of fuel and energy consumption, this is often not recommended due to dust and other air quality concerns. Recirculating this air could have significant effects on in-barn air quality and subsequently affect animal health and wellbeing. Hot water systems draw water from a heated reservoir and circulate this water through pipes in the containment area. Specialized radiator pipes transfer heat from the water into the surrounding air. So long as these pipes are kept clean then the efficiency of the system is quite high. Unlike forced air systems, recirculating of the hot water can easily be done as there is no risk of contamination or harm to the livestock. Additionally, for both systems a heat exchanger can be implemented to help preheat incoming air and water. This process can drastically reduce the heating requirement and fuel expenditure [30]. 1.21.4.1.4.2 Cooling During the warmer months of the year and in many climates year round it is important to provide cooling to ensure livestock wellbeing. For many regions the simplest way to do this is through shading. Shading is a simple form of cooling that requires no energy inputs making it highly cost efficient. Simple structures or even large trees can be enough to provide all the cooling requirements for certain climates given the type of livestock [30]. While the shading system will reduce the load of solar radiation on the livestock, given its design it may not do much to reduce the overall temperature after accounting for heat trapping and the cold heating generated by the livestock themselves. Due to this, proper system design must take air flow within the shading system into consideration [31]. Proper shading implementation can take advantage of local wind patterns and geography in order to provide the best air flow for the system. Depending on the situation, a properly designed system may be enough to account for the heat and solar radiation on its own. Where design is not enough to fully meet the ventilation and airflow requirements, a forced air system can be employed. This is typically done through the use of fans, which provide bonus air circulation to the area. While fans do offer greater control over air flow they also consume power in their operation. This cost however may need to be incurred, should the air flow requirement be impossible to meet naturally [30]. Generally speaking, supplemental cooling is only implemented when the average temperature exceeds what is required for maximum livestock productivity be that milk, biomass, or egg production. While refrigeration would be the optimal method for providing this cooling it is generally considered to be too expensive for use in livestock production [30]. The high installation costs as well as the large power consumption of the units makes refrigeration only possible for the largest operations. It is for this reason that the most commonly employed cooling method in livestock operations is evaporative cooling. Evaporative cooling comes in two forms, fan and pad, as well as spray evaporators. A fan and pad evaporator functions by having a moist pad located in front of a fan, which blows air through the porous pad. Water is circulated through the pad to ensure that it remains wet. As the air makes its way through the moist pad it evaporates some of the water. This evaporative process results in the removal of latent heat from the air, thereby lowering the temperature of the incoming air. The result is an influx of cool air and the lowering of the internal temperature. This system has a far lower energy requirement than refrigeration as the only aspects that require a power input are the fan and a small pump to circulate water through the pad [30]. Spray evaporative cooling systems operate by spraying a mist of small water droplets in front of a fan, which then distributes the droplets within the area. The small droplets will then evaporate and cool the area through the removal of latent heat. Other designs utilize sprinklers to wet animals to the skin before utilizing fans to once again evaporate this moisture. Both systems are effective for providing cooling to a variety of livestock [32]. 1.21.4.1.4.3 Other contributors to energy use in livestock production Waste handling can be another highly energy intensive process within a livestock operation. Some estimates suggest that waste handling can account for more than 11% of total energy requirements in an agricultural operation [33]. Scrapers, front end loaders, belts, and wash water may all be used for collecting manure depending on the nature and consistency of the manure. Moisture control was briefly mentioned earlier, however ventilation also serves to control potentially harmful odors produced as a result of livestock generated waste. The amount of ventilation required to control moisture buildup within enclosures is generally considered to be enough to also control odor. If this is not the case, then supplemental ventilation will be necessary to provide. If supplemental ventilation is required then this must be accounted for in all other areas of environmental control. The ventilation requirement for odor control will be dependent on the type of livestock, the size of livestock, the size of the enclosure, and the waste handling system in use [30,34]. Lighting is another source of energy use in livestock production. While lighting does not have the same importance for all livestock, it is often provided to improve visibility. Lighting is particularly important for laying hens whose productivity can be greatly enhanced through the implementation of selected photoperiods [35]. Feeding animals comes at a cost as well. Transport and delivery of feed can be done via motorized augers, driven belts, or by small vehicles equipped with a bucket. While grazing can reduce this cost, it is a seasonal practice for many parts of the world. Additionally, the handling and transport of livestock from production to processing areas can be highly energy reliant, dependent on the weight, distance, and required processing steps [30].

Food and Energy 1.21.4.1.5

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Energy in transportation of agricultural goods

Agriculture is a highly energy intensive process and perhaps nowhere is this more apparent than in the transportation sector of agriculture. Agricultural transportation refers not only to the transport of goods to market but also the transport of pesticides, fertilizers, liquid fuels, and other inputs to the farm as well as the transport of goods and wastes away from the farm to processing plants and the subsequent transport to market. To further intensify this energy demand, farms are often decentralized from their major markets. This makes transportation costs much higher as the distance to processing and markets is much further. In addition to this, agriculture products have become globally available. Northern climates now enjoy all the riches that warmer climates typically do, with such things as citrus fruit, berries, and a wide variety of vegetables being available at market year round. Conventionally, these were considered luxuries in the winter months, but through globalization have become the normal. Despite the benefits that the availability of these crops bring, they do come at a price. This price comes largely in the form of transportation costs associated with shipping products such great distances. 1.21.4.1.5.1 Food miles The term food miles was first introduced in literature in the 1994 paper titled “The Food Miles Report” [36]. In this report, the term food miles is used to describe the distance from where a food is grown to where it is eventually being sold. Along with this comes the negative connotation that says that the further a food is produced from where it is sold the more environmentally detrimental it is due to associated transportation costs. While this approach does seem to make sense, there are a number of other factors to consider when determining the environmental impact of a product. Additional aspects to consider include packaging, processing, marketing, and production [37,38]. After factoring in these aspects, the profile of the issue can change somewhat. The example given by Garnett is that of a heated greenhouse. While the greenhouse could be local and require very little transport to market, the energy required to heat this greenhouse may have a higher impact than the energy required to transport the same crop a great distance to the same location [37]. Additionally, Garnett goes on to state that the requirement for pesticides and fertilizers in certain locations may also outweigh the amount of energy required to transport the same crops from more agriculturally friendly and appropriate zones regardless of distance. Despite all of this, Garnett does conclude that the concept of food miles is a legitimate predictor and highlights the importance of attempting to source locally available and seasonal foods [37]. While this sounds like a great solution the issue that arises is that fresh, local, and seasonal crops are not available year round for northern climates. Therefore, for those who are looking for fresh produce during the winter months, the only option is to turn to foods grown in warmer climates. This means more food miles, greater energy consumption, and generally more of an environmental impact. The global increase in food miles has been one largely driven by the global increase in food trade. This increase in trade can be attributed to a number of factors including but not limited to increasing interest in foreign products, better storage and transport conditions, as well as the current structure of the food value chain (agricultural specialization, supermarket, major distribution centers). Each of these aspects has a highly important role to play in determining the distance food travels from field to processing to market [39]. While the trade of food not only within countries, but also across borders, has become more or less normal in much of the developed world, food trade does not come without significant environmental and social impacts. By increasing the distance food travels, there is a direct effect on air, soil, and noise pollution. From a social standpoint, this also means more trucks on the road, more vehicle accidents, and raises many questions about animal welfare in terms of how they are transported and processed in a manner that aims to reduce costs as much as possible [39]. With all of this being said, global food trade does also come with a number of positive benefits. For example, increases in global food trade can result in job creation, higher food exports for poor countries, greater food availability, greater food diversity and overall, cheaper food products [39]. It is the last of these benefits that seems to be the greatest driving factor in the justification of global food trade. Consumer choice will always drive what is sold, and it should come as no surprise that cheaper goods will often be preferential given that they are of similar quality. Further to this point, it must be recognized that in order to reduce the environmental impacts of food consumption in the modern situation, a major shift in focus must occur. This however seems possible given a high degree of personal choice coupled with a lack in long term lock-in effects in consumers’ day-to-day choices [40]. While the concept of food miles does a reasonable job of depicting the impact of food transport from production to plate, there are some who feel that it is too simplistic [13,38,39]. Opponents to the use of food miles as a sustainability indicator state that there are far more factors involved in food sustainability than the simple distance it is transported as portrayed by many conventional food mile models. This is where the concept of enhanced food miles comes in. Enhanced food miles is a proposed model that aims to incorporate the aspects of social, environmental, and economic sustainability and account for all of the external costs associated with each, as they pertain to food transportation. In addition, this model also takes into account the method of transport of food products [39]. The current model for food miles treats all methods of transport the same and is simply concerned with the distance food travels. While this does paint some of the picture, the method of transport has a major effect on a number of environmental parameters. Vehicle size, type, efficiency, and fuel source all have an important role to play in determining the overall impact and energy consumption of food transportation. For instance, air transport has a very high energy and environmental impact when compared with water- or road-based transportation systems. Water transport has the lowest impact due to the volume of product that can be transported at one time, however it can be slower, which must be accounted for especially when dealing with perishable goods [39]. This gives further justification to the need for an improved food mile model. For instance, transporting bananas from Central America to New Jersey, United States via water is far more energy efficient than transporting it to Dallas, United States via road-based transportation despite the fact that Dallas is far closer [13]. Enhanced food

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miles is just one model that has the potential to better explain the total impact of food miles. By taking a comprehensive outlook, the true cost of global food trade can be determined. With all of this being said, developing a comprehensive model is challenging due to uncertainties in input/output analyses, how to properly aggregate goods, true efficiencies of transport methods, regional differences, and how to properly determine what is, and draw conclusions for, an “average” home [40]. 1.21.4.1.5.2 Energy use in transportation After industrial applications, transportation represents the largest energy consumer in the United States. Around 5% of what is consumed in the transportation sector can be attributed to the transportation of food [13]. While this may not seem like much, this 5% accounts for approximately 1.4 quadrillion kJ in energy consumption annually [11,13,14,41]. To put this in perspective, transportation of food accounts for a little over 1% of the total United States annual energy consumption [13]. Taking this all into account it becomes quickly apparent that food transportation represents a major consumer of energy, particularly in the form of fossil-based liquid fuels.

1.21.4.1.6

Energy in food processing, packaging, and storage

Foods are processed in a variety of ways with the overall goal generally being to alter the form of the food, ensure any microbial activity is safe, improve the quality of the food, or to maximize shelf life. Of these four, three of them are generally performed through energy intensive thermal processes. In looking at the food production sector as a whole, food processing can account for as much as one third of the total energy input [42]. In all it is the consumer’s demand for quick and convenient foods along with more stringent food safety regulations that have spurred the movement toward highly processed foods. It has become normal to enter the grocery store and find processed fruits, vegetables, meat, dairy, and all other varieties of processed foods. Whether the processing be as simple as washing or as complex as completely altering the form, these are all energy reliant processes that have had a massive effect on the energy profile of food production and processing. Food processing has been estimated as consuming as much as 1.2 quadrillion kJ annually in the United States [13]. Within processing, the most energy reliant processes are that of freezing, drying, and canning. The first two of these examples are seen as thermal processes that rely solely on the addition or removal of heat energy. This can have the effect of deterring microbial activity or increasing shelf life. Consumer preference has shifted toward these more energy intensive methods of food preservation and away from pickling, salting, and fermenting processes, which would require far less energy requirement. This however does not appear to be reverting, as the quality increase with the newer methods is worth the additional energy cost for the majority of consumers [43]. 1.21.4.1.6.1 Canning Canning is a method of food preservation commonly employed in modern food processing. The first step in canning involves the heating of a product in order to kill off any potentially harmful microorganisms that may be present. Products are then packed into sterile glass or metal cans, sealed, and shipped to market. The greatest energy consumer when it comes to canning processes is the manufacturing of the cans themselves. Production of glass or metal canisters can account for up to 80% of the total energy input to the system [44]. While plastic retort pouches offer a cheaper option from an energy standpoint, they do not offer the same structural benefits of a can which can be of benefit during shipping and handling. Further emphasis on the recycling of used cans has also led to a decline in the energy requirement within the canning industry. Canning operations have seen an overall downturn in recent years due largely to consumer preference. As canned vegetables must be heated prior to packaging, it causes a change in the food’s consistency. As such, many people are turning to frozen alternatives, which do not encounter the same flavor and texture issues. 1.21.4.1.6.2 Freezing and refrigeration Freezing is a refrigeration process that directly takes advantage of the vapor compression cycle. This cycle operates by compressing and expanding refrigerants and relies on the pressure/temperature relationship to draw heat from a source and move it toward a sink. The primary consideration in selecting a refrigerant is the requirement to have a boiling point slightly below the intended temperature. The cycle begins with the refrigerant, in the state of a saturated vapor, entering the compressor. The compressor increases the pressure that the vaporized refrigerant is under and subsequently causes a rise in temperature. The now superheated vapor enters the condenser, which can be easily observed as the coils on the exterior of the refrigeration unit. This step condenses the superheated vapor back into a liquid, which subsequently releases heat back into the environment. Systems such as the one described are known as air cooled units however some systems may use water as a sink for excess heat. The compressed liquid then passes through an expansion valve where it is converted into a mixture of liquid and vapor. This drastic reduction in pressure causes a simultaneous drop in the refrigerant’s temperature. The liquid/vapor mixture is then run through a series of coils within the enclosed area to be cooled. Warm air is blown by a fan over the coils, which causes the vaporization of the remaining liquid in the refrigerant and subsequently cools the air as it enters the contained area. This air, in combination with the cool vapor within the coils, is what maintains the containment area at the desired temperature. The refrigerant then makes its way back to the compressor and the process repeats itself. The process of refrigeration is one that is highly energy intensive and detrimental to the environment. While household refrigerators may only represent a small portion of the issue, large scale, cold storage facilities require immense amounts of electricity to maintain their below-ambient temperatures. Some energy audits indicate that cold storage facilities could be using up

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to 100 kWh m 3 year 1 depending on the efficiency of the system [45,46]. Given that the largest facilities can be hundreds of thousands of cubic meter then the energy requirement is certainly substantial. In addition to this, estimates suggest that refrigeration is responsible for as much as 2.5% of global greenhouse gas emissions through direct and indirect energy consumption [47]. Freezing is a highly energy intensive process that involves the removal of heat energy from a food product, which inherently slows microbial activity not only directly but also serves to freeze water within the product that could aid harmful microbes. All of this results in a greater shelf life for the product should it remain frozen. Freezing foods is typically seen as a more energy intensive process than canning due to the additional processing steps required. Taking vegetables as an example, vegetables simply need to be heated in order to kill harmful microbes before canning. Freezing on the other hand, first requires blanching in order to inactivate plant enzymes that would otherwise cause the deterioration of color and texture, followed by a cooling period and finally freezing. On average, it is estimated that the energy requirement for freezing fruits and vegetables is around 7594 kJ/kg compared with 2406 kJ/kg for canning [41]. Further complicating the case for frozen food are the additional storage requirements that the products must undergo. Recommended storage for canned goods is only slightly below room temperature whereas it is recommended that frozen food be stored at 181C in order to deter the activity of microorganisms [41]. Based on a storage period of 6 months in a home freezer it is estimated that storing frozen foods requires as much as 4435 kJ/kg of energy depending on the size and efficiency of the freezer [48]. Transport of frozen goods can also play a major role in the energy profile of these products. Frozen goods are transported via refrigerated trucks that aim to maintain a constant low temperature in order to ensure the integrity of the frozen food products. The specific requirements for each truck will vary by region and the product being transported. For instance, the United Kingdom classifies its refrigeration trucks in terms of their insulation values as well as their temperature control class. Trucks are classified as either normally insulated (U coefficient equal to or less than 0.7 Wm 2 K 1) or heavily insulated (U coefficient equal to or less than 0.4 Wm 2 K 1) based on the heat transfer capabilities of the containment walls. Additionally, trucks are also divided by temperature class into the most common groups of 201C, 101C, 01C, and 121C. The majority of refrigeration units equipped in refrigeration trucks are driven by auxiliary diesel engines. While these engines have the advantage of being independent of vehicle propulsion, they are still highly energy dependent. Impacts resulting from the use of auxiliary engines can be as high as 40% of the primary vehicle engine’s impact [49]. 1.21.4.1.6.3 Drying Another common method of food preservation is the drying of grains, meats, fruits, and vegetables. Drying is a process that removes the water from foods and in doing so, preserves them for a far longer period then they would otherwise last. More specifically, drying reduces the moisture contents of these foodstuffs below 13% in order to deter and inhibit microbial growth and activity [41]. Due to the nature of the process, food drying is a highly energy intensive process that can account for anywhere between 20% and 25% of the total energy use within the food processing sector [50]. Current research is aimed at improving the inefficiencies of the drying process. To give some perspective, it has been suggested that an energy efficiency improvement of 1% could result in an overall profit increase of as much as 10% for certain industries and processes [51]. Intermittent drying represents one approach to reducing the overall energy requirements for food drying. Intermittent drying aims to reduce energy consumption by monitoring and adjusting the drying conditions throughout the process in order to optimize the overall efficiency of the system. Conventional drying systems simply operate on a set it and forget it basis, where a set temperature is maintained for the entirety of a set amount of drying time. In some instances temperature may also vary throughout the period. Intermittent drying however takes a far more comprehensive approach to improving the efficiency of the drying process. Intermittent drying monitors and controls the variables of temperature, air flow rate, pressure, and humidity. In addition to this, intermittent drying can also alter the method of energy input. Convection, conduction, radiation, and microwaves are all possible options given the requirements to the specific drying process [50]. By monitoring and altering the drying conditions, intermittent drying is able to produce a superior product while using less energy. This is because the rate at which a food dries is not constant. As the drying process progresses, the rate at which moisture is removed from the food slows. This is due to the fact that there is less moisture to remove and what moisture is present is locked in near the center of the food. In a conventional drying system where all parameters are fixed, this results in product inconsistencies. The portions toward the outside of the food become drier than those located toward the center. This is an undesirable consequence of conventional drying, which results in an overall lower quality product. Intermittent drying can directly solve this issue by reducing temperatures throughout the drying process to match the rate of moisture removal. This results in a more desirable, homogeneous product, free of any exterior damage or excess drying [50]. In addition to a higher quality food product, intermittent food drying decreases the operational time and the amount of drying air required [52]. Taking into account a series of studies, intermittent drying can save anywhere from 19% to 52% over traditional continuous drying procedures [53–56]. This range is based on the amount of time required to dry the various tested foodstuffs along with the nature of the tested foodstuffs themselves. Microwave heating represents yet another potential solution to the issue of energy inefficiency in food drying and sterilization. Microwaves are electromagnetic waves that have a frequency ranging from 300 MHz to 300 GHz. Conventional household microwaves operate in a range near 2.45 GHz whereas industrial scale microwaves operate at frequencies of 915 MHz and 2.45 GHz [57]. Microwave heating occurs largely due to dipolar and ionic mechanisms. The dipolar nature of water present in foodstuffs causes dielectric heating when exposed to microwaves. The electromagnetic fields present within the operational microwave oscillate as they make their way through the foodstuffs. This causes the dipoles within the water of the foodstuff to flip

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in order to realign with the ever changing electromagnetic field. This flip occurs millions of times per second, and the reaction of the flipping causes internal friction with the molecules resulting in the heating of the surrounding area [58]. Microwave heating may also occur as a result of oscillatory ion migration in the foodstuffs, which generates heat as a result of the high frequency oscillating electromagnetic field [59].

1.21.5

Food Waste and the New Cost of Food Production

Fossil fuels have drastically altered agriculture in ways that allow for increasingly greater and greater production and yields. They have allowed farms to plant, manage, and harvest larger areas than ever before while requiring fewer people to perform the additional work. They have also caused a shift in how agriculture must be viewed as a highly energy intensive and resource exploiting process. No longer are crops and animals grown and produced by hand to meet the needs of the local consumer. Nowadays, large centralized farms produce vast amounts of only a few goods for shipment throughout the world. Factory farms provide easy management and meat production, tropical fruits and vegetables are available year round, and products can be purchased from nearly every corner of the globe. While these products look great on a grocery store shelf, the reality is that they require a vast amount of energy expenditure to go from a seed to your kitchen table. When factoring in the aspects of water diversion, pesticide production and spraying, fertilizer production, fuel for farm equipment, transportation of goods, processing and packaging of goods, food sales and storage, the picture becomes far clearer. Food production is a highly energy intensive process that has become reliant on fossil energy [14,60] to drive the ever-growing industry’s attempts to satisfy the ever-growing demand.

1.21.5.1

Quantifying Energy Lost Through Food Waste

As mentioned, food production is a highly energy intensive process. Some estimates suggested that food production in the United States accounts for approximately 10%–16% of the total energy use in the country [14,60]. While this amount of energy is sizeable, on the outside it is seemingly justifiable in order to feed the ever-growing population. The issue that arises is that a large amount of this energy is wasted, as much of the produced food is never consumed. Globally, as much as 32% of food by weight goes unconsumed or is lost during harvesting, processing, transportation, or spoiling. In terms of calories this accounts for 24% of all produced food [61]. Consider that nearly a quarter of all produced food goes uneaten and given the energy shortages and famine that plague the world then it quickly becomes apparent that food wastage is a large scale issue. Further complicating the matter is that the energy that is used to produce this food is primarily derived from fossil fuel sources. These are finite resources that have the added detriment of degrading the environment. In wasting food, an equivalent amount of energy is also being wasted while degrading the environment at no benefit. Table 2 shows the energy required to produce food by type and sector of the production cycle as well as the percentage that is wasted. While the data is from 2004 it still paints a representative picture of the vast amount of energy wasted in food production and processing that is never capitalized upon. From Table 2 a few important conclusions can be drawn. Firstly, meat, fish, and poultry represent the largest portion of required energy input in order to produce, transport, handle, and process. Despite this, they have a wastage rate far below the average, which could lead to the conclusion that this energy is generally being put to good use. However, upon considering the vast amount of energy input coupled with the 16% wastage rate the result is 330 trillion kJ of energy wasted annually. This figure is surpassed only by dairy and vegetables, which annually waste 460 trillion kJ and 420 trillion kJ, respectively. This is no small amount of energy either; a conservative estimate would suggest that the energy wasted in dairy alone would be enough to provide electricity to 11.5 million American homes for a year [62]. Compound this with the vast amounts of energy wasted in the other sectors and the crisis becomes clear. Table 3 gives a complete profile of the energy wasted as it pertains to each category of food. Table 2

Energy required to produce food by category and sector of production cycle along with the portion that is wasted, 2004

Food category

Agriculture (trillion kJ)

Transportation (trillion kJ)

Handling (trillion kJ)

Processing (trillion kJ)

Total (trillion kJ)

Percent wasted (%)

Grains Vegetables Fruit Dairy Meat, fish, poultry Eggs Pulses Nuts Sweeteners Fats and oils Total

75.33 56.44 28.38 246.87 820.79 102.44 9.38 0.35 0.00 0.00 1339.98

195.18 429.39 284.85 288.02 299.62 33.76 6.86 10.34 144.54 90.10 1782.63

449.43 986.43 653.05 661.49 687.86 77.02 15.83 24.27 331.27 206.78 4093.40

163.53 187.79 128.71 241.60 251.09 28.49 5.28 8.44 121.33 75.96 1212.20

883.46 1660.04 1094.98 1437.97 2059.36 241.70 37.34 43.39 597.13 372.84 8428.21

32.0 25.3 23.4 32.0 16.0 31.4 15.9 15.9 30.5 33.4

Source: Cuéllar AD, Webber ME. Wasted food, wasted energy: the embedded energy in food waste in the United States. Environ Sci Technol 2010; 44(16):6464–9.

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Table 3 in 2004

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Total energy wasted or lost by type of food

Food category

Total energy wasted/lost (trillion kJ)

Grains Vegetables Fruit Dairy Meat, fish, poultry Eggs Pulses Nuts Sweeteners Fats and oils Total

282.71 419.99 256.23 460.15 329.50 75.89 5.94 6.90 182.12 124.53 2143.95

Source: Cuéllar AD, Webber ME. Wasted food, wasted energy: the embedded energy in food waste in the United States. Environ Sci Technol 2010; 44 (16):6464–9.

Given the exponentially rising global population, there has been and will be a need to feed the ever-growing populace. While the current approach is to simply produce more food, there is evidence to suggest that decreasing food waste could have an even more drastic and immediate effect. Consider the example provided by Lipinski et al. [61]: if food waste could be cut in half from the now 24% to a more reasonable 12%, then by the year 2050 the world would require around 1314 trillion fewer kilocalories than the projected “business as usual” model. This shift alone would account for 22% of the projected global caloric requirement by 2050 [61]. This shift would subsequently have a massive effect on energy requirements in food production. While it is conceivable to believe that agricultural practices will become more energy efficient by 2050, it would be foolish to assume that they will no longer be large consumers of energy. A reduction in food waste would indirectly result in energy savings, which would be reflected in food supply and prices.

1.21.5.2

Approaches to Solving the Food Waste Issue

The food waste issue is one that certainly requires urgent attention. Through the development of better management strategies the hope is that food and subsequently energy waste can be reduced to more acceptable levels. Some strategies to help in mitigating food waste that could quickly and easily be implemented include making redistribution and donation of food easier through the use of evaporative coolers in areas where refrigeration is not possible, introduction of hermetically sealed storage bags to reduce spoilage, use of plastic crates as opposed to bags to prevent damage, changing or providing better education on the difference between best before and expiry dates, reduction of portion sizes at restaurants and other eating establishments [61]. These simple changes could have a drastic effect on food spoilage and waste if implemented properly. In addition to these suggestions Lipinski et al. [61] go on to suggest five policy changes that could serve to drastically reduce the effects of the food wastage crisis. These policy suggestions are: 1. 2. 3. 4. 5.

Develop a food loss and waste measurement protocol. Set food loss and waste reduction targets. Increase investment in reducing postharvest losses in developing countries. Create entities devoted to reducing food waste in developed countries. Accelerate and support initiatives to reduce food loss and waste.

It goes without saying that implementation of these policies would require buy-in from national governments, intergovernmental agencies, and the private sector in combination [61]. With that being said, the potential to save not only food but also substantial amounts of energy should be more than enough incentive to fix an issue that will only get worse with time.

1.21.6 1.21.6.1

Food for Biofuels First Generation Biofuels

First generation biofuels refer to those biofuels derived directly from food crops. Desired first generation feedstocks are generally high in lipids or carbohydrates such as sugars and starches [63]. These components are desirable due to their ability to be easily converted into a variety of biofuels with little processing. In the current situation, first generation biofuels make up over two thirds of total global biofuel production [64]. This is important to note amidst rising concerns over global cropland and food availability. As first generation biofuels are derived from food crops, their production means that food cannot be grown on that cropland. How can the demand for fuel be justified when globally, hunger remains one of the largest issues? This is the basis of the food versus fuel debate.

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With the obvious social and environmental concerns surrounding the production of first generation biofuels, there has arisen a need for better policy surrounding their implementation. In 2014, European energy ministers agreed to establish a cap on the use of oil and starch rich crops in fuel blending at 7%. This number was considerably lower than the European Union’s target of 10% renewable liquid fuel blends; however, it serves to acknowledge that first generation biofuels, while profitable, do have major concerns [65]. In addition to this, countries such as Spain and Italy are implementing improved regulations on feedstock selection, tending to move away from competing food crops and toward second and third generation or advanced biofuels [66]. Despite this, many countries are further raising their requirement for blended liquid fuels and are looking toward first generation biofuels to meet this demand. Argentina (up from 7% to 10%), Malaysia (up from 5% to 10%), Panama (up from 2% to 7%), and Vietnam (up from 0% to 5%) have all raised their blended fuel requirements in the last year alone. As of early 2015, there were 33 countries that had some form of blended fuel mandate requiring a minimum percentage of alternative liquid fuels to be incorporated with commercially available petroleum [66].

1.21.6.1.1

Bioethanol

The most prominent first generation biofuel is that of bioethanol. Bioethanol is derived through a fermentation process that converts sugar into ethyl alcohol. This approach is used for crops such as sugar cane, sugar beet, and sweet sorghum. Alternatively, for crops with a higher starch content such as corn, wheat, and cassava, a hydrolysis/fermentation process can be performed in order to attain the same ethyl alcohol as an end product [64]. While both processes result in the same output, sugars are still the more desirable of the two due to their greater ease in conversion. Conversion of simple C6 sugars into ethyl alcohol simply requires the use of selected yeast species such as Saccharomyces cerevisiae [67]. In contrast, the conversion of starches into ethyl alcohol is more complex in that they must first be hydrolyzed with the aid of enzymes into fermentable sugars [68]. This is an energy intensive process that comes at an increased cost over simple conversion of sugars. Despite this, starches are still an attractive option for biofuel conversion especially if they can be grown sustainably with little impact on food supply. Global bioethanol production continues to rise, going from 28.5 billion liters in 2004 to 94 billion liters in 2014. This accounts for approximately 74% of global liquid biofuel production [66]. This rise in production is reflective of the increased emphasis on alternative liquid fuel options as well as the global movement toward blended fuels. Blended fuels combine traditional fossil fuel based petroleum fuels with bioethanol or biodiesel. E10 is a liquid fuel that blends 10% bioethanol with conventional petrol. The result is a 6% decrease in petrol use, a 2% reduction in greenhouse gas emissions (GHG) and a 3% reduction in fossil energy use [69]. Leading the way in this practice is Brazil, whose use of biofuels in road transport exceeded 20% in 2014. Despite this, the world’s greatest producer of bioethanol is the United States at 58% of total global production. In 2014 alone, the United States produced 54.3 billion liters of bioethanol. This was followed by Brazil, which produced 26.5 billion liters. No other country produced more than 3 billion liters [66]. Good corn and sugar cane yields in recent years continue to drive the increase in first generation bioethanol production. This along with the low cost of crude oil is maintaining production costs at a low level and driving this industry to the forefront of alternative liquid fuels [66].

1.21.6.1.2

Biodiesel

Biodiesel is the second most common alternative liquid fuel generated from first generation biofuel feedstocks. While animal fats can and are used, the most common feedstock in biofuel conversion is vegetable oils. Vegetable oils contain phospholipids, water, sterols, free fatty acids, odorants, and other physical and chemical impurities. These make the use of vegetable oils as a fuel impossible without a conversion process. Biodiesel is thus produced through a transesterification process that reacts oils and fats with a monohydric alcohol and a catalyst. There are a number of factors influencing the quality and speed of the reaction including the nature of the alcohol used in the reaction, the molar ratio of alcohol to oil, the length of the reaction, the amount and nature of the catalyst, reactant purity, and temperature [70]. Global production of biodiesel reached 29.7 billion liters in 2014. This number was up from 2.4 billion liters in 2004, serving to show the increased demand for biodiesel based on consumer preference and the increasing focus on blended fuels. Many of the same requirements globally for blended ethanol fuels are also in place for biodiesel. This has the result of keeping demand high while offering room for expansion of the technology as more countries adopt policies requiring fuel mixtures that incorporate alternative fuels [66].

1.21.6.1.3

Corn as a first generation biofuel feedstock

Of the varied first generation biofuel feedstocks, corn is by far the most prevalent. Best estimates suggest that corn makes up around 95% of total bioethanol feedstock inputs [71]. With the increased emphasis being placed on blended fuels the importance of this resource should not be underestimated. The primary reason for corn’s applicability to the bioethanol industry is its elevated starch content. Starch within the corn kernels accounts for 72%–73% of the total weight of the kernel. In addition to this, corn kernels also contain simple sugar carbohydrates such as glucose, fructose, and sucrose in a content around 1%–3% total weight [72]. A profile of total carbohydrate percentage for a variety of corn species can be observed in the table below (Table 4). It is this elevated carbohydrate content of corn that makes it such an attractive option for bioethanol conversion. 1.21.6.1.3.1 Conversion of corn to bioethanol The generation of corn-based bioethanol begins with the receiving and processing of the grain. The received corn is thoroughly cleaned along with having any broken kernels or foreign materials removed from the feedstock. From here the corn is milled using

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Table 4

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Carbohydrate percentage for a variety of corn species

Corn species

Carbohydrate percentage (% of total kernel weight)

Salpor Crystalline Floury Starchy Sweet Pop Black

75.9 70.3 70.4 72.8 69.3 66.0 75.9

Source: F.A.O. Maize in human nutrition. Rome: Food and Agriculture Organization of the United Nations; 1992.

a hammer mill, which grinds the corn into a more usable powder form. The corn powder is then transferred to a slurry tank along with large amounts of process water. To this slurry a combination of thermostable alpha-amylase, ammonia, and lime are added in preparation for the liquefaction stage. The liquefaction occurs through the use of a steam injection heater which has the effect of first gelatinizing and then hydrolyzing the starches present in the slurry into oligosaccharides or dextrins. This causes a rise in the viscosity of the slurry during the gelatinization phase, which must be properly accounted for. The viscosity of the slurry will decrease as the starch becomes hydrolyzed. Liquefaction is typically performed at a pH around 6.5 for 1 h at 881C while providing adequate mixing via mechanical agitation. The output from this liquefaction stage is then combined with backset (a liquid/solid mixture separated via centrifugation later in the bioethanol production process), which provides nutrients essential to the proper function of the yeast during the fermentation process. The newly formed mixture is then heated to 1101C for 15 min in preparation for transfer to the saccharification tank [73]. Once in the saccharification tank, sulfuric acid is added to the mixture in order to lower the pH to 4.5. During this saccharification stage, glucoamylase is also added to the mixture and the entire slurry is maintained at 611C for a period of 5 h. The glucoamylase has the effect of converting nearly all of the oligosaccharides into glucose. With that being said, should there remain oligosaccharides that have not been fully hydrolyzed into glucose within the slurry, then the glucoamylase will continue to perform its function throughout the fermentation process resulting in the highest possible conversion efficiency. The slurry is then cooled to 321C in preparation for the fermentation process [73]. Fermentation is a reaction caused by yeast that converts sugars (such as the glucose present following the hydrolyzation process) into ethanol and carbon dioxide. Depending on the nature of the slurry and the yeast the residence time will need to be varied in order to attain the highest possible conversion efficiencies. The fermentation process results in a liquid often referred to as “beer.” This beer is then sent to a degasser drum in order to flash off the vapor. The flashed-off vapor contains primarily ethanol and water, however some carbon dioxide is also present in the mixture. The vapor is then condensed, effectively separating the water/ethanol mixture from the carbon dioxide. What is left at the bottom of the fermentation tank following completion of the fermentation process is known as stillage and is what will become the backset. The backset is prepared by removing water from the stillage, resulting in a solid/liquid mixture of around 37% solids. This mixture is then returned to the liquefaction stage of a subsequent batch [73]. Following the fermentation stage there remains a large amount of water present alongside the ethanol, which must be separated out. The beer is transferred to a distillation column, which begins the separation process; however there still remain large amounts of water, protein, oil, fiber, and residual chemicals following this step. The beer is then sent to the rectifier, which separates out around 99% of the ethanol as distillate. What is left in the rectifier is sent to a stripper, which separates out the remaining ethanol from the water. Both samples are then recombined and fed through a molecular sieve, which separates out nearly all of the water. The product at this stage is in excess of 99.6% pure ethanol. The resultant ethanol is then mixed with 5% gasoline and stored for a period of time before making its way onto the market as a fuel additive [63].

1.21.6.1.4

Social impact of first generation biofuels

The development of the first generation biofuel industry has often been described as being one of “riches to rags” [74]. This statement was made in response to the rapid development of the technology with little concern for how it affected various other aspects of the environment, economy, and social wellbeing. During the mid-2000s, development of first generation biofuels was increasing dramatically. With the increase in production however came increased attention and greater public awareness of the technology. As a result, the linkage between biofuel production and food prices was made. As one would imagine, as more and more food crops were being directed toward biofuel production, the increase in the food prices of these same crops began to rise as market supply decreased. This was not taken well by the public as many felt that cheaper, existing fossil fuels were the answer regardless of their environmental effects. The issue came to a head during the food price crisis of 2007–08, which promised increasing food prices in the years to come as a result of the increased emphasis on biofuel production. While in agriculturally rich countries this was largely not an issue, many net food importers began to feel the sting of the biofuel revolution [75]. The term “energy crop” took on a negative connotation that to this day remains present. This was the dawn of the food versus fuel debate, which continues to rage on.

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As much the issue as food prices is that of land usage. When it comes to this issue there are two schools of thought. The first is that food and fuel are inherently linked. In order to produce food on a large scale there is at the same time a large requirement for fuel. This argument justifies the use of the best cropland for the production of energy crops as the return will be cheaper fuel, which allows for greater and improved production on remaining cropland [76]. Additionally, the use of biofuel production byproducts as soil amendments should be considered on a greater scale whether for food or energy crop production [77]. These unique approaches could serve to reduce the divide between food and energy crops. With that being said they are not without their issues. Taking the first remedy as an example, the question that arises is whether this actually solves the issue. It could be that using biofuels as a means of reducing production costs does not reduce the cost of production low enough to where it makes up for the reduction in market supply. This is where further research is required in order to properly determine the effect of potential remedies and policies.

1.21.6.2

Second Generation Biofuels

Second generation biofuels encompass all biofuels derived from field crops not generally considered to be food crops. These feedstocks aim to solve the major issue associated with first generation feedstocks in that they directly compete with global food supplies. Second generation feedstocks do not have this issue as they are derived from noncompeting, conventionally undesirable, and what are now being termed “energy” crops. With that being said, these feedstocks are not entirely perfect either. Second generation feedstocks still require large amounts of land to grow. This is often land that could otherwise be used to grow food. Therefore, while they do not directly remove food from the market, they do indirectly affect food supply by occupying valuable agricultural lands. This is why there is a call to find energy crops capable of growing and thriving on marginal lands. As mentioned, when it comes to biofuel conversion, feedstocks high in carbohydrates such as sugars and starches as well as feedstocks high in oils and fats are the most desirable. Unfortunately, the crops that are highest in these components are often the same crops that are considered as foods. The challenge then becomes finding crops that do not affect the food supply while at the same time are locally profitable. The result is that many second generation feedstocks are crops lower in carbohydrates and oils, and higher in lignocellulosic compounds. These woodier crops are not as desirable as the conversion process to biofuels is more costly and energy intensive [63]. If the additional cost is incurred then the end product can be quite similar to any other biofuel product. While there are a number of already identified second generation biofuel feedstocks, further research is required to find acceptable local options for more regions globally. Some crops already identified as having great potential in the proper situation include castor bean, jatropha, camelina, switchgrass, and poplar. Despite the promise of these crops there remains the overarching issue that they are still land competing. While some may be able to take advantage of marginal land, it is not to say that this land could not be remediated to some capacity for food production. This will always be a cloud over second generation biofuels regardless of the source. Therefore, while second generation biofuels do help to solve the problem, they do not entirely mitigate the issue at hand. Second generation biofuels are fuels often derived from the woodier, lignocellulosic portions of plant materials. These portions are generally derived from grasses, stalks, stems, and wood of noncompeting food crops or as leftovers following the processing of a food crop. The lignocellulosic nature of these feedstocks refers to their composition in that they are comprised largely of cellulose, hemicellulose, and lignin. While cellulose and hemicellulose can both be hydrolyzed, it is the lignin that causes many of the problems associated with lignocellulosic biofuel conversion. This is due to the fact that lignin cannot be efficiently broken down resulting in additional treatment costs when attempting to use lignocellulosic crops high in lignin. Pretreatment of these feedstocks is required to break the lignin seal and alter the crystalline structure of the surrounding cellulose if the feedstock is to be used in biofuel conversion. This is an essential step as the lignin acts as a protective barrier that can greatly inhibit the ability to hydrolyze the cellulose and hemicellulose of the feedstock [78]. It is for this reason that crops lower in lignin and higher in cellulose and hemicellulose are preferential for biofuel conversion. As an essential step in the utilization of second generation biofuel feedstocks the pretreatment aims to meet the following four requirements. Firstly, the pretreatment must improve the ability to form sugars or improve the efficiency of the hydrolysis process as it pertains to cellulose and hemicellulose. Secondly, the pretreatment must avoid the degradation of carbohydrates available within the feedstock. Thirdly, the pretreatment process must avoid introducing potentially detrimental byproducts that would serve to complicate and inhibit the subsequent hydrolysis and fermentation processes. Finally, the entire process must be performed efficiently and cost effectively [78]. Table 5 shows four distinct second generation biofuel feedstocks along with their lignin, cellulose, and hemicellulose contents by dry weight. With all of this being said, there is still a call to find nonfood competing energy crops that are high in carbohydrates and oils. While cellulose and hemicellulose can be processed, they are evidently suboptimal. Nonfood competing crops high in oils and carbohydrates and that also possess the ability to grow in marginal lands is the optimal goal for today’s researchers. Finding locally profitable crops with these characteristics has the ability to completely change the global biofuel profile.

1.21.6.2.1

Emerging second generation biofuel feedstocks

1.21.6.2.1.1 Camelina Camelina is an emerging second generation biofuel feedstock known largely for its high oil content. Oil contents within the crop can range from 35% to 43% based on a number of factors including genotype, weather, soil conditions, fertilizer inputs and location [79–81]. Camelina has the additional benefits of being tolerant to drought, cold, and insects as well as having a relatively short growing season when compared with other biofuel feedstocks. Furthermore, it has been suggested that camelina-based biofuels are more environmentally friendly than alternative biofuels when you consider the lower input and processing

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Table 5

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Comparison of lignin, cellulose, and hemicellulose in four different second generation biofuel feedstocks

Plant

Cultivar

Lignin (% dw)

Cellulose (% dw)

Hemicellulose (% dw)

Miscanthus Switchgrass Sorghum Reed

Miscanthus sinensis Panicium virgatum L. Sorghum bicolor Phragmites australis

18.73 18.2 19.3 26.2

32.02 34.37 33.15 30

25.33 24.7 23.5 23.8

Source: Jung S, Kim S, Chung I. Comparison of lignin, cellulose, and hemicellulose contents for biofuels utilization among 4 types of lignocellulosic crops. Biomass Bioenergy 2015;83:322–7. Miscanthus – average of 4 different collection sites. Switchgrass – average of 3 different collection sites. Sorghum – average of 2 different collection sites.

requirements [82–85]. These aspects serve to provide camelina with a distinct advantage over other traditional biofuel crops: the potential for biannual harvesting. Under the proper growth conditions a complete cropping cycle takes from 85 to 100 days. Given that this crop also responds well to lack of water and cold weather the acceptable growing season is much longer than that of many first generation biofuel sources. What this all means is that two harvests are possible within the same year given proper management. This has the potential to drastically increase yields by as much as double [85]. However, there remains the issue of cropland. In order to provide camelina with the best chance at success and multiple harvests, it must be provided with acceptable cropland. This means that it is displacing food crops and indirectly affecting food supply. Research on camelina is still in its relative infancy and as with any other crop it would only be viable in particular regions. Currently, genetic research is being performed on camelina in order to increase oil content, improve seed yield, and allow for greater adaptability to a wider array of climates. 1.21.6.2.1.2 Jatropha Jatropha seed is a crop gaining more and more attention for a variety of reasons including biodiesel production. This is because of the elevated oil contents within the seeds, which can be as high as 25%–35% [86]. It is not only this high oil content that makes jatropha attractive though. Jatropha is a highly adaptable crop that grows perennially, is drought resistant, and has the ability to grow in limited nutrient conditions in arid or semiarid environments [87]. This highly adaptable crop serves to provide a potential solution to the ever present food versus fuel debate as it is not considered as a food crop nor does it have to compete for agricultural land. This makes jatropha an attractive biofuel conversion option however much is still unknown about this crop. This comes down to the fact that jatropha is still largely an undomesticated tree, which results in it being highly unpredictable in its growth and development [86]. This makes predicting oil yields quite difficult if not impossible given the drastic variations in accumulations. Additionally, even though jatropha can grow in arid and semiarid conditions, this does not mean that these are its optimal conditions. As such, the lack of nutrients and harsh environmental conditions can serve to lower lipid accumulation [88]. The other issue that jatropha faces is that despite its ability to deal with drought and lack of nutrients it is highly temperature sensitive. Being that jatropha is a tropical crop it thrives in mean annual temperatures of 26–271C. In addition to this, jatropha also requires annual mean minimum temperatures to remain above 81C. As expected, jatropha is highly sensitive to frost, which can result in the death of the plant [86]. What this all means is that jatropha is an excellent second generation biofuel feedstock for a very specific region of the globe. It encounters many of the same issues other second generation biofuel feedstocks do in that it is highly localized. Despite this, for regions that can produce the crop effectively it is an excellent option. 1.21.6.2.1.3 Castor bean Castor bean (Ricinus communis L.) represents yet another promising second generation biofuel for a variety of reasons. The first and most important reason is its high oil content. Castor bean oil content ranges from 45% to 58% given a variety of environmental factors [89]. Castor bean is also highly adaptable to a variety of environments, growing naturally in many tropical and subtropical countries on what would generally be considered to be marginal land [90]. Castor bean is also a perennial crop that is highly inexpensive to implement and maintain when compared with its direct competitors. It has been estimated that the cost of building and maintaining a castor bean plantation is around 50% less than that of rapeseed and 25% less than that of jatropha [91]. It is this inexpensiveness coupled with high oil yields that make castor bean such an attractive option. While castor bean may seem like the ultimate answer to the question of a sustainable, second generation biofuel crop, it too is not without its flaws. The issue with castor is that it is comprised of around 80%–90% ricinoleic acid. The major issue with this is that it drastically increases the viscosity of the castor oil. Research suggests that castor oil can be as much as seven times more viscous than that of other similar vegetable oils. This creates a complication where biodiesel derived from castor bean cannot be incorporated into many modern bio/petro fuel blends. With that being said, it can be combined with other biodiesels such as soybean and subsequently blended with petrodiesel in order to account for the viscosity issue [92]. Given the proper situation, one in which another biodiesel is produced alongside castor bean, the potential for this crop as a second generation biofuel feedstock is certainly promising. Its low cost, coupled with its perennial growth and high oil yield, certainly make it a crop worth further consideration and research.

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Table 6 Recipe for a Big Mac sandwich (Sweden 1999), based on the personal communication by Carlsson-Kanyama and Faist Ingredient

kg hamburger

Bread Ground beef Sauce Lettuce Onions Pickles Cheese

0.0740 0.0900 0.0200 0.0280 0.0017 0.0074 0.0145

1

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

Table 7 of bread

High and low energy estimates for the production of 0.0740 kg

Process

Low estimate (MJ)

High estimate (MJ)

Production and drying Milling Baking Storage Transportation Total

0.17 0.03 0.45 0.31 0.07 0.96

0.24 0.39 1.00 1.60 0.09 3.20

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

1.21.7

Case Study: The Energy Cost of a Hamburger

This case study looks at the energy cost of producing a McDonald’s hamburger by focusing on the work performed by CarlssonKanyama and Faist [93]. Their study looked at a number of factors focused around energy use in the food sector. The data presented in this case study examines one aspect of their work. In an attempt to quantify the energy requirement to produce a single hamburger, one must first consider the components required to produce the product. The examined product in this case is the Big Mac sandwich from McDonald’s. The contents and amount of each component of the Big Mac are outlined in Table 6.

1.21.7.1

Bread

The first component examined is that of the bread. There are a number of production and processing steps that must occur prior to the final product being sold at the restaurant. In this case study, crop production and drying, milling, baking, storage, and transportation were all considered to be significant contributors to the energy profile for bread. High and low estimates of energy consumption were given for each of the processes and can be observed in Table 7. Taking these figures into account, it can be concluded that the energy requirement for the production of bread ranges from 13 to 44 MJ per kilogram. Baking and storage represent the most energy intensive processes as a result of the drastic temperature control requirements for the two processes. Transportation is the least energy intensive process likely due to the low weight and local availability of inputs. It should be noted that this example assumes the bread is frozen during the storage phase. If this is not the case then the energy requirement for storage would be significantly lower.

1.21.7.2

Ground Beef

Ground beef production represents the most energy intensive process among all of the ingredients in the Big Mac sandwich. It is also important to note that when calculating the energy requirement to produce ground beef that the energy requirements for feed production also be considered. As such, this study operated under the assumption that meat was attained from spring calves who required 2728 kg of feed in order to attain an appropriate slaughter weight of 265 kg. This results in a feed consumption per kilogram of weight of approximately 6.4 kg at a dressing yield of 62%, which is toward the high end for beef cattle. Estimates of the feed for the beef cattle were performed under the assumption that the feed mixture was comprised of barley, fodder peas, and

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Table 8 High and low energy estimates for the production of 0.0900 kg of ground beef Process

Low estimate (MJ)

High estimate (MJ)

Feed production Butchering Grinding/freezing Storage Frying Transportation Total

3.50 0.23 0.12 0.45 0.79 0.44 5.60

5.00 1.40 0.16 2.30 1.00 0.59 10.0

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

Table 9 lettuce

High and low energy estimates for the production of 0.0280 kg of

Process

Low estimate (MJ)

High estimate (MJ)

Crop production Storage Transportation Total

0.04 0.02 0.04 0.09

4.27 0.05 0.04 4.36

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

hay. This study also assumed that there were zero production losses during feed production. The energy requirements for ground beef production can be observed in Table 8. Based on the assumptions and collected data the analysis results in an energy consumption in the range of 62 to 116 MJ per kilogram of ground beef produced. Feed production makes up the largest portion of the energy profile largely due to the massive feed requirement for beef cattle to reach slaughter weight. For comparison purposes, the same storage and transportation requirements were used as for bread.

1.21.7.3

Sauce

As no recipe could be attained for the sauce, the energy requirement for its production was omitted from the analysis.

1.21.7.4

Lettuce

The energy requirement for lettuce production is one that varies greatly dependent on the nature of the growth environment. For instance, growing lettuce outdoors in a field has a considerably lower energy cost than growing it in a greenhouse does. For this reason the estimates for the energy requirement in lettuce production encompasses quite a broad range. These energy requirements can be observed in Table 9. The energy effect of growing lettuce in a greenhouse environment can quickly be observed by the high estimate for crop production. In this case, the energy requirement to produce one kilogram of lettuce would be 160 MJ. When compared with lettuce grown in an outdoor environment whose energy cost is 3.4 MJ per kilogram, the drastically superior nature of the outdoor process can be observed. The aspects of storage and transportation are fairly negligible in contributing to the energy profile of greenhouse production, but serve to make up a fairly substantial portion of the comparably small profile for outdoor growth.

1.21.7.5

Onions

Unlike the other ingredients in the sandwich, the onions are freeze dried prior to their incorporation in the hamburger. Freezedrying adds another energy intensive step to processing that must be taken into consideration for the total energy profile. It should be noted that this study used a ratio of 12:1, meaning that 12 kg of fresh onions produces 1 kg of freeze-dried onions. The total energy profile for the onion component of the sandwich can be observed in Table 10. From Table 10 it can quickly be observed that freeze-drying makes up between 60% and 72% of the total energy profile. This step drastically increases the energy cost of onion production as production, storage, and transportation make up considerably smaller portions of the total profile. This estimate yields a per kilogram profile for onion production in the range of 32–62 MJ. This

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Table 10 of onions

High and low energy estimates for the production of 0.0017 kg

Process

Low estimate (MJ)

High estimate (MJ)

Crop production Freeze-drying Storage Transportation Total

0.0120 0.0410 0.0039 0.0085 0.0570

0.0150 0.0730 0.0093 0.0109 0.1200

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

Table 11

High and low energy estimates for the production of 0.0074 kg of pickles

Process

Low estimate (MJ)

High estimate (MJ)

Crop production Storage Pickling Transportation Total

0.0074 0.0008 0.0200 0.0140 0.0460

0.0097 0.0074 0.0320 0.0072 0.0560

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

amount could be drastically reduced with improvements to freeze-drying techniques as well as revaluating the importance of freeze-drying and considering alternative methods.

1.21.7.6

Pickles

Pickles are a food product derived from cucumbers. In this example, energy values were attained by considering typical energy values for canning and jarring of fruits and vegetables. In addition to that, it was also assumed that all cucumbers were grown in an outdoor environment. The energy profile for pickle production can be observed in Table 11. From Table 11 it can be observed that pickling makes up the greatest proportion of the energy profile in pickle production accounting for 43–57% of the total demand. Based on the estimates in this study, the energy requirement for pickle production ranges from 6.2 to 7.6 MJ per kilogram. It should be noted that for cucumbers produced in a greenhouse, the energy requirement would be much higher. Consider the same increase in energy consumption we observed between the high and low estimates for lettuce production. Using this increase, the new energy demand for cucumber production would be 0.79 MJ per 0.0074 kg of pickles. This would yield a high end per kilogram energy requirement of approximately 106.8 MJ, demonstrating the drastic effect on energy consumption for greenhouse production.

1.21.7.7

Cheese

Similar to the energy profile for ground beef, one must consider the feed requirements for dairy cows in the production of cheese. In addition to this, there were two important assumptions in determining cheese’s energy profile. The first is that it requires 12 kg of milk in order to produce 1 kg of cheese. The second assumption was that it required 5820 kg of feed to produce 7300 kg of milk in a year. The energy profile for cheese can be observed in Table 12. Taking Table 12 into consideration it can be concluded that cheese accounts for 38–62 MJ of energy per kilogram to produce. The largest contributors to the profile are the production of feed followed by the actual cheesemaking process. Storage was less of a consideration for cheese as it was concluded that the majority of cheese was stored in temperature appropriate caves and caverns throughout Sweden. This served to drastically reduce the requirement for refrigeration, which would be necessary for regions that do not have access to such caves.

1.21.7.8

Total Energy Profile

Taking all aspects of the hamburger into consideration, it can be concluded that a single hamburger requires 7.3–20 MJ of energy input dependent on a variety of production factors. The greatest contributors to this profile are the ground beef and lettuce, if the lettuce was produced in a greenhouse. Due to the elevated energy requirements associated with beef production [94], maintaining the same recipe in an attempt to lower energy costs would be a challenge. With that being said, utilizing more parts of the animal along with introducing more energy efficient meat sources such as chicken or turkey into the hamburger mixture could be an

Food and Energy

Table 12

871

High and low energy estimates for the production of 0.0145 kg of cheese

Process

Low estimate (MJ)

High estimate (MJ)

Crop production and drying Milking and cheese making Storage Transportation Total

0.26 0.16 0.01 0.11 0.54

0.37 0.32 0.07 0.15 0.9

Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

Table 13 livestock.

Kilograms of grain and forage input per kilogram meat output for various

Livestock

Grain (kg)a

Forage (kg)b

Lamb Beef Chicken Turkey Pork

21.0 13.0 2.3 3.8 5.9

30.0 30.0 – – –

a

[95]. [96,97]. Source: Carlsson-Kanyama A, Faist M. Energy use in the food sector: a data survey. Stockholm, Sweden: Swedish Environmental Protection Agency; 2000.

b

option to reduce energy inputs. Table 13 shows the grain and forage requirement for various livestock. Lamb and beef require both grain and forage whereas chicken, turkey, and swine require only grain. What can quickly be observed are the drastic differences in feed conversion to weight for beef when compared with more energy efficient choices such as pork, turkey, and chicken. Being that feed requirements for ground beef make up anywhere from 50 to 62.5% of the energy input in ground beef production [93], adding meats with better feed to weight conversion ratios represents one major avenue for improved energy efficiency. With that being said, for businesses such as McDonald’s, this is not likely to happen as they have an already established recipe and a high demand for it. Should a new recipe come at a drastically reduced cost (i.e., cheaper meat sources as a result of lower input costs), then there is the potential that some shift may occur. A second and more likely area for energy efficiency improvements comes in the form of lettuce production. From what can be observed in Table 9, there is a drastic difference between the high and low estimates for lettuce production. This difference comes as a result of the environment in which the lettuce is produced. In the above study, lettuce was produced in Sweden, a temperate climate suitable for outdoor lettuce production during the warmer months of the year. In this case, it was stated that it was far more energy efficient to produce lettuce outdoors than in a greenhouse environment. This can be somewhat misleading though, as the efficiency of each of the systems is variable based on a number of factors, especially that of climate. Consider the same lettuce produced in a much hotter and drier climate such as Arizona. Lettuce grown hydroponically in a greenhouse can expect yields 1171.7 times greater while utilizing 1372.7 times less water than conventional outdoor growing practices [98]. Taking the improved production and reduction in water consumption into account may result in a different outcome considering total efficiency. Despite this, the energy requirement for lettuce produced in a greenhouse remains much higher regardless of the environment. Hydroponically produced lettuce in Arizona was found to require 82711 times more energy per kilogram of lettuce produced than conventional outdoor methods [98]. While this number is quite high, it may be justifiable for an area such as Arizona, where reduction in freshwater usage may be seen as a more important environmental issue than energy expenditure.

1.21.8

Closing Remarks

The connection between food and energy is one that is impossible to separate. It is known that all energy on Earth has its roots in the Sun and it is this energy that is converted and altered to produce all of the food humans enjoy today. Whether it is plant and livestock production or the conversion of food to energy, these processes simply serve as demonstrations of the link food and energy share. The first law of thermodynamics dictates that energy cannot be destroyed but rather can only change forms and perhaps nowhere is this more apparent than with food. Growth of plants, digestion in humans and animals, and biofuel conversion all represent changes in energy form critical to the success of their processes. The energy inherent to food is an aspect that deserves great attention as optimization and management could be critical in feeding and fueling an ever-growing population.

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Environ Sci Technol 2008;42(10):3508–13. Pimentel D, Pimentel MH. Food, energy, and society. Boca Raton, FL: CRC press; 2007. Rodriguez‐Gonzalez O, Buckow R, Koutchma T, Balasubramaniam V. Energy requirements for alternative food processing technologies – principles, assumptions, and evaluation of efficiency. Compr Rev Food Sci Food Saf 2015;14(5):536–54. Hall GM, Howe J. Energy from waste and the food processing industry. Process Saf Environ Prot 2012;90(3):203–12. Rahman MS. Handbook of food preservation. Boca Raton, FL: CRC press; 2007. Evans J, Gigiel A. Reducing the energy consumption in cold stores. In: The 22nd IIR international congress of refrigeration. Beijing, China; 2007. Evans J, Gigiel A. Reducing energy consumption in cold storage rooms. Cambridge: IIR ICCC; 2010. p. 29–31. Froid et alimentation: Sécurité, sûreté ou procédé. Conférence Centenaire du froid; 2008. Klippstein R.N. The true cost of home food preservation. Information bulletin/. 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A comparative study on intermittent heat pump drying process of Chinese cabbage (Brassica campestris L. ssp) seeds. Food Bioprod Process 2013;91(4):381–8. Chin SK, Law CL. Product quality and drying characteristics of intermittent heat pump drying of Ganoderma tsugae Murrill. Dry Technol 2010;28(12):1457–65. Datta AK. Handbook of microwave technology for food application. Boca Raton, FL: CRC Press; 2001. Chandrasekaran S, Ramanathan S, Basak T. Microwave food processing – a review. Food Res Int 2013;52(1):243–61. Datta AK, Davidson PM. Microwave and radio frequency processing. J Food Sci 2000;65(s8):32–41. Canning PN. Energy use in the US food system. Collingdale, PA: Diane Publishing; 2011. Lipinski B, Hanson C, Lomax J, et al., Reducing food loss and waste. World Resources Institute Working Paper; 2013. US Energy Information Administration. How much electricity does an American home use? 2015. Rosegrant MW, Msangi S. Consensus and contention in the food-versus-fuel debate. 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Relevant Websites https://books.google.ca/books?isbn=3642552625 Convergence of Food Security, Energy Security and Sustainable Agriculture. https://books.google.ca/books?isbn=9251010889 Energy Cropping Versus Food Production. http://michaelminn.net/geography/2009-food-energy/2009-05-11-food-energy.pdf Energy Use in American Food Production. https://books.google.ca/books?isbn=3319167812 Energy Use in Global Food Production: Considerations for Sustainable Food Security in the 21st Century. https://books.google.ca/books?isbn=1437930336 Energy Use in the U.S. Food System. https://books.google.ca/books?isbn=9251050147 FAO Food and Nutrition Paper - Issue 77. https://books.google.ca/books?isbn=0323157645 Food and Energy Resources. https://books.google.ca/books?isbn=1420046683 Food, Energy, and Society, 3rd ed. https://books.google.ca/books?isbn=1139495127 Food, Energy and the Creation of Industriousness: Work and Material Culture in Agrarian England, 1550–1780. https://books.google.ca/books?isbn=012800374X Food, Energy, and Water: The Chemistry Connection. http://www.gracelinks.org/118/energy-and-agriculture GRACE Communications Foundation.

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https://books.google.ca/books?isbn=1118913051 Introduction to the US Food System: Public Health, Environment, and Equity. https://books.google.ca/books?isbn=131727783X The Water, Food, Energy and Climate Nexus: Challenges and an Agenda for Action.

1.22 Biofuels Yas- ar Demirel, University of Nebraska Lincoln, Lincoln, NE, United States r 2018 Elsevier Inc. All rights reserved.

1.22.1 Introduction 1.22.2 Background and Fundamentals 1.22.2.1 Biomass 1.22.2.2 Biofuel and Conversion Processes 1.22.3 Biorefinery Systems 1.22.4 Conversion Processes 1.22.4.1 Biochemical Processes 1.22.4.2 Chemical Processes 1.22.4.3 Thermochemical Processes 1.22.4.4 Hydrothermal Liquefaction 1.22.5 Biofuels 1.22.5.1 Biohydrogen 1.22.5.2 Bioethanol 1.22.5.2.1 First generation bioethanol 1.22.5.2.2 Second generation bioethanol 1.22.5.2.2.1 Second generation bioethanol by biochemical processes 1.22.5.2.2.2 Second generation bioethanol by thermochemical processes 1.22.5.3 Fischer–Tropsch Diesel 1.22.5.4 Biobutanol 1.22.5.5 Biomethanol 1.22.5.5.1 Biomethanol from sewage sludge 1.22.5.6 Biodimethyl Ether 1.22.5.7 Biodiesel 1.22.5.7.1 Biodiesel from plant oils 1.22.5.7.2 Green diesel 1.22.5.7.3 Biodiesel from algae 1.22.5.7.4 Nutrient recovery from municipal wastewater for algae-based biofuel production 1.22.5.7.5 Jet fuel from camelina 1.22.6 Further Discussions 1.22.6.1 Comparison of Biomass Used for Bioethanol Production 1.22.6.2 Chemical and Fuel Properties of Biofuels 1.22.6.3 Energy Efficiencies of Biofuels 1.22.6.4 Renewable Fuel Standard 1.22.6.4.1 Categories of renewable fuel 1.22.6.5 Biofuel Assessment Models 1.22.6.5.1 Life cycle assessment 1.22.6.5.2 Risk assessment for biofuels 1.22.6.6 Right Way to Use Biofuels 1.22.6.6.1 Safety of biofuels 1.22.6.6.2 Economic assessment of biofuels 1.22.6.6.3 BioBreak model for second generation biomass feedstock 1.22.6.6.3.1 Willingness-to-pay for lignocellulosic bioethanol production 1.22.6.6.3.2 Willingness-to-accept for lignocellulosic bioethanol production 1.22.6.6.4 Optimum cost of algae biomass 1.22.7 Case Studies 1.22.7.1 Biohydrogen Production 1.22.7.2 Biomethanol Production 1.22.7.3 Biodimethyl Ether Production 1.22.7.4 Methyl Dodecanoate (Biodiesel) 1.22.8 Future Directions 1.22.9 Closing Remarks References Further Reading Relevant Websites

876 877 877 877 878 880 880 880 881 881 882 882 883 883 883 883 884 884 885 885 886 886 886 886 887 887 888 888 889 889 890 890 892 892 892 893 893 893 893 893 894 895 895 898 899 899 900 902 902 903 904 905 907 907

Comprehensive Energy Systems, Volume 1

875

doi:10.1016/B978-0-12-809597-3.00125-5

876

Biofuels

Nomenclature CAlgae CES CHM CI CO COpp CS D DFC DVC Ebiodiesel Ebiogas Epetroleum

The maximum acceptable cost of algae, US$ t 1 Establishing and seeding cost Harvest and maintenance cost, US$ Investment cost, US$ Operating cost, US$ Opportunity cost, US$ Biomass storage cost, US$ t 1 One-way transportation distance, km Transportation fixed cost, US$ km 1 Transportation variable cost, US$ km 1 Average energy content of biodiesel, MJ t 1 Energy content of biogas MJ m 3 Energy contained in a barrel of petroleum, MJ barrel 1

Abbreviations CHST Cost of collection harvesting, storage and transportation, US$ t 1 CLSG Chemical-looping steam gasification CNR Nutrient replacement cost, US$ t 1 DDGS Dried distillers’ grain solubles DMC Dimethyl carbonate DME Dimethyl ether EROI Energy Return on Investment, US$ t 1 FAPRI Food and Agricultural Policy Research Institute FASOM Forest and Agricultural Sector Optimization Model FDA Food and Drug Administration F–T Fischer–Tropsch GGE Gallon of gasoline equivalent GHG Greenhouse gas GTAP Global Trade Analysis Project

1.22.1

EV G M PG Pgas Poil Q T VCP VO w YB YE

HHV ICI LCA LHV LPG MeOH NREL POLYSYS RFS RIN SRWC TEA TEAM USDA WTA WTP

Energy equivalent factor Government incentives Mass of algae, t Price gap: WTA-WTP, US$ t 1 Price of gas US$ L 1 Price of oil US$ barrel 1 Biogas volume produced by anaerobic digestion (400 m3 t 1) Tax credit, US$ t 1 Coproduct production, t Octane benefit, US$0.1 gal 1 Oil content of algae biomass, % Biomass yield, % Conversion ratio

Higher heating value, MJ kg 1 Imperial chemical industries Life Cycle Assessment Lower heating value, MJ kg 1 Liquid petroleum gas Methanol National Renewable Energy Lab Policy Analysis System Renewable fuel standard Renewable identification number Short rotation woody crops Technoeconomic analysis Tools for Environmental Analysis and Management United States Department of Agriculture Willingness-to-accept Willingness-to-pay

Introduction

Secure energy supplies drive technological developments for every nation. Because of the concerns of climate change, renewable energy is pursued as a secure and clean energy source [1,2]. Biofuels must contain over 80% renewable materials such as biomass, which is originally derived from the photosynthesis process. Biomass resources are mainly divided into four types, which are first, second, and third generations, and wastes. The first generation is food-based biomass such as corn, sugarcane, plant, vegetable oils, and fats. The second generation refers to nonfood-type biomass, which includes cellulose and hemicellulose, while third generation biomass mainly refers to algae and cyanobacteria. All these types of biomass can be converted to alcohols, biogas, biooil, biodiesel, and bioproducts by using biochemical, thermochemical, and hydrothermal processes [3,4]. Biofuels are promising alternatives to fossil fuels and are becoming part of sustainable development worldwide because they are produced predominantly from biomass feedstock. Biomass is a renewable resource with carbon sequestered and energy stored with very little sulfur content during the photosynthesis. Therefore, the biofuels have the capability of controlling the greenhouse gas (GHG) emissions and could have a positive impact on climate change. Bioethanol and biodiesel are the most widely used biofuels. Because of the demand for secure energy supplies and concerns of climate change due to the adverse impact of fossil fuels, biofuels are increasing their share in renewable energy usage worldwide as the conversion technologies of biomass to biofuels keep improving and biofuel costs are being reduced [4,5]. Biorefinery systems with multigeneration technology are advancing fast to integrate with the existing infrastructure of energy storage and distribution. This study highlights some recent developments and improvements in the biofuel production processes using various types of biomass feedstock. The main conversion processes including fermentation, transesterification, gasification, and Fischer–Tropsch (F–T) synthesis are analyzed together with economics and safety of biofuel production and usage.

Biofuels

1.22.2

877

Background and Fundamentals

Biofuels are biomass-based energy forms and this section summarizes what kinds of biomass and conversion processes are used to produce various biofuels.

1.22.2.1

Biomass

Biomass feedstock originates from diverse resources including naturally growing terrestrial and aquatic plants as well as natural or human-made wastes. Biomass also has diverse compositions of components including carbohydrates, lipids, lignin, and proteins. Based on this diversity, biomass feedstock is classified into first, second, and third generations, as well as wastes, as seen in Table 1. Lignocellulosic biomass requires large land usage but does not compete with the food supply chain. On the other hand, aquatic biomass does not compete with the food supply chain and land usage either and its cultivation results in a higher yield. Table 2 shows the proximate and ultimate analyses of second generation biomass. The ultimate analysis indicates that the biomass contains between 40% and 53% of carbon and 5% and 6% of hydrogen, while the percentage of ash varies between 0.25% and 12%. Lignocellulosic biomass contains cellulose (38%–50%), hemicellulose (23%–32%), and lignin (15%–25%) [4].

1.22.2.2

Biofuel and Conversion Processes

Although biofuels are mainly considered as liquid fuels, such as bioethanol, biodiesel, and biomethanol, biogas and biopower are also biofuels. Bioethanol and biodiesel have by far the largest share of the global biofuels market. Total bioethanol from surplus corn in the United States and from sugarcane in Brazil reaches around 70% of the global bioethanol production capacity [6–8]. The biofuel supply chain involves the growing/production of biomass, and then harvesting, collecting, storing, and transporting it to the biorefinery where it is converted to biofuel, bioproducts, heat, and power to be distributed to users. The unspecified term biomass usually contains 30% moisture, while the term dry biomass has 10% moisture. Food-based fuels are mainly bioethanol from corn, sugarcane, and biodiesel from plants, vegetable oils, and fats. The technology for these biofuels has reached a certain level of maturity and been accepted by society worldwide. However, the competition of biomass resources with food sources has created a discussion toward technoeconomic analysis and sustainability assessment of such biofuels. Any type of biomass feedstock can be converted to biofuels by chemical, thermochemical, biochemical, and hydrothermal processes. Bioethanol, for example, can be produced either from sugarcane or corn as well as lignocellulosic biomass using Table 1

Comparison of various types of biomass

Generation

Type

Source

Examples

First

Food crops

Second

Lignocellulosic crops

Third

Aquatic

Wastes

Natural

Starch crops Sugar crops Feed Woody Herbaceous Microalgae Macroalgae Water plants Agricultural Forest Municipal Industrial

Corn, wheat Sugarcane, sugar beet, sweet sorghum Grass Short-rotation crops, willow poplar Miscanthus, switchgrass Chlamydomonas rheinhardii, chlorella, spirulina Seaweed Salt marshes, sea grass Animal manure, crop residues Logging residues, tree wastes Solid waste, sewage sludge, waste oil Pulp and paper industry, sludge

Human-made

Table 2

Proximate and ultimate analyses of the second generation of biomass and wastes in wt% and dry base

Biomass type

Fixed C

Volatiles

Ash

C

H

O

N

S

HHVa, MJ kg

Redwood Wheat straw Corn stover Bagasse Sawdust Manure and sludge Municipal waste

16.10 19.80 19.25 14.95 14.33

83.50 71.30 75.17 73.78 76.53

0.40 8.90 5.58 11.27 0.25 38.8 27.1

53.50 43.20 43.65 44.80 40.00 29.9 40.4

5.90 5.00 5.56 5.35 5.98 4.3 4.9

40.30 39.40 43.31 39.55 44.75 22.40 25.30

0.10 0.61 0.61 0.38 0.01 2.90 0.91

0.00 0.11 0.01 0.01 0.01 0.62 0.35

21.03 17.51 17.65 17.33 19.95 13.1 16.5

a

1

HHV: Higher heating values. Source: Reproduced from Demirel Y. Energy: production, conversion, storage, conservation, and coupling. 2nd ed., London: Springer; 2016; Gaur S, Reed T, Teed TB.Thermal data for natural and synthetic fuels. New York, NY: CRC Press; 1998; Ptasinski KJ. Efficiency of biomass energy: an exergy approach to biofuels, power, and biorefineries. New York, NY: Wiley; 2016.

878

Biofuels

First generation biofuel Sugar biomass sugarcane, sugar beet

Second generation biofuel

Starchy biomass corn, wheat

Lignocellulosic biomass corn stover, wood, grass

Biochemical proceses

Sugar extraction

Starch hydrolysis acid/alkaline, enzymatic

Cellulose, hemicellulose hydrolysis Thermochemical processes

Sugar solution, C6 and C5 sugars Biochemical: Fermentation

Bioethanol

Gasification biosyngas Bioethanol synthesis

Bioethanol separation Gasoline/ diesel

Gasoline/ diesel

Pyrolysis biooil

Liquefaction biooil

Fig. 1 Biochemical and thermochemical routes for the first and second generation of biofuels.

biochemical and thermochemical conversion processes. The biochemical process of fermentation converts the first generation biomass of corn, sugarcane, and wheat to bioethanol, while biochemical and thermochemical processes convert the lignocellulosic biomass to bioethanol and other fuels and chemicals. Conversion of lignocellulosic feedstock requires first the complex process of conversion of hemicellulose and cellulose into fermentable sugars and consequently to bioethanol. The cost of the conversion processes of biomass increases in this direction: triglycerides-starch-lignocellulosic, while the cost of biomass increases in this order: lignocellulosic-starch-triglycerides. Fig. 1 shows some of the basic steps of the conversion processes used in biofuel production.

1.22.3

Biorefinery Systems

Biomass can be converted to several renewable carbon compounds such as food/feed, chemicals beside biofuels, heat, and power in a biorefinery concept [9] similar to a currently existing petroleum refinery illustrated in Fig. 2. Since the biomass comes from diverse environments and requires various conversion processes, biorefinery is beneficial in converting various biomass feedstocks into various valuable products in a sustainable manner with positive impacts on economic activity, environment, and society [8]. There are two main operations in a biorefinery: first is the preparation of biomass by separating it into its constituent chemicals such as carbohydrates, triglycerides, protein, and lignin; and secondly converting them into various commodity and specialty products, power, and heat. Conversion processes are biochemical, chemical, thermochemical, and hydrothermal. Biochemical processes mainly refer to fermentation, anaerobic and aerobic digestion using microorganisms. Chemical processes mainly refer to transesterification of lipids, and F–T synthesis of biosyngas (mainly CO and H2) into biofuels [10]. Thermochemical processes refer to gasification, pyrolysis, and reforming, while hydrothermal processes use hot water and catalyst to liquefy various biomass feedstocks to biooil, which requires refining to biofuels. Use of existing petroleum refining and distribution with the biomassbased biooil, plant oil, lignin, biomass waste, and glycerol may be possible for the establishment of biorefinery to deliver jet fuel, diesel, gasoline, olefins, light gas, and liquid petroleum gas (LPG) [11]. The three possible options are [12,13]: 1. Fluid catalytic cracking involves the cracking of alkanes, alkenes, naphthene, and alkyl aromatics to a lighter product, followed by hydrogenation and coking reactions using solid catalyst such as Y-zeolites as binder, and alumina or silica-alumina. An effective H/C ratio of H/C ¼ (H–2O–3N–2S)/C, where H, C, O, S, and N are the moles of hydrogen, carbon, oxygen, sulfur, and nitrogen, respectively, is suggested for the biomass-derived oxygenates using catalytic cracking. H/C ratio is generally low in biomass feedstocks (o0.12). 2. Hydrotreating requires H2 and can convert biomass-based biooil into more stable fuel with more energy density that is ready to blend with petroleum fuels. Hydrotreating adds hydrogen while removing sulfur, and oxygen (hydrodeoxygenation) using cobalt and nickel-based catalysts. 3. Use of biomass-derived syngas or H2 by gasification/reforming to produce H2-rich syngas or pure H2 required in fluid catalytic cracking and hydrotreating.

Biofuels

Renewable resources

Biomass

Biomass

Thermochemical Gasification Hydrotreating

Biomass

Biomass Renewable Energy Wind Solar

Multiple bioproducts

Biochemical, chemical, and thermochemical processes Biochemical Fermentation Transesterification Digestion

879

Food/feed Ethanol Biodiesel Butanol CO,H2

F-T process

Pyrolysis Hydrothermal/ Liquefaction

Methane Gasoline Diesel Biooil Methanol Heat Power

Biological

H2

MeOH production

DME production

MeOH

DME H2

Electrolysis Ammonia H2

Air

Air separation unit

N2

NH3 production

Urea production

DMC production

DMC

N2,O2 Urea Process waste water Fig. 2 Block flow diagram of a biorefinery system for biofuel/bioproduct production from biomass feedstock and renewable resources. CO, carbon monoxide; DMC, dimethyl carbonate; DME, dimethyl ether; F–T, Fischer–Tropsch; MeOH, methanol; NH3, ammonia. Reproduced from Kumar A, Noureddini H, Demirel Y, Jones DD, Hanna MA. Simulation of corn stover and distillers grains gasification with Aspen Plus. Transaction of American Society of Agricultural and Biological Engineers (ASABE) 2009;52:1989–95; Cherubini F. The biorefinery concept: using biomass instead of oil for producing energy and chemicals. Energy Convers Manag 2010;51:1412–21; Phillips S, Aden A, Jechura J, Dayton D, Eggeman T. Thermochemical ethanol via indirect gasification and mixed alcohol synthesis of lignocellulosic biomass. Technical report NREL/TP-510-41168; 2007; Manganaro J, Chen B, Adeosun J, et al., Conversion of residual biomass into liquid transportation fuel: an energy analysis. Energy Fuels 2011;25:2711–20.

The first step to use the cheap and abundant lignocellulosic biomass in a biorefinery is to convert it into alcohols by biochemical or thermochemical processes, biooil by fast pyrolysis or liquefaction. These oils have comparable properties to conventional fuel oil (see Table 3). With a renewable and affordable H2 supply, hydrotreating can convert biooils into diesel and gasoline-type fuels using F–T synthesis. Gasification and upgrading of syngas into liquid “drop-in” fuels are possible at the pilot scale using various biomass feedstocks [14–16]. Catalysts for F–T synthesis are well developed yet sensitive to impurities. As Fig. 2 shows, thermochemical conversion processes are not as feedstock-specific as biochemical conversion, allowing for a wide range of biomass feedstocks to be converted to various biofuels. This provides opportunities for refineries to be built in any location where adequate biomass can be produced to maintain their operations. Methanol (MeOH)-derived fuels include MeOH to gasoline technology, dimethyl ether (DME), dimethyl carbonate (DMC), and other products. Central or distributed biorefineries are considered for using crop residues as biomass feedstock. One particular model considers locally pyrolyzing the biomass into biooil, char, and noncondensable gases, and transporting the biooil to a remote central biorefinery to convert into liquid transportation fuels with around 90% energy efficiency [17].

80 1 0 19 Externalenergy > > < LHV of biofuel = C B B C 1 0 @ produced per 1 kg A @ used in 1 kg biomass A > > Energy efficiency : ; ofbiomass to biofuel conversion C B   @ of biomass to biofuel A ¼ LHV of the 1 kg biomass conversion used in the convesion

ð1Þ

880

Biofuels

Table 3

Comparison of various properties of biomass-based biooils and petroleum-based fuel oil

Property

Biooil by pyrolysis

Biooil by liquefaction

Heavy petroleum fuel oil

Ultimate analysis C H O N Ash Moisture, wt% Specific gravity Higher heating value (HHV), MJ kg-1 Viscosity, cP

54–58 5.5–7.0 35–40 0–0.2 0–0.2 15–30 1.2 16–19 0.2–1

73 8 16

85 11 1 0.3 0.1 0.1 0.94 40 1

5 1.1 34

Source: Reproduced from Czernik S, Bridgewater AV. Overview of applications of biomass fast pyrolysis oil. Energy Fuels 2004;18:590–8; Elliot DC, Schiefelbein GF. Liquid hydrocarbon fuels from biomass. Am Chem Soc Div Fuel Chem 1989;34:1160–6.

1.22.4

Conversion Processes

Biomass is an advantageous feedstock as it contains carbon, oxygen, and hydrogen in a variety of compounds, such as carbohydrate, lipids, and protein. On the other hand, high moisture content and low energy density create problems in biomass transportation and processing. Size reduction of cutting, crushing, and shearing using grinders, shredders, and clippers helps transport biomass in a cost-effective manner. In general, biomass feedstock preparation involves size reduction, densification, drying, and torrefaction. During torrefaction, biomass is heated at 200–300oC under an inert atmosphere to remove moisture and CO2 resulting mass loss of about 30% and energy loss of around 10%. Reduced oxygen content improves gasification of biomass [18].

1.22.4.1

Biochemical Processes

Various enzymes and microorganisms break down and convert organic compounds within biomass feedstocks into alcohols, biogas, biofuel, food/feed, and other chemicals. The chemical reactions in biochemical processes occur at lower temperatures as well as at lower conversion rates compared with the reactions in chemical and thermochemical conversion processes. As a result, biochemical processes are nonpolluting natural processes requiring low energy and few other chemicals. However, suitable process control systems are required to maximize the required product and reduce the side reactions. There are two biochemical processes operated at industrial scales: (1) fermentation of sugars in biomass crops to alcohols, primarily to bioethanol, and (2) anaerobic digestion of biomass and its wastes to methane known as biogas and residue that can be used as fertilizer. Both bacterial (Escherichia coli) (prokaryotic) and eukaryotic (yeast) cells are actively used in batch, fed-batch, or continuous fermentation. Beside these mainline processes, there are dark-fermentation, photofermentation, and others under development to produce H2, valueadded chemicals, and dietary products from various biomass feedstocks [19]. Microbial electrolysis cell is also another process investigated for productions of H2, materials, and electricity [20]. The large-scale biochemical processes are used to produce bioethanol from mainly sugar crops, starch crops, and lignocellulosic feedstock by anaerobic fermentation using yeast. Another large-scale biochemical process is anaerobic digestion of wet biomass feedstock (o15% solid), such as animal manure, agricultural residue, and sewage sludge from municipal waste water treatment to produce methane-rich biogas using bacteria (methanogenic), archaea, and fungi at 37–551C. Biogas has a lower heating value (LHV) of 20–25 MJ Nm 3 and can be used for heating, steam, and consequently electricity production. It can also be used as renewable natural gas after desulfurization and methane enrichment [21].

1.22.4.2

Chemical Processes

The most-used direct chemical process in biofuel production is the transesterification of triglycerides of fatty acids into biodiesel (fatty acid methyl ester) using mainly MeOH or ethanol and a catalyst (mainly acids and alkali-NaOH) [22] and producing glycerin as a byproduct. The general transesterification reaction using MeOH is represented by RCOOR 0 þCH3 OH ¼ RCOOCH3 þ R 0 OH Triglyceride þ Methanol ¼ Mixture of methyl esters þ Glycerin

ð2Þ

Triglycerides are esters of glycerol and are present in oilseed crops, such as soybean, rapeseed, and sunflower, as well as in animal fat. During the transesterification, methyl or ethyl esters of fatty acids are produced and used as biodiesel in compressionignition engines. Waste cooking oil contains free fatty acid and is esterified with alkali (KOH) or acid first before being converted to biodiesel by transesterification [23].

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Hemicellulose and cellulose within the lignocellulosic biomass contain a complex polymer of sugars that are known as polysaccharides (see Fig. 1). Hydrolysis of hemicellulose (C5 pentose units) and cellulose (C6 glucose units) using dilute inorganic acid into simple sugars is the second important chemical process for converting lignocellulosic biomass feedstock into bioethanol. As seen in Fig. 2, other commodity and specialty chemicals can also be produced by several processes in a biorefinery system, such as MeOH and DME. F–T synthesis is another well-known indirect chemical process for producing biofuel from biosyngas, containing mainly CO and H2 and produced from gasification of a biomass. A representative F–T reaction is ð2n þ 1ÞH2 þ nCO-Cn H2nþ2 þ nH2 O

170 kJ mol 1 ðat 250o C and 15 atmÞ

ð3Þ

In the production of diesel fuel “n” can be in the range of 12–25; therefore, a H2 to CO molar ratio of close to 2 is required. An iron-based catalyst and an operating temperature of 3501C will produce mostly gasoline, while a cobalt base and an operating temperature of 2001C will produce mostly diesel fuel. The crude biooil produced in the F–T synthesis is distilled to naphtha, distillate, and wax, which are processed through a series of refining and reforming steps with hydrotreatment and catalytic processes to produce gasoline and diesel at the required configurations [10,17].

1.22.4.3

Thermochemical Processes

Thermochemical conversion processes of combustion, gasification, and pyrolysis take place at high temperatures (450–12001C) and are very common for converting the second generation biomass feedstock and wastes into useful fuels and chemicals. In the indirect biomass gasification, heat for the gasification comes from an external source, while a part of the biomass is combusted in the direct gasification. A biomass, represented by CnH2m, is oxidized to CO2 and water and releases heat of combustion, which can be used to produce steam and electricity in a Rankine cycle. Cn H2m ðn þ 0:5mÞO2 -mH2 O þ nCO2

ð4Þ

In a conventional gasification process, biomass (or other carbon-containing feedstock) reacts with limited oxygen (or air), CO2, and steam at high temperatures (750–11001C) to produce synthesis (biosyngas) containing mainly H2 and CO as well as CO2, methane, and others in small amounts [11]. The following reaction represents the steam gasification (reforming): Cn Hm þ H2 O ¼ nCO þ ðm=2 þ nÞH2

ð5Þ

For dry basis, H2 and CO contents of biosyngas are around 32 vol% and 29 vol%, respectively. After removing impurities (including nitrogen, methane, carbon dioxide) and enriching to the desired ratio of H2 to CO, biosyngas can then be chemically converted into MeOH, ethanol, and other liquid fuels using F–T synthesis. The water–gas shift reaction can increase the hydrogen content from 6% to 6.5% in the initial biosynthesis gas to 30–50 vol% [24]. CO þ H2 O ¼ CO2 þ H2

ð6Þ

Overall yield and energy efficiency are 23%–41% and 32%–51%, respectively, for biomass-based hydrocarbon productions [25]. Purification of the syngas accounts for 60%–70% of the total capital cost. In chemical looping steam gasification (CLSG), an oxygen carrier, mainly a metal oxide, transfers oxygen to a biomass, preventing direct contact between the biomass and air [26,27]. An oxygen carrier such as Fe2O3 binds oxygen in the air reactor and then provides O2 in the fuel reactor to produce the product gas containing mainly CO and H2, as seen in Fig. 3. Thus, the oxygen carrier circulates between the fuel reactor and the air reactor. In CLSG, nitrogen is not allowed to come into contact with the biomass; thus, CO2 does not become diluted by nitrogen, which is a major issue in restricting CO2 capture from diluted CO2 streams by solvents [28,29]. Pyrolysis uses fast heating to high temperatures under anaerobic conditions to break down biomass into a volatile mixture of hydrocarbons. This mixture of hot gases is condensed into a biooil with a rich mixture of hydrocarbons, some of which can be converted into biofuels. The raw biooil is an emulsion, rendering it incompatible with conventional petroleum oils and requiring additional upgrading. Table 3 shows the properties of biooil, which vary based on the conversion process. The most frequently proposed upgrading technology is hydrotreating.

1.22.4.4

Hydrothermal Liquefaction

Hydrothermal liquefaction of biomass also produces biooil through controlled reaction rates and reaction mechanisms using pressure and catalysts [30]. Catalysts used for upgrading liquefaction products include alkali, metals, and nickel and ruthenium heterogeneous catalysts. Hydrothermal liquefaction uses subcritical or supercritical water to liquefy biomass into a biooil (see Table 3). Elevated temperatures (200–4001C) are used in a pressurized vessel containing biomass (5–40 MPa), depolymerizing and converting cellulose, lignin, and hemicellulose into a soluble mixture that can be upgraded and processed in similar fashion as pyrolytic-based biooil [24]. The primary advantage of these liquefaction systems is that they do not require pretreatment and can work with high-moisture biomass feedstocks and municipal waste streams such as sewage sludge and wet algae at much lower temperatures compared with the gasification and pyrolysis processes. Biooil has to be upgraded to fuels in the gasoline and diesel range by hydrodeoxygenation if it were to be used as transportation fuel because of poor volatility, high viscosity, coking, corrosiveness, and poor cold-flow properties [11]. Catalytic upgrading

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Cyclone Depleted air (mainly N2)

Air

Air reactor CO2 Fe2O3 CO2, H2O

Fuel reactor

Condenser

H2O

H2, CO, CH4

FeO

Product gas Gas cleaning

Biomass

Gasification reactor

Fe3O4

Fischer−Tropsch reactor

H2, H2O Steam reforming reactor

Refining reforming

H2 Condenser

Water

Fischer−Tropsch liquids

H2

H2O

Fig. 3 Biomass steam gasification with chemical looping for liquid transportation fuels by Fischer–Tropsch (F–T) synthesis. Reproduced from Demirel Y, Matzen M, Winters C, Gao X. Capturing and using CO2 as feedstock with chemical-looping and hydrothermal technologies and sustainability metrics. Int J Energy Res 2015;39:1011–47.

Air/steam Biomass Gasification

Steam Gas cleaning

Water-gas shift

Heat

Hydrogen Separation CO2-rich stream

Fig. 4 Block flow diagram of biohydrogen production by gasification of biomass feedstock.

reduces the oxygen level of the biooil and increases the H2 proportion, leading to the production of saturated C–C bonds that are fully compatible with petroleum infrastructure and use.

1.22.5

Biofuels

Biofuels are biomass feedstock-based fuels and include biohydrogen, bioethanol, biobutanol, biomethanol, biooil, biogas, and biodiesel. These biofuels are produced mainly by chemical, biochemical, thermochemical, and hydrothermal processes and are reviewed briefly in the following sections.

1.22.5.1

Biohydrogen

Hydrogen is a zero-emission fuel with combustion products of water and trace amount of NOx. Hydrogen can be produced mainly from the second generation of biomass feedstock by using thermochemical processes of gasification (steam reforming) and fast pyrolysis. Fig. 4 shows a schematic of biohydrogen production by gasification of a biomass feedstock. Energy efficiency for biomass gasification for H2 production is around 55%–65%. Hydrogen can also be produced by microorganisms in biological processes [31] as well as electrolysis of water by using a renewable power source of wind, solar, or hydro [32]. Among them, thermochemical processes are more mature and suitable for large-scale productions, while biological processes are in the developing stages. Steam methane reforming is a current and economical process to produce hydrogen in large scale with around 86% energy efficiency. Steam reforming can also be used with biomass feedstock including municipal organic waste, sewage sludge, and

Biofuels

883

agricultural waste. Supercritical water gasification (at 220–400 bar and 500–7001C) can use wet biomass with high gasification efficiency but at higher cost. The pressure swing adsorption process is widely used for hydrogen separation in the syngas with around 85% separation efficiency [33].

1.22.5.2

Bioethanol

Bioethanol can be produced using the first and second generation biomass feedstock as well as some other feedstock such algae. The following sections briefly explain the various forms of bioethanol production.

1.22.5.2.1

First generation bioethanol

First generation bioethanol uses feedstock containing sugar (sugarcane, sugar beet, sweet sorghum) and containing starch (corn, wheat, cassava). Wet and dry milling routes are used to produce bioethanol from corn. Dry milling requires less investment and produces dried distiller’s grain with solubles (DDGS) beside bioethanol, while the wet milling produces oil and animal feed beside the bioethanol. Corn-grain is used to coproduce bioethanol and wet or DDGS as animal feed. Fig. 5 shows the basic steps of converting starch into bioethanol by biochemical process using 6-carbon sugar sources. Most corn is ground to a meal, and then the starch from the grain is hydrolyzed by enzymes to glucose (dry mill). The 6-carbon sugars are then fermented to ethanol by natural yeast and bacteria. The fermented mash is separated into ethanol and residue by distillation. Hydrated ethanol forms an azeotropic mixture; fuel grade ethanol (0.4 vol% water) can be achieved by azeotropic distillation, by means of molecular sieves, or by extractive distillation [34]. The average yield of converting corn starch to ethanol is around 100 gallons bioethanol per dry ton corn [35]. About one-third of every kilogram of corn grain is converted to ethanol, one-third to DDGS, and one-third to CO2. Ethanol is produced at ASTM D4806 standards and shipped to the refiner or distributor for blending with conventional fossil gasoline into finished gasoline. Surplus corn in the United States and sugarcane in Brazil are used to produce bioethanol. Fermentation of a bushel of corn (approximately 25.4 kg) using the dry-mill process yields about 10.2 l of ethanol and approximately 7.9 kg of DDGS that contains 10% moisture. This coproduct is richer in protein, fat, minerals, and fiber relative to corn and hence is a valuable feed [14]. Bioethanol producers have adopted various technologies such as high-tolerance yeasts, continuous ethanol fermentation, cogeneration of steam and electricity, and molecular sieve driers to reduce ethanol production costs [35,36].

1.22.5.2.2

Second generation bioethanol

Second generation bioethanol is produced from lignocellulosic biomass and other nonfood biomass resources. There are mainly two types of technology that are used to convert lignocellulosic biomass to fuels to meet the Renewable Fuel Standard (RFS) [36]: (1) biochemical and (2) thermochemical conversions [37]. Biochemical pathways for converting cellulosic biomass into fuels follow the process of pretreatment to release carbohydrates from the lignin shield, breaking down cellulose and hemicellulose to release sugars, fermentation of sugar to ethanol, distillation to separate the ethanol from the dilute aqueous solution, and conversion of the residue to electricity. In the thermochemical processes, the biomass is gasified or liquefied (pyrolysis) to produce biosyngas and biooil, respectively [27]. 1.22.5.2.2.1 Second generation bioethanol by biochemical processes Cellulose, hemicellulose, and lignin are the structural components of lignocellulosic biomass to produce bioethanol. Lignocellulosic biomass includes corn stover, corn cobs, sorghum stalks, wheat straw, cotton residue, alfalfa stems, wood, fastgrowing plants such as grass, and bagasse, which is the fiber residue left after sugarcane and sorghum stalks are crushed to extract their juice. Dedicated bioenergy crops refer to nonfood perennial crops that are grown primarily for use as bioenergy feedstocks, and include switchgrass (Panicum virgatum L.), Miscanthus, mixtures of native grasses, and short-rotation woody crops such as hybrid poplar and willow. Crop residues also help maintain soil quality (including fertility, structure, physical, chemical, and biochemical qualities) and reduce or mitigate soil erosion [38]. The three main steps of converting lignocellulosic feedstock to bioethanol are (1) hydrolysis of lignocellulosic polysaccharides into fermentable sugars (C6 and C5), (2) fermentation of these sugars into bioethanol, and (3) dehydration of ethanol to fuel CO2

Enzyme Milling

Liquefaction

CO2 scrubbing

Distillation/ dehydration

Ethanol

Enzyme Sacharification

Fermentation

Corn/ wheat

Dewatering/ drying

Yeast Coproducts/DDGS

Fig. 5 Main steps for the first generation biofuel production process producing bioethanol, dried distiller’s grain with solubles (DDGS), and CO2.

884

Biofuels

grade to be blended with conventional gasoline. As the cellulose is protected by lignin and hemicellulose, pretreatment is required to hydrolyze hemicellulosic sugars and open up the structure of biomass. Solvent-based pretreatment technology can produce chemical-grade cellulose, hemicellulose sugars, and lignin. In comparison to the dilute-acid pretreatment method, most of the advanced pretreatment methods involve the use of enzymes in several stages of the pretreatment process. After pretreatment, cellulolytic enzymes are used to hydrolyze the cellulose polymers to C5 and C6 sugars (xylose and glucose). Unlike glucose, xylose is not readily fermented to ethanol. Genetically modified or metabolically engineered yeasts or bacteria are used to ferment both glucose and xylose to enhance yield of ethanol from lignocellulose [39]. One of the challenges is to develop glucose- and xylosefermenting microorganisms genetically modified or metabolically engineered to withstand antimicrobial agents released during the pretreatment and hydrolysis steps and that are not inhibited by high alcohol concentrations. Some other biomass feedstocks for bioethanol production can be macroalgae and sugarcane bagasse. Macroalgae do not need arable land, water, and expensive nutrients and can be used as a source for renewable sugars to produce bioethanol and biogas besides other fermentation-based chemicals. Brown macroalgae (Saccharina latissimi) in particular contain carbohydrates (450%) without lignin and are suitable for fermentation after an enzymatic hydrolysis step [40].

1.22.5.2.2.2 Second generation bioethanol by thermochemical processes Fig. 6 shows the basic steps of the gasification process in which biomass (or other carbon-containing feedstock) is used to produce bioethanol. The general process areas include feed preparation, gasification, gas cleanup and conditioning, and alcohol synthesis and purification [11]. The biomass feedstock is dried to that required for proper feeding into the gasifier. Injected steam into the gasifier stabilizes the entrained flow of biomass and particles through the gasifier. The biomass chemically converts to a mixture of biosyngas components (CO, H2, CO2, CH4, etc.), tars, and a solid char, which are reformed to CO and H2. For dry basis, CO and H2, contents of syngas are around 29 vol% and 32 vol%, respectively. The hot biosyngas is cooled and sent to an amine unit to remove the CO2 and H2S. The biosyngas can then be chemically converted into MeOH, ethanol, and other liquid fuels using the F–T synthesis with suitable catalyst, mainly Fe or Co, at high temperature (200–3501C) and pressure (25–40 bar). Overall yield and energy efficiency are 23%–41% and 32%–51%, respectively, for biomass-based hydrocarbon production [25]. Purification of the syngas accounts for 60% to 70% of the total capital cost. Alcohols are fed to a flash separator and unused biosyngas is recycled to gas cleanup section. A distillation column separates the dehydrated alcohol feed into the mixture of MeOH and ethanol and the higher molecular weight alcohols of butanol and alcohols. An important design parameter for thermochemical conversion of biomass to biofuel is the H2/CO ratio. This ratio for the F–T process is around 2, while biomass gasification produces a raw biosyngas with ratios typically between 0.8 and 1.6. Hydrogen in the raw biosyngas is usually increased by using water–gas shift reaction: H2O þ CO-H2 þ CO2 DH298K ¼ 41 kJ mole 1. The gasification process requires proper utilization of heat integration (using, e.g., a pinch analysis), which provides a systematic approach to optimize the energy integration [15]. Municipal solid wastes (MSWs) may contain paper, paperboard, textiles, wood, yard trimmings, and food scraps, which are biological materials that could be used to generate biofuels. Large cities with large volumes of MSW have installed trash incinerators to recover the energy. Any new biofuel facility using MSW should compete economically with the existing incineration facilities. MSW is a mixed stream that is highly heterogeneous and also contains microorganisms and some level of toxic substances (such as mercury in batteries, pesticide residues, and paints) that could contaminate a biochemical conversion process. MSW might be better suited for a thermochemical conversion process; however, once the technology matures, MSW would become an attractive feedstock. Various simulation and modeling studies of biomass (corn stover and distiller grain) gasifier can predict the flowrate and composition of product from given biomass composition and gasifier operating conditions. Mass balance, energy balance, and minimization of Gibbs free energy during the gasification can be applied to determine the product gas composition. Sensitivity analyses can be performed to investigate impact of steam-to-biomass ratio, equivalence ratio, and furnace temperature of the gasification [14–16].

1.22.5.3

Fischer–Tropsch Diesel

Also known as a gas-to-liquid fuel, F–T diesel is produced when a gaseous fuel is converted to a liquid and refined to make diesel. Biomass feedstocks for F–T biofuels are wood, forest wastes, grass, agricultural wastes, manure and sludge, and MSW. Around 1 t of biomass with 30% moisture will produce 159 L of biodiesel fuel. Optimum size of a biomass-to-FT-liquid fuel plant is around 5–8 million tons year 1 [37,41]. F–T diesel offers reduced emissions and is compatible with advanced emission-control devices. In Ethanol Biomass

Feed handling/ drying

Gasification

Flue gas

Fig. 6 Biomass gasification for alcohol production.

Gas cleaning

Alcohol synthesis

Separation Higher alcohols

Biofuels

885

green diesel production, fats, algal oils, waste oils, or virgin oils are converted to low-sulfur diesel by hydrogenation and hydrodeoxygenation.

1.22.5.4

Biobutanol

By the fermentation process, sugars can be converted into butyric, lactic, and acetic acids. Butyric acid is converted by fermentation into biobutanol. The electrodeionization process makes the entire fuel conversion process faster and less costly. Corn starch also can be converted to biobutanol via the acetone–butanol–ethanol fermentation pathway [42]. Coproducts include alcohols with lower molecular weight than butanol and acetone. Butanol’s toxicity to the microorganisms that ferment sugar creates obstacles. If corn grain is the source of the sugars for fermentation, a residue similar to dried distillers’ grain is produced. This might require additional processing to remove any toxic biobutanol and acetone residue before it could be used as an animal feed. Gas stripping can be used to extract the biobutanol. First, the wheat straw is pretreated with dilute sulfuric acid or other chemicals. Next, the material is fermented in a bioreactor containing three different types of commercial enzymes and a culture of Clostridium beijerinckii P260. The bacteria and enzymes function simultaneously; first, the enzymes hydrolyze the straw and release simple sugars, then the bacteria start fermenting those sugars into acetone, butanol, and ethanol. Butanol is produced in greatest quantity but the other two are also valuable components. Isobutanol can be produced by anaerobic process using E. coli strains and continuous vacuum stripping for butanol fermentation. This process is still in the developing stage. The sugar to isobutanol conversion yield is around 85%. As the yield increases, butanol purification improves considerably. Butanol costs, water usage, and direct CO2 emissions are all higher than that of cellulosic bioethanol [43], while butanol is far superior to ethanol in energy efficiency.

1.22.5.5

Biomethanol

MeOH synthesis needs carbon-rich feedstock, H2, and a catalyst, mainly Cu/ZnO/Al2O3 and consists of three fundamental steps: (1) biomass reforming to produce biosyngas with an optimal ratio of [(H2 CO2)/(CO þ CO2)] ¼ 2, (2) conversion of biosyngas into crude MeOH, and (3) distillation of crude MeOH: CO2 þ3H2 ¼ CH3 OH þ H2 O CO þ 2H2 ¼ CH3 OH

DHo ð298KÞ ¼ DHo ð298KÞ ¼

49:4 kJ mol

90:5 kJ mol

1

ð7Þ

1

ð8Þ

Selectivity for MeOH is high with a value of 99.7% at 5 MPa and 523K and with a H2/CO2 ratio of 2.82. The energy efficiency for the concentrated CO2 and H2-based MeOH is around 46% [44]. Some of the available sources for CO2 are fermentation processes such as bioethanol production plants. Renewable H2 comes from the electrolysis of water using hydropower, wind power, and solar photovoltaic power. Alkaline electrolysis technologies are the most mature commercial systems. For producing 1 kg H2, approximately 26.7 kg water is necessary. Fig. 7 shows a schematic of wind electricity-based hydrogenation of CO2 to MeOH. Currently, the cost for hydrogen from electrolysis is roughly twice that from natural gas steam reforming; however, a significant GHG reduction ( 1.07 kg CO2 per kg MeOH) may be possible [45–47]. The electricity cost accounts for around 23%–65% of the MeOH production cost because of high stoichiometric hydrogen demand in the synthesis [48]. Biomass-based biomethanol and electricity production together may have a positive impact on the cost of the integrated process shown in Fig. 7. The plant shown in Fig. 7 uses 18.6 metric ton (mt) H2 day 1 and 138.4 mt CO2 day 1, and produces 97.0 mt MeOH day 1 at 99.5 wt% together with 54.6 mt day 1 of 99.5 wt% H2O wastewater. The reduction of GHG emission is around 1.07 kg CO2e kg 1 MeOH as a feedstock. The hydrogen production cost is highly dependent on the electricity price, which may be around 75% of the final cost [45]. Wind electricity

Methanol

Transformer

O2

Electrolysis Electrolyte solution

H2

H2 compression

H2

Methanol synthesis Water

Water

CO2 Ethanol plant

Fig. 7 The integral methanol (MeOH) production facility based on the feedstock of renewable hydrogen and CO2. Reproduced from Matzen M, Alhajji M, Demirel Y. Technoeconomics and sustainability of renewable methanol and ammonia productions using wind power-based hydrogen. Adv Chem Eng 2015;5:128; Matzen M, Alhajji M, Demirel Y. Chemical storage of wind energy by renewable methanol production: feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53.

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1.22.5.5.1

Biomethanol from sewage sludge

Sewage sludge is a residue of a municipal wastewater treatment plant. Mechanically dewatered sludge contains 12%–25% solid (LHV¼ 12.0 MJ kg 1) with an organic fraction of 56% of dry solids rich in carbon (50%), hydrogen (7%), and oxygen (31%) [44]. This may lead energy recovery by producing biofuels as well as bioproducts beside the incineration commonly used. One way for energy recovery is the gasification of the sludge and conversion of syngas produced into MeOH as well as other chemicals. In the low-pressure MeOH process catalytic synthesis takes place at 77 bar and 200oC using the cleaned syngas. This will help minimize waste as well as recover energy.

1.22.5.6

Biodimethyl Ether

DME is the simplest ether (CH3OCH3) and can be produced by catalytic biomethanol dehydration: 2CH3 OH-CH3 OCH3 þ H2 O

ð9Þ

DME is a colorless, nontoxic, highly flammable gas at ambient conditions, but can be handled as a liquid under slight pressure (0.5 MPa). The properties of DME are similar to those of LPG with a LHV of 28.4 MJ kg 1 and density of 0.67 kg L 1. It has the conventional diesel fuel equivalency of 0.59 as the LHV of diesel is 43.1 MJ kg 1. DME is not a GHG and can be used as a substitute for diesel fuel or domestic gas [44].

1.22.5.7

Biodiesel

Seed crops contain high levels of protein and oil with various numbers of carbon atoms and double bonds as shown in Table 4. Food and nonfood oils, animal fats, and waste cooking oil can be converted into biodiesel. The type of oil affects the quality of biodiesel, conversion process, and operating conditions. Soybean and palm oils are the two largest oilseed crops. High level of protein produces high economic value meal. On a dry-weight basis, soybean contains around 41% protein, 21% oil, and 29% carbohydrate, on average. Triacylglycerol (triglycerides: C55H98O6) (94%) are the primary component in the soybean oil, while phospholipid content is around 3.7%. Triacylglycerol contains three fatty acids attached to a glycerol molecule (C3H5O3). Typical soybean oil has the density (at 201C) of 0.916 g mL 1, melting point of 0.61C, and heat of combustion of 9.0 kcal g 1 (38 kJ g 1) [49].

1.22.5.7.1

Biodiesel from plant oils

Several countries produce biodiesel from rapeseed oil, palm oil, and soybean oil. In the United States, biodiesel is produced mostly from soybean oil. Other vegetable oils and animal fats such as canola, camelina, and jatropha constitute a small fraction of biodiesel feedstock. Soybean seeds yield about 18% oil and the remaining meal, which is the primary product of soybean and sold as a highly nutritious animal feedstuff. Because of the high yield of the meal, this coproduct may provide better monetary returns per ton of seed than the oil used in biofuel production. Chemical conversion technology is the transesterification of triglyceride with alcohol (usually MeOH and ethanol) to produce biodiesel and glycerin that can be used for pharmaceutical formulation, soap production, and other uses (see Fig. 8). It can be blended with conventional diesel (typically 20%) to reduce vehicle emissions. Soybean-based biodiesel mainly uses MeOH. Methyl esters from typical soybean oils are palmitate (10%), stearate (4%), oleate (23%), linoleate (55%), and linolenate (7%). Biodiesel produced from oilseeds, such as soybean or sunflower, leaves behind a protein-rich meal that is an excellent feedstuff for poultry, pigs, and dairy cattle [36]. It can also be used as a feedstock to produce hydrogen and other bioproducts such as glycerol carbonate, which may be economically viable with technical improvements [50,51]. Used frying or cooking oils (mainly olive oils and sunflower oils) contain a large amount of free fatty acids, so an esterification step is necessary before transesterification to produce biodiesel. This reaction is usually carried out in batch reactors at ambient pressure and 601C where the esterification reaction acts as the limiting step of the production. Based on the experimental results, biodiesel from used frying oil does not fulfill all the specifications from the EN 14214 standard due to the presence of polar compounds with the chemical modifications in the oil during cooking [52]. Table 4 Oil or fat

Rapeseed Soybean Sunflower Jatropha Tallow

Fatty acid composition (wt%) of various oils and fats Typical oil content %

39–43 16–18 40–50 28–38 24–32

Number of carbon atoms: number of double bonds 14:0

16:0

18:0

18:1

18:2

18:3

– – – – 3–6

4.3 6–10 7.2 11.3 24–32

1.3 2–5 4.1 17.0 20–25

59.9 20–30 16.2 12.8 27–43

21.1 50–60 72.5 47.3 2–3

13.2 5–11 – – –

20:1

1.8

Source: Reproduced from Van Gerpen J. Biodiesel from vegetable oils. In: Vertes aa, Qureshi N, Yukawa H, Blaschek HP, editors. Biomass to biofuels: strategies for global iindustries. Chichester: Wiley; 2010.

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Recycled fatty acids Acid/ methanol Dilute acid esterification Vegetable oils Methanol

Transesterification

Methanol recovery

Glycerin

Glycerin purification

Water washing

Catalyst removal

Biodiesel purification Biodiesel

Fig. 8 Biodiesel production from fatty acids and vegetable oils.

Solid catalysts are increasingly selected for the transesterification reaction of vegetable oils to produce biodiesel. Heterogeneous catalysts are environmentally benign, and can be used in continuous processes. Alkali earth metal oxides (magnesium oxide, calcium oxide, and strontium oxide) and transition metal oxides (zirconium oxide, titanium oxide, and zinc oxide) are studied for transesterification of oils. Alumina, silicate, zinc oxide, and zirconium oxide are used as catalyst supporting materials [53].

1.22.5.7.2

Green diesel

Green diesel production requires large volumes of H2 and a catalyst to hydrogenate triglycerides into a high-cetane diesel fuel [54] by removing all of the oxygen from the triglyceride and saturating all of the olefinic bonds in the fatty acids. The primary products from this hydrogenation are water, CO2, propane, and a mixture of normal paraffin. Green diesel is fully compatible with petroleum-based diesel. It can even be produced by coprocessing triglycerides along with other petroleum streams in conventional refinery diesel hydrotreaters.

1.22.5.7.3

Biodiesel from algae

Oil-rich microalgae strains are capable of producing the feedstock for a number of transportation fuels, for example, biodiesel, green diesel, gasoline, and jet fuel, while mitigating the effects of CO2. There are many different kinds of algae that grow in nearly any water resource in a variety of colors and forms, and can be found everywhere on Earth. Algae require water, sunlight, carbon, and nutrients like nitrogen and phosphorus to grow. One notable group is blue-green algae, which consists of prokaryotic cells (or bacteria) that use photosynthesis that draw CO2 from the atmosphere. Using them to create biofuel can significantly reduce GHG emissions from transportation fuels, power plants, and refineries. Blue-green algae, or cyanobacteria strains, have an extremely high photosynthetic rate and are ideal for producing triglycerides and biofuels. Cyanobacteria strains can also be engineered to produce photosynthesis-based biofuels [55]. Certain strains of algae could potentially produce up to 60 times more oil than plants like soybeans and offer the highest-yield feedstock for biodiesel [56]. Fig. 9 shows algae-based biofuel and bioproduct pathways with the following steps: 1. 2. 3. 4.

Algae growth in open ponds or in photobioreactors, which may be tubular, flat plate, plastic bag, or biofilm. Algae harvesting can be achieved via dissolved air flotation, gravity settling, and flocculation. Dewatering is possible with centrifugation, thermal drying, and belt filter. Processing microalgae biomass by either lipid extraction or whole cell. The extracted lipid can be fed into hydrotreating for green biodiesel, in situ conversion to biooil, or transesterification process to produce biodiesel and glycerin. The residue after the lipid extraction can be a. fed into anaerobic digestion to produce biogas and biopower. b. used as a feedstock for fermentation to alcohols. c. used as fertilizer. Whole cell can be used in anaerobic digestion as well as in thermochemical conversion (pyrolysis, hydrothermal liquefaction) processes.

As Fig. 9 shows, a specific biofuel or biooil pathway can be selected and analyzed if it is feasible and sustainable since the processing cost is a great concern for biodiesel from algae [22]. Ultrasound-based methods of algae harvesting are currently under development, and other additional methods are currently being developed. Harvesting algae and extracting oil are costly. In addition, a large amount of water is needed for large-scale production, which involves pumping it out of the production system and back in again. The smallest practical size for an algal biodiesel plant is 1000 ha, which pumps about 1 million m3 of water a day. This is about twice the amount of fresh water used for agricultural irrigation [55–58]. Many commercial manufacturers of vegetable oil use mechanical pressing and chemical solvent (hexane, benzene, or ether) to extract the oil. Estimates of the cost to extract oil from microalgae vary, but are likely to be around three times that of palm oil.

888

Biofuels

Microalgae strain

Water, CO2, nutrients, light

Water, CO2, nutrients, light

Oxygen Photo-bioreactors-0.5%

Open ponds-0.05% dw Paddle wheel

Natural circulation

Tubular

Flat plate

Oxygen

Plastic bag

Biofilm

Harvesting-1% Gravity settling

Flocculation

DAF

Water recycle

Dewatering-25% Belt filter

Centrifugation

Thermal drying

Microalgae 25−30 g/m2/day

Extract lipid 30%

Whole cell R sid esidue ue

Re

Hydrotreating

In-situ conversion

Esterification

Fermentation

Anaerobic digestion

Thermochemical methods

Ethanol Bio gas/power Wet

Dry

Biooil

Wet

Dry

Biodiesel $2.2−10 (2012)

Dry

Gasification

Pyrolysis

Wet

Hydrothermal liquefaction

Fig. 9 Algae-based biofuel pathways, cultivation, harvesting, conversion. Residue of lipid extraction goes to fermentation as well as anaerobic digestion; whole cell: anaerobic digestion and thermochemical methods (gasification, pyrolysis, and hydrothermal liquefaction). DAF, dissolved air flotation.

Enzymatic extraction uses enzymes to degrade the cell walls and costs much more than solvent extraction. Enzymatic extraction can be supported by ultrasonication, which may cause faster extraction and higher oil yields. Fig. 10 shows the block flow diagram for algal biomass production using a photobioreactor and solvent extraction of lipid with solvent recovery [58]. Algae strains can be genetically engineered to produce desirable ingredients such as more lipids and polyunsaturated oil components known to promote and maintain health [59]. Recently, algae biomass created via photosynthetic microbial bioproduction techniques has gained attention as a feedstock for biofuels [20]. Usually, algae with high oil contents grow relatively slowly; strains capable of producing large amounts of lipids tend to do so when they are starved of nutrients. Microbes can produce fats or materials that can be converted to biofuel by redirecting the protein utilization system. Mostly, the biofuelproducing algae have not made use of the protein like a carbon supply for biofuel but have used it for growth. Altered nitrogen metabolism may induce the biorefining process. The cells retain the nitrogen and take out just the ammonia. Once done with the biofuel production, the residue may be used as a fertilizer [60–62].

1.22.5.7.4

Nutrient recovery from municipal wastewater for algae-based biofuel production

There are efforts toward recovering nutrients and water necessary for algae biomass growth from municipal wastewater treatment plants [63,64]. Fig. 11 shows the general block flow diagram for algal biodiesel and biopower productions using the recovered nutrients, mainly phosphorous and nitrogen, for algae biomass growth in a pond. 151.5 mt of algal biomass can produce 27 mt crude lipid for biodiesel production, 124.5 mt residue for fertilizer or animal feed by using around 758 m3 solvent [55]. A common algae cultivation can be done side by side with wastewater treatment plants to recover nutrients. Thence the processes may be more efficient and less expensive. The algae can use the extra nitrogen and phosphorous in the existent water and make it safer for marine flora and fauna.

1.22.5.7.5

Jet fuel from camelina

Camelina oil seems right for the conversion to a hydrocarbon green jet fuel. It meets or sometimes exceeds all petroleum jet fuel specifications. Camelina oil is compatible with existing fuel infrastructure. The life cycle analysis shows that camelina is one of the

Biofuels

889

Recy-Sol M101

Solvent

Biomass recovery

Algal biomass production in photobioreactor

Light water/nutrients carbon dioxide algae

S7

Biomass extraction Biorefinary: biodiesel bioproduct

H2O-Recy Oil

Light Broth

H2O-Nut CO2

1

S2

R101

2

Solvent recovery

SEP2

3

SEP1

S6 SEP3 S3

6

EFF-CO2

4

Biogas

S5 Power

5

S8

Boiler

Effluent

R102

Turbine

Anaerobic digestion

Power generation

Animal feed

Fertilizer irrigation

Fig. 10 Algae biomass feedstock preparation to produce triglyceride acids, bioproduct, and biopower. R101: Reactor; SEP1: Separator (centrifuge); SEP2: Extractor; SEP3: Distillation column; R102: Reactor.

CO2

Evaporation

Algae pond

Water

Water

Fertilizer/ animal feed

Phospholipids lechitin Methanol

Harvesting

Algae culture

Solvent

Oil extraction

Phase separation

Degumming

Esterification

Glycerin Water

Nutrients/water

Power generation

Anaeorobic digestion

Biodiesel

Bio gas Wastewater nutrients

Sludge

Biopower CO2

Fig. 11 A block flow diagram for nutrient recovery from municipal wastewater for algae biomass growth and biofuel and biopower production.

leading near-term options and is even better in terms of affordable price and availability of large-scale quantities of second generation feedstocks [65].

1.22.6 1.22.6.1

Further Discussions Comparison of Biomass Used for Bioethanol Production

A large area of farmland needs to be diverted for corn production for corn-based bioethanol. Lignocellulosic biomass minimizes the potential conflict between the land use for food and biofuel productions. Some benefits and problems of bioethanol are that (1) it can be added to gasoline up to 10% in existing cars; (2) new cars can run on a 20% mix of ethanol with gasoline; (3) only minor changes are necessary for new cars to run on any mix of ethanol and gasoline, such as 85% ethanol (E85); (4) bioethanol can provide nations with energy security and significantly reduce GHG emissions; (5) corn-bioethanol may not be sustainable as corn is subsidized, grown, and harvested using fossil fuels, synthetic fertilizers, pesticides, and considerable amount of water,

890

Biofuels

Table 5

Comparison of ethanol plants using starch and lignocellulosic feedstock

Corn starch

Corn stover

Corn starch has alpha-linked glucose polymer easily broken down to glucose monomers and fermented to ethanol; conversion to ethanol takes around 2 days. Treatment is around 80–901C

Cellulose has beta-linked glucose polymer difficult to break down to glucose monomers; the conversion is longer (3 days) and more energy intensive; pretreatment requires dilute acid to make the cellulose digestible by cellulose enzyme at 180–2001C Have hemicellulose, which is a more complex polymer of several fivecarbon sugars of xylose and arabinose, which can be fermented to ethanol with the use of proper microorganisms Maximum theoretical yield 91 gal t 1 at 15% moisture, real yield is around 75 gal t 1 Lignin (14.7% of residue), currently is used as a fuel. Other organics (17.1% of residue) Requires more feed handling; to be delivered in bales that must be washed, shredded, and milled to a conveyable particle size Cellulosic feedstock to plant gate: $30–$53/t 1-dry. About 33% of the stover is available for collection. Capital cost is around four times higher compared with the cornethanol plant

Fiber from corn yields distiller’s dried grains with solubles (DDGS)

Enzymes: alpha-amylase and gluco-amylase convert 100% of the starch to glucose DDGS is high in protein and sold as animal feed The feedstock is the largest cost contributor Corn, yeast, urea, and enzymes are purchased raw materials Requires milling to a fine meal

Source: Hahn-Hagerdal B, Galbe M, Gorwa-Grauslund MF, Liden G, Zacchi G. Bio-ethanol-the fuel of tomorrow from the residues today. TRENDS in Biotechnol 2006;24:549–56; Pimantel D, Patzek TW. Ethanol production using corn, switchgrass, and wood; biodiesel production using soybean and sunflower. Nat Resour Res 2005;14:65–76; Sandor D, Wallace R, Peterson S. Understanding the growth of the cellulosic ethanol industry. Technical report NREL/TP-150-42120;2008.

which may impact the environment adversely; and (6) 100% bioethanol cannot be transported through existing pipelines, because of its chemical properties. Table 5 compares the bioethanol plants using the first and second generation biomass feedstocks [66].

1.22.6.2

Chemical and Fuel Properties of Biofuels

Table 6 compares the properties of biofuels and gasoline. Carbon content of gasoline is much higher with no oxygen, while biofuels contain high levels of oxygen and less carbon. These properties result in considerably LHVs for biofuels, while lowering the ratio of stoichiometric air to fuel ratio. Bioethanol is blended with gasoline causing corrosion in fuel transporting pipes and some problems of ethanol transport. The Renewable Fuels Association is currently exploring whether a dedicated ethanol pipeline would provide the same transport security. The Association for oil pipelines is also conducting a study of whether gasoline blends, those with up to a 20% ethanol additive, could utilize existing oil pipelines. Table 7 shows that the fuel properties of biodiesel from soybean oil and the conventional diesel are comparable.

1.22.6.3

Energy Efficiencies of Biofuels

Ptasinski [7] provides the energy and exergy analyses of biofuels. Energy efficiency for biomass to biofuel can be estimated by 80 19 1 0 External energy > > < LHV of biofuel = C C B B 1 0 used in 1 kg biomass produced per 1 kg A A @ @ > > Energy efficiency : ; to biofuel conversion of biomass C B   @ of biomass to biofuel A ¼ LHV of the 1 kg biomass conversion used in the convesion

ð10Þ

Energy balance studies reveal the ratio of the energy contained in the final bioethanol produced to total fossil energy used during the production. Table 8 shows such ratios for bioethanol production from various feedstock. The table indicates that sugarcane and lignocellulosic feedstocks have the highest energy ratios, mainly because of the use of bagasse and lignin as energy source within the production stage. Energy return on investment (EROI) shows the ratio of energy of a fuel to the total energy invested to produce that fuel [67]. The values of EROI for biofuels are generally lower compared with those of conventional fossil fuels (see Table 8). At the societal level, declining EROI means that an increasing proportion of energy output and economic activity must be diverted to attaining the energy needed to run an economy, leaving fewer discretionary funds available for the nonessential purchases that often drive growth [67]. The cost ratio Cr shows the biofuel cost to fossil fuel cost used in the production process. The emissions of GHGs from the transportation sector are around 25% of the global energy-related emissions. This is one of the main reasons to replace fossil fuels with biofuels. However, use of biofuels also causes GHG emissions occurring from different stages of the life cycles of biofuels, which include growing, cultivating biomass, and production of biofuels [68,69]. Combustion of biofuels recycles CO2 captured during photosynthesis. In order to characterize the environmental impact of biofuels GHG emissions caused by biofuels with respect to fossil fuels can be compared. Table 8 shows approximate avoided GHG emissions because of the biomass feedstock used in bioethanol production. There are some publications reporting an increase of GHG

Biofuels

Table 6

891

Properties of bioethanol, biomethanol, biobutanol, bioisobutanol, and conventional gasoline

Properties

Methanol (MeOH)

Ethanol

Butanol

Isobutanol

Gasoline

Ultimate analysis, wt% C H O Density (201C), kg m 3 Normal boiling point, 1C Motor octane number Higher heating value (HHV) (201C), MJ kg Stoichiometric air/fuel ratio kg kg 1 Flash point, 1C Autoignition temperature, 1C Energy density, MJ L 1 CO2 production, MJ kg 1 fuel

37.5 12.6 49.9 791 65.0 91 22.3 6.4 12 470 16 15

52.1 13.1 34.7 789 78.5 92 29.8 8.9 13 363 21.4 13

64.8 13.5 21.6 809 117.7 84 37.3 11.2 37 340 26.9 15

64.8 13.5 21.6 802 107.9 90 37.2 11.2 28 415 26.6 15

85–88 12–15 – 690–800 27–225 80–88 47.2 14.7 43 250–300 30–33 14

1

Source: Reproduced from Klass DL. Biomass for renewable energy, fuel, and chemicals. San Diego: Academic Press;1998; Demirel Y. Energy: production, conversion, storage, conservation, and coupling. 2nd ed. London: Springer; 2016; Tao L, Tan ECD, McCormic R, et al., Techno-economic analysis and life-cycle assessment of cellulosic isobutanol and comparison with cellulosic ethanol and n-butanol. Biofuels Bioprod Biorefining 2014;8:30–48.

Table 7

Properties of biodiesel from soybean and conventional diesel

Properties

Biodiesel

Diesel (No. 2)

Density, kg m 3 Viscosity (401C) mm2 s 1 Flash point, 1C Cloud point, 1C Pour point, 1C Sulfur content, wt% Cetane number Higher heating value (HHV), MJ kg 1 Stoichiometric air/fuel ratio, kg kg 1

886 3.89 188 3 3 0.012 55 39.8 12.5

849.5 2.98 74 12 23 0.036 49 45.4 14.5

Source: Reproduced from Klass DL. Biomass for renewable energy, fuel, and chemicals. San Diego: Academic Press; 1998.

Table 8

Energy ratio and energy return on investment (EROI) for bioethanol production from various feedstocks

Feedstock

Energy ratioa

EROI

Crc

Sugarcane Sugar beets Sweet sorghum Corn Wheat Lignocellulosic Gasoline

E8 E2 E1 E1.5 E2 E2–36 E0.8

0.8–10

E0.5 E1.2

87 to 35 to

96 56

0.84–1.65

E0.6

0.69–6.61

E

21 to 19 to 37 to

38 47 82

Greenhouse gas (GHG) emissions changeb (%)

a

Energy from biofuel/fossil energy used in production of biofuel. Approximate avoided GHG emissions because of the biomass feedstock used in bioethanol production. c Cr: Cost ratio. Source: Worldwatch Institute, Biofuels for transport: global potential and implications for sustainable energy and agriculture. Earthscan, London: BMELV; 2007; Basset N, Kermah M, Rinaldi D, Scudellaro F. The net energy of biofuels, EPROBIO IP; 2010. b

emissions from biofuels [70]. As Table 8 shows corn has the lowest energy ratio and reduction in GHG emissions because of the relatively large use of fossil fuel energy in the production of bioethanol. Pure ethanol is completely miscible with conventional gasoline. The HHVs (at 201C) for ethanol and gasoline are 29.8 MJ kg 1 and 47.2 MJ kg 1, respectively [5]. This suggests that a blend of bioethanol and gasoline will have lower total energy in a vehicle. With 10 vol% ethanol the fuel consumption is around 3.3% higher compared with the pure gasoline [8]. Flex-fuel engines can utilize higher percentage (85 vol%) of ethanol. Since the ethanol is oxygenated fuel (oxygen: 35 wt%), its combustion is cleaner. Ethanol is also a fuel for the direct ethanol fuel cells.

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Biofuels

Table 9 Energy ratio for biodiesel production processes from various feedstocks and change in life cycle greenhouse gases (GHG) emissions per kilometer traveled by replacing diesel with 100% biodiesel fuel; the cost ratio (price of biodiesel/price of fossil fuel) for biodiesel is around 1.2 Feedstock

Energy ratio

Energy return on investment (EROI)

Rapeseed Soybeans Sunflower Castor Palm oil Jatropha Waste vegetable oil Diesel (crude oil)

E2.5 E3 E3 E2.5 E2.5–9 E1.4 E5–6 0.8–0.9

1.0–1.5 0.7–2.0 0.4–1.2

GHG emissions change (%) 21 to 63 to

51 78

92

Source: Hall CAS, Lambert JG, Balogh SB. EROI of different fuels and the implications for society. Energy Policy 2014;64:141–52; Pradhan A, Shrestha DS, McAloon A, et al., Energy life cycle assessment of soybean biodiesel revisited. Trans ASABE 2011;54:1031–9; Worldwatch Institute, Biofuels for transport: global potential and implications for sustainable energy and agriculture. Earthscan, London: BMELV; 2007; Basset N, Kermah M, Rinaldi D, Scudellaro F. The net energy of biofuels, EPROBIO IP; 2010; EPA, Available from: https:// www.epa.gov/renewable-fuel-standard-program; 2016 [accessed: 07.12.16].

Table 9 shows the energy ratio that is the biodiesel energy output to fossil energy inputs in the production process with different feedstock. This table indicates that the energy ratios for all the biodiesels from various feedstocks are higher than 1 suggesting that biodiesels are renewable energy with positive net energy outputs and reductions in GHG emissions.

1.22.6.4

Renewable Fuel Standard

The US Congress created the RFS program in an effort to reduce GHG emissions and expand the nation’s renewable fuels sector while reducing reliance on imported oil. The RFS program was authorized under the Energy Policy Act of 2005 and expanded under the Energy Independence and Security Act of 2007. This new RFS is known as RFS2. The Clean Air Act requires the EPA to set the RFS volume requirements annually; for example, cellulosic biofuel volumes for 2016 and 2017 are approximately 870 and 1180 million liters respectively [36,71].

1.22.6.4.1

Categories of renewable fuel

A renewable fuel pathway includes three critical components: (1) feedstock (a biomass), (2) production process (a technology used to convert biomass into renewable fuel), and (3) fuel type. Renewable fuels include liquid and gaseous fuels, and electricity derived from renewable feedstock sources. To qualify for the RFS program, the fuel must be intended for use as transportation fuel, heating oil, or jet fuel. Qualifying fuel pathways are assigned one or more “D” codes representing the type of renewable identification number (RIN) they are eligible to generate. RINs are credits used for compliance, and are the “currency” of the RFS program; renewable fuel producers generate RINs, market participants trade RINs, and obligated parties obtain and then ultimately retire RINs for compliance. The RFS program includes four categories of renewable fuel, each with specific fuel pathway requirements and RIN D-codes [36,71]:

• • • •

Advanced biofuels (D5) are produced from any type of renewable biomass (sugarcane, biobutanol, bionaphtha) except corn starch ethanol. Required life cycle GHG emissions reduction is at least 50% compared to the petroleum baseline. Biomass-based diesel (D4) includes biodiesel and renewable diesel produced from biomass such as soybean oil, canola oil, waste oil, or animal fats. Required life cycle GHG emissions reduction is at least 50% compared to the diesel baseline. Cellulosic biofuel (D3 or D7) produced from cellulose or hemicellulose of corn stover, wood chips, Miscanthus, or biogas. To be eligible for D7 RINs the fuel must be cellulosic diesel. Required life cycle GHG emissions reduction is at least 60% compared to the petroleum baseline. Conventional renewable biofuel (D6) includes ethanol derived from corn starch, or any other qualifying renewable fuel. Required life cycle GHG emissions reduction is at least 20% compared to the average petroleum baseline.

1.22.6.5

Biofuel Assessment Models

Some economic models are used to assess the effects of biofuel production. The four main economic models are the Food and Agricultural Policy Research Institute (FAPRI) model, the Forest and Agricultural Sector Optimization (FASOM) model, the Global Trade Analysis Project (GTAP) model, and the Policy Analysis System (POLYSYS) model. Three of the models, that is, FAPRI, FASOM, and POLYSYS, are partial equilibrium models as they focus on the agricultural sector and do not include all the sectors of the economy. GTAP is a general equilibrium model and covers all sectors of the economy and all regions of the world focusing on the trade dimensions [36]. All four models were developed before the implementation of RFS2, and have been modified in recent years to include varying degrees of biofuel coverage. The FAPRI and GTAP models include corn-grain ethanol,

Biofuels

893

sugarcane ethanol, and oilseed-based biodiesel, which are the first generation biofuels. These models plan to expand the database to include second generation biofuels. The FASOM and POLYSYS models include second generation biofuels from lignocellulosic feedstocks presently used. The FASOM is the only model of the four to include electricity generation from cellulosic feedstocks [36].

1.22.6.5.1

Life cycle assessment

Integrated system analyses, technoeconomic analyses, and life cycle assessments (LCAs) provide the total economic and environmental benefits and drawbacks of a biofuel process that can be quantified. LCA is an analytic method for identifying, evaluating, and minimizing the environmental impacts of emissions and resource depletion associated with a specific process [5]. Material and energy balances are used to quantify the emissions, resource depletion, and energy consumption of all processes involved, including raw material extraction, processing, final disposal of products and byproducts, and required in operating the process of interest. The results of this inventory are then used to evaluate the environmental impacts of the process so efforts can focus on mitigation. LCA studies have been conducted on the following systems: direct-fired biomass power plant using biomass residue, anaerobic digestion of animal waste, bioethanol from corn stover, comparison of biodiesel and petroleum diesel used in an urban bus. For these analyses, the software package used to track the material and energy balances in each system is Tools for Environmental Analysis and Management (TEAM) [72–74].

1.22.6.5.2

Risk assessment for biofuels

Risk analysis deals with several criteria, such as financial risk, environmental risk, technical risk, and social risk. For a standalone plant, such as heat production in a sawmill for drying wood, availability and failure risk will be of minor importance for realization. However, for emerging technologies, some risk of unexpected failure or production breakdown should be taken into consideration. If the bioenergy plant is integrated into an industrial production (e.g., energy supply of a pulp and paper mill) availability of the feedstock has to be extremely high (B99.5%) and the risk of unexpected failure extremely low. A failure of the bioenergy plant would induce a stop to the whole production. Most developers will carry out some form of risk assessment as part of their project activities. Technoeconomic assessment (TEA) can be used to help inform this risk assessment, and conversely, risk assessment can identify key areas that could be tested in a sensitivity analysis as part of the TEA. For a novel technology, it might be relevant to test the robustness of the TEA to availabilities. In a new market, it might make sense to test the impact of increases in feedstock cost or of having to switch to an alternative supplier [1,75].

1.22.6.6

Right Way to Use Biofuels

Caution should be exercised if biofuels are considered as alternative sources of energy. The diversion of land to corn production and a greater demand for corn from the biofuel industry helped increase the price of wheat, corn, soybean, and rice in the mid2000s [74,75]. Dead zones have overload of nitrogen and phosphorus, which kill the aquatic flora and fauna, and marine life. To clean the dead zones, one needs to purify and oxygenate the existent waterways by removing the excess fertilizer run-off nitrogen and phosphorus. So we have to be aware of those alternative energy resources that may do more harm than good. We know that once destroyed we will never be able to restore the flora and fauna of the natural habitat. Biomass is the organic matter that can come from sustainable sources, but could also come from natural forests and grasslands. The wrong sources of biofuel can destroy forests and they can become the breeding ground of cropland or sterile tree plantations at the cost of wildlife of the area. A new campaign has been started by the Natural Resources Defense Council to warn people to use discretion while using biofuels. The right kind of biofuels will deal with the unemployment problem and will lead us toward green jobs, a stronger economy, a safer economy, and ultimately toward greener pastures [36].

1.22.6.6.1

Safety of biofuels

Safety concerns include health and welfare of the animals consuming the coproducts and the safety of the foods that are derived from these animals because of the presence of antibiotic residues and mycotoxins in distillers’ grains, which are used as animal feed. In corn-based ethanol production, bacterial contamination during the fermentation [76] competes with the yeast activity for sugars and micronutrients, and they produce organic acids, which may inhibit yeast and reduce ethanol yield. To prevent this, antibiotics, including virginiamycin, erythromycin, and tylosin, are sometimes added into the feed, which is regulated by the US Food and Drug Administration (FDA), the Department of Agriculture (USDA), and related organizations worldwide. When byproducts containing antibiotics are inadvertently fed to livestock, residues in meat, milk, or eggs could result in unacceptably high levels of the antibiotics in human foods [36].

1.22.6.6.2

Economic assessment of biofuels

Biomass feedstocks can be used to produce food/feed, fuel, fiber, fertilizers, polymers, chemical feedstock, pharmaceuticals, heat, and electricity. Second generation biomass resources are geographically more evenly distributed than fossil fuel resources, which may lead to energy security. Biofuels from lignocellulose generate low net GHG emissions and reduce the adverse effects of climate change. Biofuels might create local economic activity and employment. Most agricultural biomass production, except of forest products, is seasonal and results in a large volume of feedstock material that needs to be stored with little or no loss of dry matter for year-round supply to a biorefinery. To avoid transporting bulky biomass with low energy content, regional preprocessing infrastructure can be set up to clean, sort, chop or grind, control moisture, densify, and package the feedstocks before

894

Biofuels

transporting them to biorefineries. In contrast, forest products are available year-round so that long-term storage might not be necessary [77]. Biofuels are currently not cost-efficient compared with the fossil fuels. However, biofuels are promoted worldwide by tax credits and subsidies in order to reduce petroleum imports and GHG emissions from vehicles, and encourage local economies. There is a strong indication that as the biofuel technology becomes more energy efficient and more advanced with technological improvements, the production cost will be reduced by around 50% by 2030. Bioethanol production from sugarcane bagasse using liquefaction with simultaneous saccharification and cofermentation process shows that the overall bioethanol yield affects the minimum selling price, which is varied between $0.50 l 1 and $0.63 l 1 2016 US$ [78]. Lignocellulosic biofuel production does not result in an appreciable amount of coproducts. Investment costs of lignocellulosic biorefinery have been estimated to be four to five times higher than a starch-based bioethanol production of similar size [79]. Efficient and affordable depolymerization of cellulose and hemicellulose to soluble sugars and fermentation of them with free inhibitory compounds may advance process integration steps, freshwater usage, and energy costs, which are key to this type of process [3]. Assessment of three decades of a sugarcane bioethanol program since 1975 in Brazil shows that bioethanol can provide improvements in energy security, foreign exchange savings, employment, and reduction in GHG emissions with the right policies on biomass supply chain [78,80,81]. Table 10 shows the large amounts of water requirements of bioethanol and biodiesel productions from various biomass feedstocks. The effects of biofuel production on the worldwide trade of grains, livestock, biomass, and crude oil are a part of economic assessment. The biofuel industry also has some economic effects related to national budget spending such as tax credits, subsidies, incentives, and other policy matters. The diversion of land to corn production and a greater demand for corn from the biofuel industry coincided with an increase in the price of the staple commodities (wheat, corn, soybean, and rice) at an average of 102% in the mid-2000s [75]. The rapid nature of the increase was disruptive to food processors and to households. Technoeconomic analysis of MeOH production from biomass-based syngas shows that overall energy efficiency is around 55% based on HHV. The level of emission is around 0.2 kg CO2 per kg MeOH, which is mainly from biomass growing, harvesting, and transportation. MeOH from biomass is at least 2–3 times more expensive than that of the fossil fuel-based MeOH [82]. MeOH synthesis from water, renewable electricity, and carbon may lead to chemical storage of renewable energy, carbon recycle, and fixation of carbon in chemical feedstock [45,82]. Renewable hydrogen-based MeOH would recycle carbon dioxide as a possible alternative fuel to diminishing oil and gas resources [45]. There are already vehicles that can run with M85, a fuel mixture of 85% MeOH and 15% gasoline [5]. MeOH can be used with the existing distribution infrastructure of conventional liquid transportation fuels. In addition, fuel cell-powered vehicles are also at a fast developing stage, although they are not yet available commercially. Technological advances such as these would lead to a MeOH economy [83].

1.22.6.6.3

BioBreak model for second generation biomass feedstock

For an existing lignocellulosic biomass market, the purchase price for feedstocks should be obtained by surveying biorefineries, and the marginal costs of producing and delivering biomass feedstocks to a biorefinery should be calculated based on observed production practices. Often, models such as the biofuel breakeven (BioBreak) model can be used to evaluate the cost and feasibility of a regional market for a biomass feedstock and biofuel refining process. BioBreak is a flexible breakeven model that represents the regional feedstock supply system and biofuel biorefinery. BioBreak estimates the two costs [36]: 1. Willingness-to-pay (WTP) is the maximum price that a biorefinery will pay for a dry ton of biomass delivered at the gate. WTP is a function of the price of bioethanol, the conversion yield in gallons per dry ton of, and the cost of processing biomass. Table 10

Comparison of water requirements for ethanol and biodiesel productions

Biofuel crop

Water use m3 water kg

Biofuel conversion 1

crop

liter fuel kg

1

crop

Crop water use m3 water kg

1

Crop water use per unit energy fuel

m3 water GJ

Ethanol Corn (grain) Sugarcane Corn stover Switchgrass Grainsorghum Sweetsorghum

833 154 634 525 2672 175

409 334 326 336 358 238

2580 580 2465 1980 9460 931

97 22 92 74 354 35

Biodiesel Soybean Canola

1818 1798

211 415

9791 4923

259 130

1

Source: Reproduced from Stone KC, Hunt PG, Cantrell KB, Ro KS. The potential impacts of biomass feedstock production on water resource availability. Bioresour Technol 2010;101:2014–25.

Biofuels

895

2. Willingness-to-accept (WTA) is the minimum price that a biomass producer would accept for a dry ton biomass delivered at the gate of a biorefinery. WTA depends on the biomass opportunity cost, as well as production and delivery costs of biomass in a long time range. Assumptions used in the BioBreak model are:

• • • • • •

Producer minimizes costs on the long-run average cost curve. Yield distribution for biomass crops is based on the expected mean yield. Transportation cost is based on the average hauling distance for a circular capture region. Biorefinery has a 189-million-liter annual capacity to be competitive in the market. Each biorefinery uses a single feedstock with no market disruptions. Impact of energy price uncertainty on biofuel investment is not considered.

1.22.6.6.3.1 Willingness-to-pay for lignocellulosic bioethanol production Eq. (9) shows the processor’s WTP for 1 dry ton of cellulosic material delivered to a biorefinery: WTP ¼ Pgas EV þ T þ VCP þ VO

CI


CO YE

ð9Þ

The market price of bioethanol is estimated as the energy equivalent price of gasoline, where Pgas denotes per-gallon price of gasoline and EV denotes the energy equivalent factor of gasoline to ethanol. Based on historical data for conventional gasoline and crude oil, the following relationship between the price of gasoline and oil is assumed: Pgas ¼0.13087 þ 0.023917Poil. Beyond direct ethanol sales, the ethanol processor also receives revenues from tax credits T, coproduct production VCP, and octane benefits VO per gallon of processed bioethanol. Biorefinery costs are separated into two components: investment costs CI and operating CO costs per gallon. To determine the processor’s maximum WTP per dry ton of feedstock, a conversion ratio is used for gallons of ethanol produced per dry ton of biomass YE. Therefore, Eq. (9) provides the maximum amount the processor can pay per dry ton of biomass delivered to the biorefinery and still break even [36]. The values of the variables in Eq. (9) are based on the following assumptions and listed in Table 11:

• • • • • •

•

Price of oil (Poil). The three oil price levels: $52, $111, and $191 per barrel, which are the low, reference, and high price projections for 2022 [85] in 2008 US$. Energy equivalent factor (EV) and octane benefits (VO). The energy equivalent ratio (EV) for ethanol to gasoline is fixed at 0.667. Blending gasoline with ethanol increases the fuel’s octane value. For simplicity, the value of VO was fixed at $0.10 per gallon. Coproduct value (VCP). Excess energy is the only coproduct, and Aden et al. [81] estimated that cellulosic ethanol production yields excess energy valued at approximately $0.14–0.21 per gallon of ethanol, after updating to 2007 energy costs [86]. Conversion ratio (YE) is assumed to be a conversion ratio with a mean value of 70 gallons per dry ton feedstock as representative of current and near-future technology (baseline scenario) (and a mean of 80 gallons of the long-run conversion ratio) in the sensitivity analysis. Investment costs (CI) are based on laboratory- or pilot-scale operations and estimated cost data for an optimized nth biorefinery for biochemical conversion of corn stover to ethanol. Aden et al. [80] updated to 2007 capital cost and feedstock cost. The model assumes a mean (likeliest) value of $0.94 ($0.85) per gallon for baseline biorefinery capital investment cost. Operating costs (CO) are separated into two components: enzyme costs and nonenzyme operating costs. Nonenzyme operating costs, including salaries, maintenance, overhead, insurance, taxes, and other conversion costs, were fixed at $0.36 per gallon. Aden et al. [81] assumed set enzyme costs at $0.10 per gallon, which may vary between $0.40 and $1.00 per gallon at current yields and technology. Biofuel production incentives and tax credits (T) for cellulosic ethanol producers designated by the Food, Conservation, and Energy Act of 2008 of $1.01 per gallon was considered in the sensitivity analysis and was denoted as the “producer’s tax credit.”

1.22.6.6.3.2 Willingness-to-accept for lignocellulosic bioethanol production Eq. (10) shows the biomass supplier’s WTA for 1 dry ton of cellulosic material delivered to the biorefinery [36] WTA ¼




CES þ COpp =YB þ CHM þ SF þ CNR þ CS þ DFC þ DVCD 2G

ð10Þ

The value of WTA is equal to the total production costs less the government incentives G (e.g., tax credits and production subsidies) for one dry ton of feedstock. Depending on the type of biomass feedstock, costs include establishment and seeding CES per acre, land and biomass opportunity costs COpp per acre, harvest and maintenance CHM, stumpage fees SF, nutrient replacement CNR, biomass storage CS, transportation fixed costs DFC, and variable transportation costs calculated as the variable cost per mile DVC multiplied by the average hauling distance to the biorefinery D. Therefore, the biomass yield per acre YB is used to convert the per acre costs into per dry ton costs. Eq. (10) provides the minimum price the supplier can accept for one dry ton of biomass delivered to the biorefinery and still break even [36]. The values of the variables in Eq. (10) are based on the following assumptions and listed in Table 12:

•

Nutrient replacement costs (CNR) range from $5 to $21 per dry ton after adjusting for 2007 costs and represent the added value by the uncollected cellulosic material to the soil through enrichment and protection against rain, wind, and radiation, thereby limiting the loss of vital soil nutrients such as nitrogen, phosphorus, and potassium.

896

Table 11

Biofuels

BioBreak model assumptions to estimate willing to pay WTP cost by processor

Parameter

Feedstock

Mean value

Oil price (POil) Energy equivalent factor (Ev) Tax (T) Byproduct value (VBP)

All All All Stover Switchgrass (all) Miscanthus (all) Wheat straw Short rotation woody crops (SRWC) Forest residue Alfalfa All All All All All – current All – future

$52 brl 1; $111 brl 1; $191 brl 0.68 $1.01 gal 1 $0.16 gal 1 $0.18 gal 1 $0.18 gal 1 $0.18 gal 1 $0.14 gal 1 $0.14 gal 1 $0.18 gal 1 $0.10 gal 1 $0.91 gal 1 $0.36 gal 1 $0.50 gal 1 70 gal t 1 80 gal t 1

Octane (Vo) Capital cost (C1) Nonenzyme operating cost Enzyme cost Yield (YE)

1

SRWC: short-rotation woody crops; brl: barrel. Source: Reproduced from National Research Council, Renewable fuel standard: potential economic and environmental effects of U.S. biofuel policy, The National Academic Press. Available from: http://nap.edu/13105; 2011 [accessed 12.07.16].

• •

• •

• • •

Harvest and maintenance costs (CHM) and stumpage fees (SF) are assumed a mean value of $27–$46 per dry ton for harvest and maintenance with an additional stumpage fee with a mean value of $20 per dry ton for short-rotation woody crops. Transportation costs (DVC, DFC, and D). The BioBreak model uses breakdown of variable and fixed transportation costs. Oneway transportation distance D has been evaluated up to around 140 miles for woody biomass and between 5 and 75 miles for all other feedstocks. BioBreak calculates the average hauling distance D as a function of annual biorefinery biomass demand, annual biomass yield, and biomass density using the formulation by French [84] for a circular area with a square road grid. The average hauling distance is between 13 and 53 miles. Biomass storage costs (CS) depends on the feedstock, harvest technique, and storage area. Adjusted for 2007 costs, storage cost estimates range between $2 and $23 dryton 1. The mean (likeliest) cost for woody biomass storage is $11.50 ($12) dryton 1, while corn stover, switchgrass, Miscanthus, wheat straw, and alfalfa have a mean value of $11 dryton 1. Establishment and seeding costs (CES) are assumed to not incur for corn stover, wheat straw, and forest residue suppliers, whereas all other feedstock suppliers would have to be compensated for their establishment and seeding costs. The model assumes a mean cost per acre per year of $40 for switchgrass, $150 for Miscanthus, $52 for short rotation woody crops (SRWC), and $165 for alfalfa. Opportunity costs (COpp) of using biomass for ethanol production are assumed a mean opportunity cost per acre of $50–150 for switchgrass and $75–150 for Miscanthus. Biomass yield (YB) is variable; the mean yield of various feedstock is between 1 and 8.5 t. Biomass supplier government incentives (G) are the dollar/dollar matching payments provided in the Food, Conservation, and Energy Act of 2008 up to $45 per dry ton of feedstock for collecting, harvesting, storing, and transporting (CHST), which is a temporary (2-year) payment.

For the economic analysis, the BioBreak model estimates the price gap (PG): PG ¼ WTA WTP; if the PG is negative or zero, a biomass market is economically feasible, otherwise the biomass market is not sustainable under the assumed biomass production and conversion technology [1]. Table 13 presents the mean values of WTP, WTA estimated by the BioBreak model, and price gap per dry ton without policy incentives in 2007 US$. The value of PG decreases with higher oil prices and vice versa. The value of PG increases to between $110 and $168 per dry ton of biomass with an oil price of $52 per barrel. The breakeven price is also sensitive to the conversion rate of biomass to ethanol. The baseline results assume a conversion rate of 70 gallons per dry ton biomass. Table 13 shows the price gap values with policy incentives. Any policy incentives for either the processor or supplier will decrease the price gap needed for market viability. The 2008 farm bill provides a $1.01 per gallon tax credit to lignocellulosic biofuel blenders. Policy incentives for carbon emissions could also affect the PG for a possible interaction of biofuel policy with possible carbon policies [36]. A possible government intervention to encourage biomass production is to eliminate the price gap between the processor’s WTP and the supplier’s WTA by placing a price on carbon such as a carbon tax or carbon credit. Such a credit should be at a level in order to establish a viable biomass fuel market. The implicit price can be viewed as attributable to energy security and rural development benefits in addition to GHG reduction benefits. BioBreak extends the breakeven analysis by using the GREET model and GHG emissions savings from cellulosic ethanol relative to conventional gasoline. Maintaining a low price gap plays an important role in sustaining a lignocellulosic ethanol market [36].

Biofuels

897

Table 12 BioBreak model assumptions to estimate willing to accept (WTA) price by producer for feedstock. The values with the highest probability density are within the parentheses. Supplier breakeven (WTA) – Parameter assumptions Parameter

Feedstock

Mean value

Nutrient replacement (CNR)

Stover Switchgrass Miscanthus Wheat straw Forest residue Stover Switchgrass Miscanthus Wheat straw Short rotation woody crops (SRWC) Forest residue Alfalfa SRWC Stover Switchgrass Miscanthus Wheat straw SRWC Forest residue Alfalfa All Stover (CS) Alfalfa (1st year) Alfalfa (2nd year) Switchgrass Miscanthus Wheat straw SRWC Forest residue Alfalfa Others All Switchgrass Miscanthus SRWC Alfalfa (1st year) Switchgrass Miscanthus Wheat straw Alfalfa (1st year)

$13.6 t 1 ($14.6) $15.6 t 1 ($16.6) $8.35 t 1 $5.6 t 1 $15.6 t 1 $43 t 1 ($46) $36 t 1 ($38) $45 t 1 ($48) $32 t 1 ($33) $26 t 1 $26 t 1 $57 per acre $20 t 1 $8.50 t 1 [$0.35 t 1 mile $8.50 t 1 [$0.35 t 1 mile $8.50 t 1 [$0.35 t 1 mile $8.50 t 1 [$0.35 t 1 mile $10 t 1 [$0.5 t 1 mile 1]: $10 t 1 [$0.5 t 1 mile 1]: $8.50 t 1 [$0.35 t 1 mile 772,000 t3 2.1 t 1.25 t 4t 3–6 t 7–9 t 1t 5t 0.5 t 0.15 t m 3 0.20 t m 3 $10–11 t 1 $40 acre 1 $150 acre 1 $52 acre 1 $165 acre 1 $50–150 acre 1 $75–150 acre 1 $1.80 acre 1 $175 acre 1

Harvest and maintenance (CHM)

Stumpage fee (SF) Distance fixed cost (DFC) (distance variable cost (DVC)) Distance: 13–53 miles

Annual biomass demand (BD) Yield (YB)

Biomass density (B) Storage (CS) Establishment and seeding (CES)

Opportunity cost (COpp)

1

]: 36 miles ]: 16–21 miles 1 ]: 14 miles 1 ]: 37 miles 17 miles 53 miles 1 ]: 43 miles 1

Average hauling distance is calculated using the formulation by French [84]. Equivalent to 2.205 t per day delivered to a biorefinery operating 350 days per year. Switchgrass establishment seeding cost is amortized over 10 years at 10%, Miscanthus over 20 years at 10%, and woody biomass over 15 years at 10%. The values are annual payments per acre. All per-acre costs are converted to per-ton costs using the yield assumptions provided in the table. Midwest opportunity cost is assumed to be positively correlated with corn yield through stover yield with a correlation of 0.75. Source: Reproduced from National Research Council, Renewable fuel standard: potential economic and environmental effects of U.S. biofuel policy, The National Academic Press. Available from: http://nap.edu/13105; 2011 [accessed 12.07.16].

Anex et al. [79] compared the cost of producing bioethanol by fermentation, gasoline or diesel by gasification and F–T process, and gasoline or biodiesel by fast pyrolysis (see Table 14) for a required selling price for the liquid fuel to give a 10% discounted cash flow rate of return on a project with a 20-year life. All capital and operating costs are referenced to 2007 US$. Corn stover is priced at $75 per dry ton. Because the three technologies produce fuels with different energy contents, the results are presented in terms of gallons of gasoline equivalent (GGE). The study was based on a consistent biorefinery size of 2205 dry tons per day of corn stover. The only byproducts from the biorefinery are the fuel generated from the unconverted biomass and electricity. A report on sustainable development of algal biofuels in the United States [87,88] identified EROI, GHG emissions, water use, supply of nitrogen, phosphorus, CO2, and appropriate land resources as potential sustainability concerns of high importance. The committee did not consider any one of these sustainability concerns a definitive barrier to sustainable development of algal biofuels because mitigation strategies for each of those concerns have been proposed and are being developed. However, all of the

898

Biofuels

Table 13 BioBreak simulated mean willingness-to-pay (WTP), willingness-to-accept (WTA), and price gap (PG¼WTA–WTP) per dry ton without policy incentives in 2007 US$; the values of WTA are estimated for each feedstock at select percentiles over the 10,000 Monte Carlo simulations at an oil price of $111 per barrel. Conversion efficiency of biomass to fuel is assumed to be 70 gallons per dry ton biomass

Stover Stover – alfalfa Alfalfa Switchgrass Miscanthus Wheat straw SRWC Forest residues

WTA, US$

WTP, US$

PG, US$

PG per GGEa

92 92 118 133 115 75 89 78

25 26 26 26 26 27 24 24

67 66 92 106 89 49 65 54

1.43 1.42 1.97 2.28 1.90 1.04 1.39 1.16

a

GGE: gallon of gasoline equivalent. Source: Reproduced from National Research Council, Renewable fuel standard: potential economic and environmental effects of U.S. biofuel policy, The National Academic Press. Available from: http://nap.edu/13105; 2011 [accessed 12.07.16].

Table 14

Summary of economics of biofuel conversion per dry ton of feedstock Ethanol by fermentation 90 gal t

Single plant capital, million US$ Million gallons of fuel per year Million gallons of gasoline equivalent per year Cost to produce nth plant million US$ Pioneer plant, million US$ Number of plants to meet 16 billion gallons of ethanol equivalent biofuels in 2022 Capital costs for RPS2, billion US$ Price gap, billion US$ per year At US$52 per barrel At US$111 per barrel At US$191 per barrel Biomass feed requirements Million dry tons per year Million acres at 5 t per acre

1

70 gal t

1

Gasoline or diesel by gasification and F–T

Gasoline or diesel by pyrolysis with purchased H2

High temp.

Low temp.

High yield

380 69.5 46.3

380 52.4 34.9

606 41.7 41.7

498 32.3 32.3

200 58.2 58.2

375 650 230

500 850 305

430 800 256

480 750 331

210 350 183

88

116

155

165

37

25 10 10

39 24 3

31 16 4

37 21 1

8 7 28

178 36

236 47

175 35

226 45

133 27

Source: Reproduced from Anex RP, Aden A, Kazi FK, et al., Techno-economic comparison of biomass-to transportation fuels via pyrolysis, gasification, and biochemical pathways. Fuel 2010;89:S29–35; Aden A, Ruth M, Ibsen K, et al., Lignocellulosic biomass to ethanol process design and economics utilizing co-current dilute acid prehydrolysis and enzymatic hydrolysis for corn stover. Golden, CO: National Renewable Energy Laboratory (NREL); 2002; Swanson RM, Satrio JA, Brown RC, Hsu DD. Techno-economic analysis of biofuels production based on gasification. Golden, CO: NREL; 2010; Wright MM, Satrio JA, Brown RC, Saugaard DE, Hsu DD. Techno-economic analysis of biomass fast pyrolysis to transportation fuels. Golden, CO: National Renewable Energy Laboratory; 2010.

key sustainability concerns have to be addressed to some extent and in an integrative manner. Therefore, research, development, and demonstration are needed to test and refine the production systems and the mitigation strategies and to evaluate the systems and strategies if the sustainable development of algal biofuels has any chance of being realized.

1.22.6.6.4

Optimum cost of algae biomass

The quantity of algal biomass (MAB, tons) representing the energy equivalent of a barrel of crude petroleum is [89] MAB ¼

Epetroleum Qð12wÞEbiogas þ YwEbiodiesel

ð11Þ

where Epetroleum (B6100 MJ brl 1) is the energy contained in a barrel of petroleum, Q (m3 t 1) is the biogas volume produced by anaerobic digestion (400 m3 t 1), Ebiogas (MJ m 3) is the energy content of biogas (B2.4 MJ m 3), Y is the yield of biodiesel from

Biofuels

899

Acceptable cost of biomass (US$/ton)

700 Oil in algae: w=30% 600

w = 40%

500

w = 50%

400 300 200 100 0 50

100

150

200

Cost of petroleum ($/barrel) Fig. 12 Acceptable cost of biomass with oil percentages of w¼30%, w¼40%, and w ¼50% at a cost of petroleum estimated from Eq. (12). Reproduced from Chisti Y. Biodiesel from microalgae beats bioethanol. Trends in Biotechnol 2007;26:126–31.

Table 15

Possible bioproducts from microalgae

Chemicals

Usage

Approx. value, $ kg

Phycobiliproteins Astaxanthin Xanthophyll Beta‐carotene Health supplements Biofuels

Medical diagnostics Food supplement: human, animal, aquaculture Fish feeds Food supplement Dietary supplements Energy

410,000 42500 B1000 4500 B10 o1.0

1

Source: Reproduced from Zemke P, Wood B, Dye D. Technoeconomic analysis of algal photobioreactors for oil production. Utah State University. Available from: http://www.nrel.gov/biomass/pdfs/zemke.pdf; 2008 [accessed 20.07.16].

algal oil (80% by weight), Ebiodiesel is the average energy content of biodiesel (37,800 MJ t 1), and w is the oil content of algae biomass. Assuming that a barrel of crude oil has the same energy of M tons of algae, the maximum acceptable cost of algae CAlgae becomes CAlgae ¼

Cpetroleum Cpetroleum ¼ Qð1 MAB Epetroleum

wÞEbiogas þ YwEbiodiesel




ð12Þ

Fig. 12 shows the acceptable cost of algae biomass with respect to crude oil prices. When the cost of petroleum is $100 brl 1, biodiesel produced from algae oil costing $2.61 gal 1 is likely to be competitive with petroleum diesel. Table 15 shows some possible bioproducts from algae biomass with their selling prices. The table indicates that such bioproduct production from algae, besides the biofuels, may have positive impact on the overall economic feasibility of algae-based biofuels and technology.

1.22.7 1.22.7.1

Case Studies Biohydrogen Production

Fig. 13 shows the schematic of wind energy-based renewable hydrogen production. The system includes the transformer, thyristor, electrolyzer unit, feed water demineralizer, hydrogen scrubber, gas holder, two compressor units, deoxidizer, and twin tower dryer. For producing 1 kg H2, approximately 26.7 kg water is necessary. The total GHG emission is around 0.97 kg CO2e kg 1 H2 [90,91]. The hydrogen production cost is highly dependent on the electricity price, which may be around 75% of the final cost. Therefore electrolysis plants take advantage of low electricity prices at off-peak hours. These electrolyzers have energy efficiencies of 57%–75%. The typical current density is 100–300 mA cm 2 [90,91]. Table 16 shows the typical energy consumption in a Norsk Hydro bipolar alkaline electrolyzer.

900

Biofuels

Wind turbine

Electricity

Wind energy Transformer/ thyristor

KOH

O2/KOH gas separator

Electrolyzer

Oxygen

Deoxidizer

Dryer Hydrogen

9 kg h−1

Dionizer

KOH

H2/KOH gas separator

Water

Compression storage delivery

1 kg h−1

Production efficiency ~72%, Electrolyzer efficiency: ~62%; target: 76% (LHV) Target cost: $0.3 kg−1 H2 = gasoline of $2.5 GJ−1; Cost: $3.74−5.86 kg−1 H2 0.97 kg CO2−eq kg−1 H2 Fig. 13 Schematic for alkaline electrolysis of water for hydrogen production with compression, storage, and delivery Reproduced from Matzen M, Alhajji M, Demirel, Y. Chemical storage of wind energy by renewable methanol production: Feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53.

Table 16

Energy usage for the Norsk Hydro bipolar alkaline electrolyzer

High pressure (B16 bar) Atmospheric

System energy required kWh kg 1 H2

Hydrogen production at highest rate kg h 1 (kg year 1)

Electrolyzer energy required at maximum rate, kW

53.4 53.4

5.4 (47,000) 43.4 (380,000)

290 2300

Source: Reproduced from Norsk, Electrolyzer. (n.d.). Available from: http://large.stanford.edu/courses/2010/ph240/pushkarev2/docs/norsk_electrolysers. pdf; 2014 [accessed 10.02.16].

The H2 production cost is around $65 GJ 1 using wind electricity, $30 GJ 1 using nuclear power, and $600 GJ 1 using photovoltaic electricity based on 2007 US$ [92]. The cost of electrolytic hydrogen depends on the cost of electricity as well as the capital cost of the electrolyzer systems and their operating efficiency [93]. Capital cost of electrolyzer increases considerably as the wind farm availability and electrolyzer capacity decrease [92]. The unit cost estimates of wind power-based electrolytic H2 are also limited geographically and range from $3.74 kg 1 H2 to $5.86 kg 1 H2 [10]. Typical output concentrations are 99.9% to 99.9998% for H2 and 99.2% to 99.9993% for O2 [92,93].

1.22.7.2

Biomethanol Production

MeOH is produced almost exclusively by the ICI, the Lurgi, and the Mitsubishi processes. These processes differ mainly in their reactor designs and the way in which the produced heat is removed from the reactor. To improve their catalytic performance, the CuO/ZnO catalysts have been modified with various metals, such as chromium, zirconium, vanadium, cerium, titanium, and palladium [94,95]. During the synthesis these following reactions occur: CO2 þ 3H2 ¼ CH3 OH þ H2 O CO þ 2H2 ¼ CH3 OH CO2 þ H2 ¼ H2 O þ CO

DHo ð298KÞ ¼ DHo ð298KÞ ¼

49:4 kJ mol

90:55 kJ mol

1

1

DHo ð298KÞ ¼ þ 41:12 kJ mol

1

Only two of these reactions are linearly independent and their reaction rate equations can describe the kinetics of all the reactions [46,94]. Fig. 15 shows a process flow diagram to produce MeOH using hydrogen and CO2, which is designed and simulated using Aspen Plus software and the RK-SOAVE equation of state. Wind-based electrolytic H2 and CO2 supplied from an ethanol plant are used in the synthesis of MeOH. The plant uses 18.6 mt H2 day 1 and 138.4 mt CO2 day 1, and produces 96.9 mt MeOH day 1 at 99.5 wt% together with 55.0 mt day 1 at 99 wt% of wastewater. Fig. 14 presents the process flow diagram for the MeOH plant using CO2 and H2. The feedstock is at the conditions associated with typical storage, with H2 at 251C and 33 bar and CO2 at 25.61C and 16.422 bar (liquid phase) [46]. The ratio of H2 to CO2 is held at 3:1 to promote MeOH synthesis. In the feed preparation block, the renewable H2 and CO2 are compressed to 50 bar in a multistage compressor and pump, respectively, and mixed with the recycle stream S12 in mixer M101. Stream S1 is preheated in HX101 and E101 before being fed into the plug-flow reactor R101 where the MeOH synthesis takes place. Table 17 shows the stream table for the process shown in Fig. 14 [46,95].

901

Biofuels

Stream tables highlighting the input and output streams for the methanol (MeOH) production facility

Table 17

H2-IN Temperature (1C) Pressure bar Vapor Frac Mass flow mt day Enthalpy Gcal h 1 Mass fraction CO2 CO H2 H2O MeOH Mole fraction CO2 CO H2 H2O MeOH

25 33 1 18.563 0.003

1

CO2-IN 25.6 16.422 0 138.367 12.817 1

1

1 1

MeOH

(W) Water

Flue

BFW

25 1.013 0 97.011 7.333

25 1.013 0 54.643 8.702

24.9 1.013 1 5.284 0.44

0.002

trace

trace 0.003 0.995

0.995 0.005

0.86 trace 0.037 0.004 0.098

0.001

trace

6 PPB 0.006 0.993

0.997 0.003

Steam

233 30 0 92.775 13.84

0.474 trace 0.446 0.006 0.074

233 30 1 92.775 12.103

1

1

1

1

Source: Reproduced from Matzen M, Alhajji M, Demirel Y. Chemical storage of wind energy by renewable methanol production: feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53.

S11

S10

SF101

C102 5.3 mt day−1

S4

18.6 mt day−1

S12

Net-Flue S9

R101

H2-IN

S3

C101

S7

M101 S1

E101

TF-IN

F102

97.0 mt day−1

S5

TF-OUT

CO2-IN

S8

S2

HX101 138.4 mt day−1

F101

E103

P101

Methanol

E105

STMDRM

S6

E102

T101 54.6 mt day−1 (W) Water

BFW

E104 92.8 mt day−1 Steam

Fig. 14 Process flow diagram of the methanol (MeOH) plant with steam production. Reproduced from Matzen M, Alhajji M, Demirel, Y. Chemical storage of wind energy by renewable methanol production: feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53.

The energy efficiency for the concentrated CO2 and hydrogen-based MeOH is around 46% [82]. Fig. 15 shows a schematic of wind electricity-based hydrogenation of CO2 to MeOH. The total emissions of CO2 from each unit are 127.94 mt CO2 day 1 for the MeOH production, 18.01 mt CO2 day 1 for the H2 production, and 6.10 mt CO2 day 1 for the CO2 capture and storage. If the MeOH is used as an intermediate feedstock for producing another chemical this leads to fixation of carbon and causes reduction of approximately 1.07 kg CO2 per kg of MeOH produced (see Table 18). The cost of renewable hydrogen and the selling price of MeOH affect the economics of the renewable MeOH [45,46]. We have evaluated the final NPV for varying MeOH prices and hydrogen prices; the results can be seen in Fig. 16(A). The minimum selling price of MeOH was also investigated with varying hydrogen production cost (seen in Fig. 16(B)). This is the selling price of MeOH that makes the NPV ¼ 0 after 10 years. The inclusion and exclusion of O2 sales was also investigated in Fig. 16(B). The use of renewables in the production of MeOH would not only avoid the issues associated with an increase in fossil fuel cost but also would eliminate MeOH’s dependency on fossil fuel feedstocks. Since MeOH can be used as a fuel source itself, its production from renewables would help to recycle CO2 and reduce the reliance of our energy and transportation sectors on fossil fuels (Fig. 17). Olah presents this idea in a very concise term called the “MeOH Economy” [83]. Put short, this concept purveys the idea that methanol can be used as an alternative way for storing, transporting, and using energy [96,97].

902

Biofuels

Biomass

Ethanol Ethanol plant CO2

Food Ind. Integrated methanol production facility

138.4 mt day−1 CO2 capture and storage Cap. cost: $37,890 mt−1 CO2;0.06 kg CO2 mt−1

−1.07 kg CO2 kg−1 methanol

day−1

96.9 mt methanol production Cap. cost: $280,280 mt−1 methanol −1.32 kg CO2 kg−1 methanol

18.6 mt/day wind-H2 production Cap. cost: $30,733 mt−1 H2; 0.97 kg CO2 mt−1

Methanol as chemical feedstock

Grid

0.30 kg CO2 kg−1 methanol

Oxygen

Wind power

Methanol as fuel 22.7 GJ mt −1 methanol (HHV) CH3OH + 3/2O2

CO2 + 2H2O

Fig. 15 Some economic and sustainability indicators in the integral methanol (MeOH) production facility. Reproduced from Matzen M, Alhajji M, Demirel, Y. Chemical storage of wind energy by renewable methanol production: feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53. Table 18

Sustainability metrics for the integral methanol (MeOH) plant

Material intensity CO2 used/unit product H2 used/unit product

1.43 0.19

Energy intensity Net duty/unit product, MWh mt 1 Net duty cost/unit product, $ mt 1

0.39 825.61

Environmental impact Total CO2e/unit product Net carbon fee/unit product, $ mt

1

1.07 2.11

Note: US-EPA-Rule E9-5711; fuel source: natural gas; carbon fee: $2/mt CO2. Source: Reproduced from Matzen M, Alhajji M, Demirel Y. Chemical storage of wind energy by renewable methanol production: feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53.

1.22.7.3

Biodimethyl Ether Production

Biodimethyl ether can be produced from MeOH using wind power-based electrolytic hydrogen and CO2 captured from an ethanol fermentation process. MeOH and DME from CO2 hydrogenation may outperform conventional petroleum-based fuels, reducing GHG emissions 82%–86%, minimizing other criteria pollutants (SOx, NOx, etc.), and reducing fossil fuel depletion by 82%–91% [73,98]. Biodimethyl ether production was modeled in Aspen Plus using a previously simulated MeOH production facility (Fig. 18). The facilities use 18.6 mt of H2 and 138.4 mt CO2 per day. Biomethanol is produced at a rate of 96.7 mt/day (99.5 wt%) and DME is produced at a rate of 68.5 mt/day (99.6 wt%). Renewable MeOH and DME results were independently compared and this renewable process was also compared to conventional production routes. Results show that production of DME impacts the environment more than MeOH production. The largest environmental impact was found to be related to the fuel production stage for both fuels. Nonnormalized indicators for the entire process can be found in Table 19. It should be noted that these values are strictly for the production stages of these chemicals (cradle-to-gate). Fuel combustion and the influence of using biogenic CO2 are not accounted for [73].

1.22.7.4

Methyl Dodecanoate (Biodiesel)

Production of methyl dodecanoate (biodiesel) using lauric acid and MeOH with a solid acid catalyst of sulfated zirconia uses two distillation sequences where the reactive distillation and MeOH recovery columns are thermally coupled (Fig. 19). This sequence may consume less energy by allowing interconnecting vapor and liquid streams between the two columns to eliminate reboiler or

903

Biofuels

$400 mt−1 MeOH

$500 mt−1 MeOH

$600 mt−1 MeOH

$700 mt−1 MeOH

with O2 sales

w/o O2 sales

1300

55.00

1150 Methanol selling price ($ mt−1)

NPV (million $)

35.00 15.00 −5.00 −25.00 −45.00

1000 850 700 550 400

−65.00 0.50

250 1.00

1.50

H2 production cost ($

(A)

kg−1

2.00 H2)

0

0.5

1

1.5

2

H2 production cost ($

(B)

kg−1

2.5

3

H2)

Fig. 16 The influence of H2 production cost on: (a) net present value at constant methanol (MeOH) price, (b) selling price of MeOH for NPV ¼0 with and without selling O2 byproduct at $100 mt 1. Reproduced from Matzen M, Alhajji M, Demirel Y. Chemical storage of wind energy by renewable methanol production: feasibility analysis using a multi-criteria decision matrix. Energy 2015;93:343–53; Methanex. Current posted prices. Available from: https://www.methanex.com/our-business/pricing; 2015 [accessed 09.07.15]; Chesko J. Methanol industry outlook [presentation slides]. Vancouver: Methanex; 2014.

Oil

Demand 75

900

70

800

65

700

60

600

55

500

50

400

45

300

2015

2014

2013

2012

2011

2010

2009

2008

2007

30 2006

0 2005

35 2005

100 2004

40

2003

200

Methanol demand (1000 MT)

Price ($ mt−1)

Methanol 1000

Year Fig. 17 Methanol (MeOH) price and demand in recent history. Reproduced from Methanex. Current posted prices. Available from: https://www. methanex.com/our-business/pricing; 2015 [accessed 09.07.15]; Chesko J. Methanol industry outlook [presentation slides]. Vancouver: Methanex; 2014.

condenser or both [99]. Table 20 summarizes the stream properties for the process shown in Fig. 19. Stream METH combined with stream S3B in mixer M101 is preheated to 1101C in heat exchanger HX102 before it is fed to the bottom of the reaction zone at stage 29 of RD101. The feeds enter at both ends of the reaction zone to maximize conversion [99]. The plant produces around 99.2 wt% of 21,527 kg h 1 of methyl dodecanoate and dilute concentration of MeOH in water as summarized in Table 20. Column T101 recovers MeOH from water and recycles. The column operates with 12 stages, with a kettle reboiler and a total condenser. The activity coefficient model of NRTL is used for predicting the equilibrium and liquid properties in column T101. The top product, stream S3A, containing mostly MeOH, is pressurized before it is recycled. The bottom product, stream WATA, is treated as a waste [99].

1.22.8

Future Directions

Biomass is a main component of the food supply chain, and also represents a stored renewable carbon and energy source. Therefore, it is a future challenge to increase the biofuel production from the second and third generations, and waste biomass feedstock resources. Improving the technologies of production and increasing the variety of value-added byproducts would be essential for the economic feasibility of the biofuel sector [89,99,100]. Biofuel share within the energy supply chain is still very

904

Biofuels

AIR-IN

HX203 Flue R202

MEOH-FLU

S7 S3

S4

S8 H2-IN

Meohprod

CO2-IN

Hierarchy

DME

E201 E202

S1

S6

HX202

P201

T201

MEOH-WW

S2 HX201

R201

T202

J201 S5 W S10

S9 NET-WW

Fig. 18 Process flow diagram for the backend dimethyl ether (DME) facility. Reproduced from Matzen M, Demirel Y. Methanol and dimethyl ether from renewable hydrogen and carbon dioxide: Alternative fuels production and life-cycle assessment. J Cleaner Prod 2016;139:1068–77.

Table 19

Nonnormalized environmental impacts for mt of product (methanol (MeOH) or dimethyl ether (DME)) 1

product

Indicator

MeOH

DME

Unit mt

Global warming potential Acidification potential Photochemical oxidant formation Particulate matter (PM) formation Human toxicity

0.30 0.67 0.69 0.29 0.10

0.53 0.97 1.17 0.44 8.18

mt CO2 eq kg SO2 eq kg NMVOC eqa kg PM10 eq kg 1,4-DB eqb

a

NMVOC: nonmethane volatile organic compound. 1,4-DB: 1,4 dichlorobenzene. Source: Reproduced from Matzen M, Demirel Y. Methanol and dimethyl ether from renewable hydrogen and carbon dioxide: alternative fuels production and life-cycle assessment. J Cleaner Prod 2016;139:1068–77.

b

small and needs to be increased with improved technology and reduced unit cost of production. Within the biorefinery and multigeneration settings the unit cost of biofuels can be reduced, because the current cost of biofuels is not competitive enough with those of fossil fuels. Distributed versus centralized biorefinery concepts should also be fully analyzed for an optimum process setting for sustainable biofuel production, regional economic development, and environmental protection [55,87,101].

1.22.9

Closing Remarks

Biomass is a renewable carbon source with built-in energy storage, contrary to solar and wind energy sources. At the same time, biomass usage may compete with food production accompanied with land and water requirements. Compared with the fossil fuel, nuclear, and water resources, renewable resources are abundant and more uniformly distributed worldwide. Biomass feedstock as a renewable source may play an important role for sustainable energy supply and hence development. With around 5%–15% available cropland up to 6% displacement of fossil fuels may be possible [47]. Mainly the United States and European Union are setting ambitious production levels and leading in the research and development of biofuel conversion processes from various feedstocks to reduce the cost and increase the energy conversion efficiency. This may be encouraging for biofuel usage worldwide and may reduce the adverse effects of fossil fuels on climate change. Production of biofuels depends on the availability and cost of biomass feedstock. Economic analyses estimate the cost of different types of biomass for producers as well as the cost of converting biomass to biofuel. The intersection of the newly emerging biofuel market with established markets in agriculture, forestry, water, and energy is causing substantial economic impacts on the prices of agricultural commodities, food, feedstuffs, forest products, fossil fuel energy, and land values because of the competition for feedstock created by increased production of biofuels.

905

Biofuels

P101

S3B

S3A H101 ESTERD ESTERC WATMET

HX101

LAURIC

T101 P102 S4B

S1

S4A

ESTERB RD101

M101 S2A

METH

WATA

S2B

H102

HX102 WATB ESTERA Fig. 19 Process flow diagram for biodiesel (methyl dodecanoate) production. Reproduced from Nguyen N, Demirel Y. Using thermally coupled reactive distillation columns in biodiesel production. Energy 2011;36:4838–47.

Table 20

Stream properties of the thermally coupled design LAURIC

METH

ESTERD

WATMET

WATB

Mass flow (kg h 1) Temperature (1C) Pressure (bar) Vapor fraction Enthalpy (kcal mol 1)

20,032.14 25.00 9.0 0 176.42

3364.43 25.00 9.5 0 56.98

21,526.71 25.00 1.0 0 159.90

5036.00 155.50 9.0 1 51.97

1869.83 25.00 1.0 0 68.30

Mass flow (kg h 1) Water Methanol (MeOH) Lauric acid Metester

0.00E þ 00 0.00E þ 00 2.00E þ 04 0.00E þ 00

0.00E þ 00 3.36E þ 03 0.00E þ 00 0.00E þ 00

1.79E-01 1.34E þ 02 3.79E þ 01 2.14E þ 04

1.93E þ 03 3.06E þ 03 9.99E þ 00 3.30E þ 01

1.80E þ 03 3.41E þ 01 9.64E þ 00 2.90E þ 01

Mass fraction Water MeOH Lauric acid Metester

0.0000 0.0000 1.0000 0.0000

0.0000 1.0000 0.0000 0.0000

0.0000 0.0062 0.0018 0.9920

0.3838 0.6076 0.0020 0.0066

0.9611 0.0182 0.0052 0.0155

Source: Reproduced from Nguyen N, Demirel Y, Using thermally coupled reactive distillation columns in biodiesel production. Energy 2011;36:4838–47.

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Further Reading Sodamade A, Oyedepo TA, Bolaji OS. 2013. Fatty acids composition of three different vegetable oils (soybean oil, groundnut oil and coconut oil) by highperformance liquid chromatography. Chem Mat Res 2013;3:26–9. Van-Dal ES, Bouallu C. 2013. Design and simulation of a methanol production plant from CO2 hydrogenation. J Clean Prod 2013;57:38–45. Weiduan S, Zhang J, Bingchen Z, et al. 1989. Kinetics of methanol synthesis in the presence of C301 Cu-based catalyst (i) intrinsic and global kinetics. J Chem Ind and Eng (China) 1989;4:248–57.

Relevant Websites https://www.chevron.com/stories/biofuels Chevron.

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https://ec.europa.eu/energy/en/topics/renewable-energy/biofuels European Commission. http://www.nationalgeographic.com/environment/global-warming/biofuel/ National Geographic. https://www.nrel.gov/workingwithus/re-biofuels.html National Renewable Energy Laboratory (NREL). https://www.scientificamerican.com/article/the-next-generation-of-biofuels/ Scientific American. http://needtoknow.nas.edu/energy/energy-sources/emerging-technologies/biofuels/ The National Academics of Sciences, Engineering, Medicine. https://www.epa.gov/environmental-economics/economics-biofuels United States Environmental Protection Agency (EPA).

1.23 Energy and Air Pollution Zhihua Wang, Zhejiang University, Hangzhou, People’s Republic of China r 2018 Elsevier Inc. All rights reserved.

1.23.1 1.23.1.1 1.23.1.2 1.23.1.2.1 1.23.1.2.2 1.23.1.2.3 1.23.1.2.4 1.23.1.2.5 1.23.1.2.6 1.23.1.3 1.23.2 1.23.2.1 1.23.2.1.1 1.23.2.1.2 1.23.2.1.3 1.23.2.2 1.23.2.2.1 1.23.2.2.2 1.23.2.2.3 1.23.2.2.3.1 1.23.2.2.3.2 1.23.2.2.3.3 1.23.2.2.3.4 1.23.2.2.4 1.23.2.3 1.23.2.3.1 1.23.2.3.2 1.23.2.3.3 1.23.2.4 1.23.2.4.1 1.23.2.4.2 1.23.2.4.3 1.23.2.5 1.23.2.5.1 1.23.2.5.2 1.23.2.5.3 1.23.2.5.4 1.23.3 1.23.3.1 1.23.3.1.1 1.23.3.1.2 1.23.3.1.3 1.23.3.1.4 1.23.3.1.5 1.23.3.1.6 1.23.3.1.7 1.23.3.2 1.23.3.2.1 1.23.3.2.2 1.23.3.3 1.23.3.3.1 1.23.3.3.1.1 1.23.3.3.1.2

Energy in the World World Energy Consumption Energy Consumption in Typical Countries Energy consumption in China Energy consumption in the United States Energy consumption in the European Union Energy consumption in Japan Energy consumption in India Energy consumption in Africa Air Pollution From Fossil Fuels Energy-Related Air Pollution Particulate Matter What is particulate matter? Sources of particulate matter What are the harmful effects of particulate matter? Sulfur dioxide SO2 What is sulfur dioxide? What are the sources of SO2? What are the harmful effects of SO2? To body health To plants To buildings To the environment What’s being done to manage sulfur dioxide? NOx What are the sources of NOx? What are the harmful effects of NOx? Global warming effect by NOx Heavy Metals What are the sources of heavy metals? What are the harmful effects of heavy metals? Global emission estimates of heavy metals Volatile Organic Compounds What are volatile organic compounds? What are the sources of volatile organic compounds? What are the harmful effects of volatile organic compounds? How to reduce the levels of indoor volatile organic compounds? Air Pollution Control Technology Development Fabric Filter and Electrostatic Precipitator for Particulate Matter Control Classification of precipitators Introduction of fabric filter Principles of fabric filter Features of fabric filter Introduction of electrostatic precipitator Principles of electrostatic precipitator Features of electrostatic precipitator Wet Electrostatic Precipitator for Particulate Matter Control Principles of wet electrostatic precipitator Features of wet electrostatic precipitator Wet Flue Gas Desulfurization for SO2 Removal Limestone/lime flue gas desulfurization Sulfur dioxide absorption Lime flue gas desulfurization chemical reactions

Comprehensive Energy Systems, Volume 1

doi:10.1016/B978-0-12-809597-3.00127-9

911 911 913 913 913 914 914 914 915 915 917 917 917 918 919 919 919 919 919 919 920 920 920 920 920 920 920 921 921 921 922 922 922 922 922 923 923 923 924 924 924 924 924 925 925 926 926 927 927 927 928 928 929

909

910

Energy and Air Pollution

1.23.3.3.1.3 1.23.3.3.1.4 1.23.3.3.1.5 1.23.3.3.1.5.1 1.23.3.3.1.5.2 1.23.3.3.1.5.3 1.23.3.3.1.5.4 1.23.3.3.1.5.5 1.23.3.3.2 1.23.3.3.2.1 1.23.3.3.2.1.1 1.23.3.3.2.1.2 1.23.3.4 1.23.3.4.1 1.23.3.4.2 1.23.3.4.3 1.23.3.4.3.1 1.23.3.4.3.2 1.23.3.4.3.3 1.23.3.4.4 1.23.3.4.5 1.23.3.4.5.1 1.23.3.4.5.2 1.23.3.4.6 1.23.3.5 1.23.3.5.1 1.23.3.5.2 1.23.3.5.3 1.23.3.5.4 1.23.3.5.5 1.23.3.6 1.23.3.6.1 1.23.3.6.2 1.23.3.6.2.1 1.23.3.6.2.2 1.23.3.6.2.3 1.23.3.6.2.4 1.23.3.6.2.4.1 1.23.3.6.2.4.2 1.23.3.6.2.4.3 1.23.3.6.3 1.23.3.6.3.1 1.23.3.6.3.1.1 1.23.3.6.3.1.2 1.23.4 1.23.4.1 1.23.4.1.1 1.23.4.1.2 1.23.4.1.2.1 1.23.4.1.2.2 1.23.4.1.2.3 1.23.4.1.2.4 1.23.4.1.3 1.23.4.2 1.23.4.2.1 1.23.4.2.2 1.23.4.2.3 1.23.4.2.4 1.23.4.2.4.1

Limestone flue gas desulfurization chemical reactions Limestone/lime flue gas desulfurization with forced oxidation Process design and operation factors of limestone/lime flue gas desulfurization process Stoichiometric ratio Liquid–gas ratio pH value Relative saturation Wet flue gas desulfurization system parameters Sodium-based wet flue gas desulfurization Regenerative processes Wellman–Lord process Magnesia scrubbing process Selective Catalytic Reduction and Selective Noncatalytic Reduction for NOx Removal Introduction of selective catalytic reduction Selective catalytic reduction chemistry Different layouts of selective catalytic reduction reactor High temperature and high dust layout High temperature and low dust layout Low temperature and low dust layout Introduction of selective noncatalytic reduction Selective noncatalytic reduction chemistry Ammonia selective noncatalytic reduction Urea selective noncatalytic reduction Characteristics of selective noncatalytic reduction Multipollution Control New Technology Solid phase adsorption and regeneration method Plasma and ammonia method Oxidation method SOx-NOx-Rox Box high-temperature baghouse Ozone oxidation with wet flue gas desulfurization absorption method Stack Height Calculation Introduction The calculation of stack height Stack exit diameter The stack height according to the requirements of environmental protection Noteworthy problems Check stack height according to force requirement Draft of stack Kinetic energy of stack outlet flue gas h1 Total fractional resistance of stack Example The calculation of stack height The calculation of stack inner diameter Check stack draft New Energy and Low Carbon Energy Biomass Biomass resources Biomass conversion technology Biomass solid shaping Thermochemical conversion Biomass direct combustion Microbial conversion Prospects Carbon Capture and Storage Gasification Oxy-fuel combustion Precombustion capture Postcombustion capture Soak-up method

929 929 930 930 930 930 931 931 931 931 931 931 932 932 932 933 933 933 934 934 935 935 935 936 936 936 936 937 937 937 938 938 938 938 938 939 940 940 940 940 940 940 941 941 941 941 942 942 942 942 942 942 942 942 943 943 944 944 945

Energy and Air Pollution 1.23.4.2.4.2 Absorption method 1.23.4.2.4.3 Membrane separation 1.23.4.2.4.4 Cryogenic method 1.23.5 Conclusions References Relevant Websites

1.23.1 1.23.1.1

911 945 945 946 946 947 949

Energy in the World World Energy Consumption

Energy is an essential resource for the survival of humanity. It is the basis of and the power behind social and economic development, playing a leading role in the progress of human culture. With the demand for energy continuously increasing in recent years, the energy issue has become one of the biggest concerns across the world; and therefore, people pay more and more attention to global environmental protection and the development of new energy. Depending on the source, energy can be divided into primary and secondary energy sources. The primary energy source is the energy from nature and without any conversion, such as raw coal, crude oil, natural gas, oil shale, nuclear energy, wind power, solar power, etc. The secondary energy source is from the conversion of primary energy, such as electrical energy, steam power, coal gas, gasoline, etc. From the statistical review of world energy in 2016 [1], oil, natural gas, and coal still take the dominant role in world energy consumption. Table 1 gives the consumption structure of world energy from 2008 through 2015. It can be found that overall the consumption of oil and natural gas decreased in recent years. However, hydroelectricity, nuclear power, and renewable energy show stable development. Fig. 1 gives the world consumption of primary energy. The world consumption of primary energy increased slightly by 1.0% in 2015, which is lower than the average level of recent years. Actually, it is the lowest growth since 1998 (except in 2008 when the global economic crisis happened). Oil is still the major fuel in the world; and in 2014, for the first time since 1999, the market share of oil increased. In 2015, the consumption of oil grew by 1.9%, or 1.9 million barrels per day, which is nearly double the recent historical average growth (1%). Among these growths, the largest increment was in China, which grew by 0.77 million barrels per day. Up until the end of 2015, the total proven global reserve of oil was 1697.6 billion barrels, which can satisfy global demand for approximately 50.7 years. Natural gas accounts for 23.8% of the global primary energy consumption. The increment of natural gas production in 2015 was 2.2%, which exceeded the increment of consumption but was still lower than the average increment (2.4%) in the past 10 years. Up until the end of 2015, the total proven global reserves of natural gas was 186.9 trillion cubic meters, which can satisfy the global demand for 52.8 years. Coal is the second largest fuel, based on its market share. However, the market share of coal in 2015 declined to the lowest level since 2005. The consumption of coal decreased by 1.8% in 2015, while it had an average increment of 2.1% for the past 10 years and accounted for 29.2% of primary energy consumption. Up until the end of 2015, the total proven global reserve of coal was 891.531 billion tons, which can satisfy the global demand for 114 years. Renewable energy is mainly from wind power, solar power, and biofuels, which are inexhaustible and eco-friendly. The power from renewable energy accounted for 2.8% of the world consumption of primary energy in 2015, which was 364.9 million tons oil equivalent. However, this value was only 0.8% ten years before. Among the renewable energy sources, wind power is still the largest renewable electricity source, which accounted for 52.2% of all the renewable energy electricity production. The consumptions for nuclear energy and hydroelectricity were 583.1 and 892.9 million tons oil equivalent, accounting for 4.4% and 6.8% of the global primary energy consumption, respectively.

Table 1 Year

2008 2009 2010 2011 2012 2013 2014 2015

Consumption structure of world energy from 2008 through 2015. Percentage of total primary energy consumption (%) Oil

Natural gas

Coal

Hydroelectricity, nuclear energy, and other renewable energy

34.8 34.8 33.6 33.4 33.1 32.6 32.7 32.9

24.1 23.8 23.8 23.8 23.9 23.8 23.7 23.8

29.2 29.4 29.6 29.7 29.9 30.2 30.0 29.2

11.9 12.1 13.0 13.1 13.1 13.3 13.6 14.0

Source: Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

Energy and Air Pollution

912

14,000

Coal Renewables Hydroelectricity Nuclear energy Natural gas Oil

13,000 12,000 11,000 10,000 9000 8000 7000 6000 5000 4000 3000 2000 1000

90

91

92

93

94

95

96

97

98

99

00

01

02

03

04

05

06

07

08

09

10

11

12

13

14

0

15

Fig. 1 World consumption of primary energy (million tons oil equivalent). Reproduced from BP. Statistical Review of World Energy. http://www. bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

Coal Renewables Hydroelectricity

Nuclear energy Natural gas Oil 100 90 80 70 60 50 40 30 20 10

North America

South and Central America

Europe and Eurasia

Middle East

Africa

Asia Pacific

0

Fig. 2 Regional consumption of fuel in 2015. Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/ energy-economics/statistical-review-of-world-energy.html; 2016.

Fig. 2 shows the regional consumption of fuel in 2015. Oil was still the major fuel in Africa and America. However, natural gas was the major fuel in Europe and Eurasia, and the Middle East, accounting for 51% of the local energy consumption. Europe and Eurasia was the only region where no fuel accounted for more than one-third of the energy consumption, which means that the

Energy and Air Pollution

History

2012

913

Projections

250 Liquids

200

Coal with CPP

150

Renewables with CPP Coal

Natural gas

100 Renewables

50 Nuclear

0 1990

2000

2012

2020

2030

2040

Fig. 3 World energy consumption by energy source, 1990–2040 (quadrillion Btu). Note: dotted lines for coal and renewables show projected effects of the US Clean Power Plant. Reproduced from U.S. Energy Information Administration. International Energy Outlook 2016. http://www.eia. gov/forecasts/ieo/; 2016. Table 2

Structure of the primary energy consumption in China in 2015.

Country

Crude oil (%)

Natural gas (%)

Raw coal (%)

Nuclear (%)

Hydroelectricity (%)

Renewable energy (%)

Sum (Mtoe)

China

18.6

5.9

63.7

1.3

8.5

2.1

3014.0

Source: Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

region had a large diversity of fuel usage. The Middle East has the least diversity of fuel usage, where the consumption of oil and natural gas accounted for 98% of total energy consumption. According to International Energy Outlook 2016 (IEO 2016) [2], over the 28 years from 2012 through 2040, fossil fuels would continue to be the largest source of the world’s energy. As shown in Fig. 3, in 2040, natural gas, liquid fuels, and coal would account for 78% of total world energy consumption. Petroleum and other liquid fuels would remain the largest source of energy, although their market share in primary energy consumption was predicted to decline from 33% in 2012 to 30% in 2040. The world’s total natural gas consumption would increase by 1.9% per year on average, from 3.34 trillion cubic meters in 2012 to 3.76 trillion cubic meters in 2020 and 5.75 trillion cubic meters in 2040. Coal would be the slowest-growing energy source, with an average increase of 0.6% per year of the total world coal consumption from 2012 to 2040. Coal consumption projection in the IEO 2016 was predicted to be in total 169 quadrillion Btu in 2020 and 180 quadrillion Btu in 2040. As renewable energy sources, hydropower and wind power will be the two largest contributors to the increase of the world’s electricity generation, accounting for two-thirds of the total increment from 2012 to 2040. The increment was predicted to be about 1.9 trillion kilowatt-hours (kWh) for both hydropower and wind power generation.

1.23.1.2 1.23.1.2.1

Energy Consumption in Typical Countries Energy consumption in China

Over the past 2.5 decades since the reforms and opening-up, China’s economy has been developing rapidly with tremendous achievements. So has its energy consumption. China’s energy consumption took 22.9% of the total global primary energy use in 2015. The demand for energy was more than three times higher than what it was 25 years before. Moreover, of this increased demand, 90% was met by fossil fuels. The structure of the primary energy consumption in China in 2015 is shown in Table 2. In China, three-quarters of the country’s electricity was generated by coal. Coal and oil generated two-thirds of energy consumed in industry and the transportation sector, and more than 90% of the energy used for transportation was generated from oil. On the other hand, the rapid development speed has resulted in severe air pollution issues. Today, around 55% of the pollution in China has reached to levels even greater than the most modest WHO interim target-1 [3].

1.23.1.2.2

Energy consumption in the United States

The United States used 17.3% of the total global primary energy in 2015. Thus, the country became the second largest energy consumer after China in the world. The majority of this energy derived from fossil fuels. In the United States, crude oil took the largest proportion of energy structure (Table 3). Also, natural gas played an important role. Although in the recent years, due to the discovery of shale gas, the renewable energy, including biomass, wind power, geothermal and solar energy, made up only a small fraction in the energy structure of the United States.

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Table 3

Structure of the primary energy consumption in the United States in 2015.

Country

Crude oil (%)

Natural gas (%)

Raw coal (%)

Nuclear (%)

Hydroelectricity (%)

Renewable energy (%)

Sum (Mtoe)

USA

37.3

31.3

17.4

8.3

2.5

3.1

2280.6

Source: Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

Table 4

Structure of the primary energy consumption in European countries in 2015.

Country

Crude oil (%)

Natural gas (%)

Raw coal (%)

Nuclear (%)

Hydroelectricity (%)

Renewable energy (%)

Sum (Mtoe)

England France Germany Italy Spain Denmark

37.4 31.9 34.4 39.1 45.0 47.9

32.1 14.8 21 36.5 18.5 17.1

12.2 3.6 24.4 8.2 10.7 10.6

8.3 41.4 6.5 – 9.6 –

0.7 5.1 1.4 6.5 4.7 o0.05

9.1 3.3 12.5 9.7 11.5 25.3

191.2 239.0 320.6 151.7 134.4 16.9

Source: Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

Table 5

Structure of the primary energy consumption in Japan in 2015.

Country

Crude oil (%)

Natural gas (%)

Raw coal (%)

Nuclear (%)

Hydroelectricity (%)

Renewable energy (%)

Sum (Mtoe)

Japan

42.3

22.8

26.6

0.2

4.9

3.2

448.5

Source: Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

Table 6

Structure of the primary energy consumption in India in 2015.

Country

Crude oil (%)

Natural gas (%)

Raw coal (%)

Nuclear (%)

Hydroelectricity (%)

Renewable energy (%)

Sum (Mtoe)

India

27.9

6.5

58.1

1.2

4.0

2.2

700.5

Source: Reproduced from BP. Statistical Review of World Energy. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html; 2016.

The national energy consumption of the United States was mainly in four sectors: industrial, transportation, residential, and commercial. The industrial sector has long been the country’s largest energy user, currently representing about 33% of the overall energy consumption. The second largest one was the transportation sector, followed by the residential and commercial sectors [4].

1.23.1.2.3

Energy consumption in the European Union

Renewable energy has developed rapidly in Europe in recent years. From Table 4, it can be found that compared with the United States and China, renewable energy took a larger proportion in the European Union. As for electricity generation usage, the proportion of renewable energy was even higher. In Germany and Italy, net generated electricity from renewable sources accounted for about 30% and 38.2% of the overall figure in 2014, respectively. In France, the highly developed nuclear power industry took more than 40% share in the energy structure.

1.23.1.2.4

Energy consumption in Japan

Japan is a country that lacks domestic reserves of fossil fuel, except for coal, and therefore, requires importing a large amount of crude oil, natural gas, and even nuclear resources, i.e., uranium. In 2010, 42% of crude oil consumption depended on imports in Japan [5]. Table 5 shows the structure of Japan’s energy consumption in 2015. Before the Fukushima Daiichi nuclear disaster in 2011, nuclear power met about 25% of the overall electricity consumption in Japan. However, after that incident, many nuclear power plants have been shut down. Now, nuclear power only accounts for a small portion of energy supply in Japan.

1.23.1.2.5

Energy consumption in India

Now that the growth of China’s economy is slowing down, China has become less energy-intensive. Meanwhile, India is assumed to take the role of “prime motor of global energy demand” in the future. Currently, India consumes only 6% of the world’s energy with over one-sixth of the world’s population. Apparently, there will be a rising demand for energy to support the development of India’s economy. Coal is the core fuel in India’s power system (Table 6). According to the World Energy Outlook Special Report 2016, coal accounted for almost 75% of the power supply. Heavy usage of coal also leads to pollution issues in India.

Energy and Air Pollution 1.23.1.2.6

915

Energy consumption in Africa

Energy demand in Africa has risen by 50% since 2000, although the per-capita energy demand remains low, i.e., about one-third of the global average. Biomass dominates the main part of the energy structure, accounting for almost half of the energy demand across Africa. Only 43% of the population in Africa has access to electricity today. Per-capita electricity consumption in Africa is 20% of the global average and differs widely from country to country. Most countries in northern Africa have adequate power supply while in sub-Saharan Africa only one-third of the population has access to electricity, and this figure falls to just 17% when looking at the rural population. The shortage of electricity not only causes inconvenience for people’s lives but also hinders the development of industrial activities. Fossil fuels are mainly used to produce electricity. South Africa, which owns almost 60% of all the power in sub-Saharan Africa, derives 94% of its energy from coal.

1.23.1.3

Air Pollution From Fossil Fuels

When contaminants’ concentration in the air reaches a dangerous level, i.e., higher than the limits of the environmental quality standards and causing harm to people’s health, we call it air pollution. Air pollution happens for many different reasons. In nature, air pollution takes place from volcanic eruptions, forest fires, plant pollen, and dust blown by wind. However, in human society, the main cause of air pollution is due to human activities, which produce a large amount of pollution all over the world. One of the main sources of air pollution is burning fossil fuels like oil, gasoline, and coal. These fossil fuels come from the fossils of ancient plants and animals that lived on Earth millions of years ago. Fossil fuels are burned to produce energy so that we can drive cars and trucks, fly planes, generate electricity, and run factories. In the process of the combustion of fossil fuels, pollutants such as particulate matter (PM), SO2, and NOx will be released; at the same time, a significant amount of CO2, which intensifies the greenhouse effect, will also be released. The evaporation or incomplete combustion of fuels, as well as natural sources, will release volatile organic compounds (VOCs). Certain biological and organic pollutants can cause the canceration, distortion, and mutation of human body. In addition, unburned methane (CH4) will also intensify the greenhouse effect. The burning of fossil fuels will also cause air pollution by heavy metals released during the burning process, which will increase the content of As, Cd, Cr, Ni, Mn, and Pb in the air. PM, SO2, and NO2 are the major pollutants released from the burning of fossil fuels and will have serious effects on the ecological environment. The global distribution of PM, SO2, and NO2 are presented as follows. PM is a serious form of air pollution, which is mainly due to some tiny pieces, or particles, that go up into the air and are carried off and spread by wind. Canadian researchers determined the amount of aerosol monitored by two NASA satellite and the aerosol vertical distribution predicted by a computer model together, and then generated a map that shows the global distribution of average PM2.5 (suspended PM less than 2.5 mm) from 2001 to 2006. As illustrated in Fig. 4, the areas colored by deep blue, light blue to yellow, and dark red, represent a higher and higher concentration of PM2.5. Fig. 4 shows that the world’s highest PM2.5 areas are mainly located in northern Africa, and southwest and eastern Asia. One typical example of PM is soot. Soot is the black dust produced when burning wood or fossil fuels like coal, diesel, and oil. Black smoke coming from the exhaust pipe of a big truck or bus contains a lot of soot due to the combustion of diesel in the engine. Similarly, soot can be seen coming from the chimneys of houses.

0

5

10 15 20 Satellite-derived PM2.5 (µg/m3)

50

80

Fig. 4 Satellite-derived PM2.5 (mg m 3). van Donkelaar A, Martin RV, Brauer M, et al. Global estimates of ambient fine particulate matter concentrations from satellite-based aerosol optical depth: development and application. Environ Health Perspectives 2010;118(6):847–55.

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According to the data from the Intergovernmental Panel on Climate Change (IPCC) [6–8], anthropogenic aerosol discharge can be divided into three levels: RCP2.6 (low emissions scenario), RCP4.5 (emissions scenario), and RCP8.5 (high emissions scenario). Global distributions of annual mean of column concentrations of PM2.5 caused by the burning of fossil fuels from 1980 to 2010 are shown in Fig. 5 [9]. Since the 1980s, many developed countries have adopted a series of measures to control humancaused emissions of PM. From Fig. 5, we can find that after years of effort, the PM concentration in the atmosphere of Europe and North America has obviously been reduced. On the other hand, PM emissions caused by the burning of fossil fuels have been growing rapidly in China, India, and other Asian countries. Figs. 6 and 7 show the global changes of NO2 and SO2 tropospheric columns, 2005–2009 to 2010–2014 [10]. Through the analysis of the spatial distribution of the world’s total NO2 in nearly a decade, it can be found that in eastern China and Xinjiang province, there is a clear rise of NO2 due to the increasing motor vehicle quantity, coal consumption, and other industrial activities. Coal denitration technology was not widely employed, therefore the coal-burning process led to the content of NO2 increasing significantly in the troposphere. From Fig. 7, SO2 tropospheric columns had a remarkable decline in China, which illustrates that desulfurization mitigation actions made significant achievements. Air pollution is associated with many health impacts; for instance, chronic obstructive pulmonary disease (COPD) is linked to enhanced ozone (O3), nitrogen dioxide (NO2), and sulfur dioxide (SO2) in the air [11]. Acute lower respiratory illness (ALRI), (b3) SF_RCP8.5

mg/m

90°N 60°N 30°N EQ 30°S 60°S 90°S

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–20°0′

–40°0′

–60°0′

–80°0′

–100°0′

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–160°0′

Fig. 5 Global distributions of annual mean of column concentrations of PM2.5 caused by the burning of fossil fuels during 1980–2010, in RCP2.6, RCP4.5, RCP8.5. Yang D, Zhang H, Shen X. Simulation of global distribution of temporal and spatial variation of PM2.5 concentration. China Environ Sci 2016;36(4):990–9.

90°0′

–200

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+100

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50°0′

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70°0′

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70°0′

+200

Fig. 6 Global changes of NO2 tropospheric columns, 2005–2009 to 2010–2014. Yan H, Zhang X, Wang W. Spatiotemporal variations of NO2 and SO2 over global region and China by OMI observations during 2004–2014. Sci Technol Rev 2015;33(17):41–51.

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Energy and Air Pollution

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Fig. 7 Global changes of SO2 tropospheric columns, 2005–2009 to 2010–2014. Yan H, Zhang X, Wang W. Spatiotemporal variations of NO2 and SO2 over global region and China by OMI observations during 2004–2014. Sci Technol Rev 2015;33(17):41–51.

ischemic heart disease (IHD), COPD, and lung cancer (LC) are linked to PM2.5 [12]. PM is so small and can be spread by wind, which makes it very easy to breathe in. If people breathe in too much PM, it will result in sickness. The estimate of the global PM2.5 related mortality in 2010 was 3.15 million people with a 95% confidence interval (CI95) of 1.52–4.60 million [13]. The main causes were cerebrovascular disease (CEV) (1.31 million) and IHD (1.08 million), and the secondary causes were COPD (374 thousand), ALRI (230 thousand) and LC (161 thousand). The global estimate of ozone (O3) related mortality by COPD is 142 thousand. In addition, there is an estimate of 3.54 million deaths per year caused by indoor air pollution due to the use of solid fuels for cooking and heating. Fig. 8 shows the geographic distribution of mortality linked to outdoor air pollution in 2010, which demonstrates the hotspots are mainly located in the large urban centers of China and India.

1.23.2

Energy-Related Air Pollution

Air pollution refers to the kind of pollution that can do harm to human health and pollute the atmosphere. It is caused by substances in our surroundings. These substances may be gaseous, solid, or liquid suspensions. The air we breathe in our daily lives consists of many chemicals; the most common one is nitrogen, followed by oxygen and then other gases. Concentration of each gas is not fixed, and there will be a slight change. If the quantity of pollutants is small, the impact on the environment and human body will be relatively mild. However, when the concentrations of these pollutants increase to dangerous levels, we must find ways to remove them from the air. Air pollution can mainly be divided into two parts: chemical pollution and biological pollution while fossil fuel is one of its main sources [14]. There are five common air pollutants discussed in this section: PM, SO2, NOx, heavy metal Hg, and VOCs. The concept, formation, and effects will be discussed here.

1.23.2.1 1.23.2.1.1

Particulate Matter What is particulate matter?

PM stands for particulate matter, a mixture whose equivalent diameter is below 100 mm. Some particles are large enough to be seen with the naked eye while others are so small that they need electron microscopes to be detected. PM is a wide mixture of solid particles and liquid droplets, including dust, soot, dirt, smoke, and so on.

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Longitude Fig. 8 Mortality linked to outdoor air pollution in 2010. Units of mortality: deaths per area of 100 km  100 km (color coded). In the white areas, annual mean PM2.5 and O3 are below the concentration–response thresholds where no excess mortality is expected. Lelieveld J, Evans JS, Fnais M, Giannadaki D, Pozzer A. The contribution of outdoor air pollution sources to premature mortality on a global scale. Nature 2015;525(7569):367–71.

Human hair 50–70 µm (microns) in diameter

PM2.5 Combustion particles, organic compounds, metals, etc.