The oceans cover a little more than 70 percent of the Earth's surface. This makes them the world's largest solar energy collector and energy storage system. On an average day, 60 million square kilometers (23 million square miles) of tropical seas absorb an amount of solar radiation equal in heat content to about 250 billion barrels of oil. If less than one-tenth of one percent of this stored solar energy could be converted into electric power, it would supply more than 20 times the total amount of electricity consumed in the United States on any given day.
Ocean Thermal Energy Conversion, or "OTEC," is an energy technology that converts solar radiation to electric power. OTEC systems use the ocean's natural thermal gradient—the fact that the ocean's layers of water have different temperatures—to drive a power-producing cycle. As long as the temperature between the warm surface water and the cold deep water differs by about 20°C (36°F), an OTEC system can produce a significant amount of power.
The oceans are thus a vast renewable resource, with the potential to help us produce billions of watts of electric power. This potential is estimated to be about 1013 watts of baseload power generation, according to some experts. The cold, deep seawater used in the OTEC process is also rich in nutrients, and it can be used to culture both marine organisms and plant life near the shore or on land.
The economics of energy production today have delayed the financing of a permanent, continuously operating OTEC plant. However, OTEC is very promising as an alternative energy resource for tropical island communities that rely heavily on imported fuel. OTEC plants in these markets could provide islanders with much-needed power, as well as desalinated water and a variety of mariculture products.
Tuesday, December 23, 2008
REVERSE OSMOSIS DESALINATION
Reverse Osmosis Desalination involves removing the salt from water to make it drinkable. There are several ways to do it, and it is not a new idea at all. Sailors have been using solar evaporation to separate salt from sea water for at least several thousand years. Most of the world’s 1,500 or so desalination plants use distillation as the process, and there are also flash evaporation and electrodialysis methods. All these methods are very expensive, so historically desalination has only been used where other alternatives are also very expensive, such as desert cities. However, an exploding world demand for potable water has led to a lot of research and development in this field and a new, cheaper process has been developed that involves heating sea water and forcing it through membranes to remove the salt from the water.
The process is even cheaper if the desalination plant can be located next to an electrical power plant that is already heating sea water to use for cooling the electrical generating units. Even so, it is still more expensive than other alternatives, but it is indeed becoming more competitive and could become a viable alternative to Edwards water. There is also a lot of interest in using local, brackish groundwaters as a source for desalination instead of ocean water. Such waters typically have only one-tenth the salinity of sea water, so desalination can be accomplished more easily and transportation is less of an issue.
In April 2000 the Texas Water Development Board approved a $59,000 grant to the Lavaca-Navadid River Authority to determine if building a $400 million plant on Matagorda Bay at Point Comfort would be economically and environmentally feasible. There is a power plant at this location that could supply the heated sea water for the membrane process.
The study was released two months later and the cost rose to $755 million, but this included the cost of transmission facilities to San Antonio. The study estimated that a 50-50 mix of desalinated water and water treated by other conventional methods could be delivered to San Antonio users for about $2.80 per thousand gallons, compared to a current cost of $1.36 per thousand gallons.
The process is even cheaper if the desalination plant can be located next to an electrical power plant that is already heating sea water to use for cooling the electrical generating units. Even so, it is still more expensive than other alternatives, but it is indeed becoming more competitive and could become a viable alternative to Edwards water. There is also a lot of interest in using local, brackish groundwaters as a source for desalination instead of ocean water. Such waters typically have only one-tenth the salinity of sea water, so desalination can be accomplished more easily and transportation is less of an issue.
In April 2000 the Texas Water Development Board approved a $59,000 grant to the Lavaca-Navadid River Authority to determine if building a $400 million plant on Matagorda Bay at Point Comfort would be economically and environmentally feasible. There is a power plant at this location that could supply the heated sea water for the membrane process.
The study was released two months later and the cost rose to $755 million, but this included the cost of transmission facilities to San Antonio. The study estimated that a 50-50 mix of desalinated water and water treated by other conventional methods could be delivered to San Antonio users for about $2.80 per thousand gallons, compared to a current cost of $1.36 per thousand gallons.
THE ECONOMICS OF NUCLEAR POWER
The economics of nuclear power is a highly contentious area. It is often difficult to establish independently verified estimates of the basic construction costs and the operating cost. In addition, the results are crucially dependent on the accounting and investment appraisal assumptions such as the rate of return on capital that is sought (the discount rate) and the life-time of the plant.
These latter factors are of particular relevance to nuclear power because the main element in the cost for each unit of electricity generated is that associated with building the plant, the capital cost. The shorter the expected life-time and the higher the discount rate, the higher these fixed costs will be. In a monopoly system, the assumed life of the plant can be the expected physical life-time because there will be nothing to stop the owner running the plant until it is worn out. In a competitive system, the plant may have to be retired much earlier if it cannot compete with new plants.
The running costs of nuclear power plants are difficult to establish because most electric utilities regard this data as commercially confidential. However, in the USA, utilities are required to publish fully authenticated running costs. In 1997, the cheapest to run nuclear plants cost about 1c/kWh (0.6p/kWh), while the average was about 2.4c/kWh (1.5p/kWh). Of this, about 0.4-0.6c/kWh was fuel cost while the rest, 0.5-1.8c/kWh, represented the non-fuel cost of operation and maintenance (wages, spare parts etc.)
Government owned utilities have usually been able to invest money at very low rates of return on capital partly because new power stations were seen as a safe investment and partly because, for a variety of reasons, governments have tended to require a lower rate of return on capital than private industry. Thus, in Britain before privatisation, the national utility, the CEGB, could invest at a 5 per cent real (net of inflation) rate of return and recover the costs over 35 years. After privatisation, it is known that private investors are looking for about 12-15 per cent real return and recover the capital over 15-20 years.
These latter factors are of particular relevance to nuclear power because the main element in the cost for each unit of electricity generated is that associated with building the plant, the capital cost. The shorter the expected life-time and the higher the discount rate, the higher these fixed costs will be. In a monopoly system, the assumed life of the plant can be the expected physical life-time because there will be nothing to stop the owner running the plant until it is worn out. In a competitive system, the plant may have to be retired much earlier if it cannot compete with new plants.
The running costs of nuclear power plants are difficult to establish because most electric utilities regard this data as commercially confidential. However, in the USA, utilities are required to publish fully authenticated running costs. In 1997, the cheapest to run nuclear plants cost about 1c/kWh (0.6p/kWh), while the average was about 2.4c/kWh (1.5p/kWh). Of this, about 0.4-0.6c/kWh was fuel cost while the rest, 0.5-1.8c/kWh, represented the non-fuel cost of operation and maintenance (wages, spare parts etc.)
Government owned utilities have usually been able to invest money at very low rates of return on capital partly because new power stations were seen as a safe investment and partly because, for a variety of reasons, governments have tended to require a lower rate of return on capital than private industry. Thus, in Britain before privatisation, the national utility, the CEGB, could invest at a 5 per cent real (net of inflation) rate of return and recover the costs over 35 years. After privatisation, it is known that private investors are looking for about 12-15 per cent real return and recover the capital over 15-20 years.
Development of Nuclear Technologies
The history of nuclear power development has been one of unfulfilled promises and unexpected technical difficulties. The ringing promise from 1955, of `power too cheap to meter' is one that has come back to haunt the nuclear industry.
With most successful new technologies, people confidently expect that successive designs become cheaper and offer better performance. This has not been the experience with nuclear power: costs have consistently gone up in real terms and processes which were expected to prove easy to master continue to throw up technical difficulties. The issues surrounding waste processing and disposal which at first were assumed to be easily dealt with, remain neglected.
Despite this history of unfulfilled expectations, two factors have meant that nuclear power continues to be discussed as a major potential energy source. First, the promise of unlimited power independent of natural resource limitations and second, the attraction to engineers and scientists of meeting the technological challenges that are posed.
However, in the developed world, patience with nuclear technology is running out. Governments are no longer willing to invest more tax-payers' money in a technology which has provided such a poor rate of return. Electric utilities cannot simply pass on development costs to consumers. Equipment supply companies, which have generally made little or no money from nuclear technology, are unwilling to risk more money on developing technologies which might not work well and which might not have a market.
There is still talk about new nuclear technologies, but a critical look at the real resources going into them shows that little money is now being spent.
With most successful new technologies, people confidently expect that successive designs become cheaper and offer better performance. This has not been the experience with nuclear power: costs have consistently gone up in real terms and processes which were expected to prove easy to master continue to throw up technical difficulties. The issues surrounding waste processing and disposal which at first were assumed to be easily dealt with, remain neglected.
Despite this history of unfulfilled expectations, two factors have meant that nuclear power continues to be discussed as a major potential energy source. First, the promise of unlimited power independent of natural resource limitations and second, the attraction to engineers and scientists of meeting the technological challenges that are posed.
However, in the developed world, patience with nuclear technology is running out. Governments are no longer willing to invest more tax-payers' money in a technology which has provided such a poor rate of return. Electric utilities cannot simply pass on development costs to consumers. Equipment supply companies, which have generally made little or no money from nuclear technology, are unwilling to risk more money on developing technologies which might not work well and which might not have a market.
There is still talk about new nuclear technologies, but a critical look at the real resources going into them shows that little money is now being spent.
Various Methods for Recovery of Waste Heat
Low-Temperature Waste Heat Recovery Methods – A large amount of energy in the form of medium- to low-temperature gases or low-temperature liquids (less than about 250 degrees F) is released from process heating equipment, and much of this energy is wasted.
Conversion of Low Temperature Exhaust Waste Heat – making efficient use of the low temperature waste heat generated by prime movers such as micro-turbines, IC engines, fuel cells and other electricity producing technologies. The energy content of the waste heat must be high enough to be able to operate equipment found in cogeneration and trigeneration power and energy systems such as absorption chillers, refrigeration applications, heat amplifiers, dehumidifiers, heat pumps for hot water, turbine inlet air cooling and other similar devices.
Conversion of Low Temperature Waste Heat into Power –The steam-Rankine cycle is the principle method used for producing electric power from high temperature fluid streams. For the conversion of low temperature heat into power, the steam-Rankine cycle may be a possibility, along with other known power cycles, such as the organic-Rankine cycle.
Small to Medium Air-Cooled Commercial Chillers – All existing commercial chillers, whether using waste heat, steam or natural gas, are water-cooled (i.e., they must be connected to cooling towers which evaporate water into the atmosphere to aid in cooling). This requirement generally limits the market to large commercial-sized units (150 tons or larger), because of the maintenance requirements for the cooling towers. Additionally, such units consume water for cooling, limiting their application in arid regions of the U.S. No suitable small-to-medium size (15 tons to 200 tons) air-cooled absorption chillers are commercially available for these U.S. climates. A small number of prototype air-cooled absorption chillers have been developed in Japan, but they use “hardware” technology that is not suited to the hotter temperatures experienced in most locations in the United States. Although developed to work with natural gas firing, these prototype air-cooled absorption chillers would also be suited to use waste heat as the fuel.
Conversion of Low Temperature Exhaust Waste Heat – making efficient use of the low temperature waste heat generated by prime movers such as micro-turbines, IC engines, fuel cells and other electricity producing technologies. The energy content of the waste heat must be high enough to be able to operate equipment found in cogeneration and trigeneration power and energy systems such as absorption chillers, refrigeration applications, heat amplifiers, dehumidifiers, heat pumps for hot water, turbine inlet air cooling and other similar devices.
Conversion of Low Temperature Waste Heat into Power –The steam-Rankine cycle is the principle method used for producing electric power from high temperature fluid streams. For the conversion of low temperature heat into power, the steam-Rankine cycle may be a possibility, along with other known power cycles, such as the organic-Rankine cycle.
Small to Medium Air-Cooled Commercial Chillers – All existing commercial chillers, whether using waste heat, steam or natural gas, are water-cooled (i.e., they must be connected to cooling towers which evaporate water into the atmosphere to aid in cooling). This requirement generally limits the market to large commercial-sized units (150 tons or larger), because of the maintenance requirements for the cooling towers. Additionally, such units consume water for cooling, limiting their application in arid regions of the U.S. No suitable small-to-medium size (15 tons to 200 tons) air-cooled absorption chillers are commercially available for these U.S. climates. A small number of prototype air-cooled absorption chillers have been developed in Japan, but they use “hardware” technology that is not suited to the hotter temperatures experienced in most locations in the United States. Although developed to work with natural gas firing, these prototype air-cooled absorption chillers would also be suited to use waste heat as the fuel.
COGENERATION TECHNOLOGIES
A typical cogeneration system consists of an engine, steam turbine, or combustion turbine that drives an electrical generator. A waste heat exchanger recovers waste heat from the engine and/or exhaust gas to produce hot water or steam. Cogeneration produces a given amount of electric power and process heat with 10% to 30% less fuel than it takes to produce the electricity and process heat separately.
There are two main types of cogeneration techniques: "Topping Cycle" plants, and "Bottoming Cycle" plants.
A topping cycle plant generates electricity or mechanical power first. Facilities that generate electrical power may produce the electricity for their own use, and then sell any excess power to a utility. There are four types of topping cycle cogeneration systems. The first type burns fuel in a gas turbine or diesel engine to produce electrical or mechanical power. The exhaust provides process heat, or goes to a heat recovery boiler to create steam to drive a secondary steam turbine. This is a combined-cycle topping system. The second type of system burns fuel (any type) to produce high-pressure steam that then passes through a steam turbine to produce power. The exhaust provides low-pressure process steam. This is a steam-turbine topping system. A third type burns a fuel such as natural gas, diesel, wood, gasified coal, or landfill gas. The hot water from the engine jacket cooling system flows to a heat recovery boiler, where it is converted to process steam and hot water for space heating. The fourth type is a gas-turbine topping system. A natural gas turbine drives a generator. The exhaust gas goes to a heat recovery boiler that makes process steam and process heat. A topping cycle cogeneration plant always uses some additional fuel, beyond what is needed for manufacturing, so there is an operating cost associated with the power production.
Bottoming cycle plants are much less common than topping cycle plants. These plants exist in heavy industries such as glass or metals manufacturing where very high temperature furnaces are used. A waste heat recovery boiler recaptures waste heat from a manufacturing heating process. This waste heat is then used to produce steam that drives a steam turbine to produce electricity. Since fuel is burned first in the production process, no extra fuel is required to produce electricity.
There are two main types of cogeneration techniques: "Topping Cycle" plants, and "Bottoming Cycle" plants.
A topping cycle plant generates electricity or mechanical power first. Facilities that generate electrical power may produce the electricity for their own use, and then sell any excess power to a utility. There are four types of topping cycle cogeneration systems. The first type burns fuel in a gas turbine or diesel engine to produce electrical or mechanical power. The exhaust provides process heat, or goes to a heat recovery boiler to create steam to drive a secondary steam turbine. This is a combined-cycle topping system. The second type of system burns fuel (any type) to produce high-pressure steam that then passes through a steam turbine to produce power. The exhaust provides low-pressure process steam. This is a steam-turbine topping system. A third type burns a fuel such as natural gas, diesel, wood, gasified coal, or landfill gas. The hot water from the engine jacket cooling system flows to a heat recovery boiler, where it is converted to process steam and hot water for space heating. The fourth type is a gas-turbine topping system. A natural gas turbine drives a generator. The exhaust gas goes to a heat recovery boiler that makes process steam and process heat. A topping cycle cogeneration plant always uses some additional fuel, beyond what is needed for manufacturing, so there is an operating cost associated with the power production.
Bottoming cycle plants are much less common than topping cycle plants. These plants exist in heavy industries such as glass or metals manufacturing where very high temperature furnaces are used. A waste heat recovery boiler recaptures waste heat from a manufacturing heating process. This waste heat is then used to produce steam that drives a steam turbine to produce electricity. Since fuel is burned first in the production process, no extra fuel is required to produce electricity.
CRYSTALLINE SILICON
Monocrystalline Silicon is made from very pure Monocrystalline Silicon. Monocrystalline Silicon has a single and continuous crystal lattice structure with practically zero defects or impurities.
One of the many reasons Monocrystalline Silicon is superior to other types of silicon cells are their high efficiencies - which are typically around 15%.
Because the manufacturing process required to produce Monocrystalline Silicon is more involved and detailed than other types, this results in slightly higher costs for Monocrystalline Silicon than other silicon technologies.
Polycrystalline Silicon - also referred to as "polysilicon" or "Poly-Si" is a material consisting of multiple small silicon crystals and has long been used as the conducting gate material in MOSFET and CMOS processing technologies. For these technologies, Polycrystalline Silicon is deposited using LPCVD reactors at high temperatures and is usually heavily n or p-doped.
The main advantage of Polycrystalline Silicon over other types of silicon is that the mobility can be orders of magnitude larger and the material also shows greater stability under electric field and light-induced stress. This allows far more complex, high-speed electrical circuits that can be created on the glass substrate along with the amorphous silicon devices, which are still needed for their low-leakage characteristics.
When Polycrystalline Silicon and Amorphous Silicon devices are used in the same process, this is called "hybrid processing."
A complete Polycrystalline Silicon active layer process is also used in some cases where a small pixel size is required, such as in projection displays.
One of the many reasons Monocrystalline Silicon is superior to other types of silicon cells are their high efficiencies - which are typically around 15%.
Because the manufacturing process required to produce Monocrystalline Silicon is more involved and detailed than other types, this results in slightly higher costs for Monocrystalline Silicon than other silicon technologies.
Polycrystalline Silicon - also referred to as "polysilicon" or "Poly-Si" is a material consisting of multiple small silicon crystals and has long been used as the conducting gate material in MOSFET and CMOS processing technologies. For these technologies, Polycrystalline Silicon is deposited using LPCVD reactors at high temperatures and is usually heavily n or p-doped.
The main advantage of Polycrystalline Silicon over other types of silicon is that the mobility can be orders of magnitude larger and the material also shows greater stability under electric field and light-induced stress. This allows far more complex, high-speed electrical circuits that can be created on the glass substrate along with the amorphous silicon devices, which are still needed for their low-leakage characteristics.
When Polycrystalline Silicon and Amorphous Silicon devices are used in the same process, this is called "hybrid processing."
A complete Polycrystalline Silicon active layer process is also used in some cases where a small pixel size is required, such as in projection displays.
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