Large solar collectors on the roof track the sun, collect sunlight, and distribute it through large optical fibers to the bioreactor's growth chamber. The fibers function as distributed light sources to illuminate cyanobacteria (algae).
Each growth chamber consists of a series of illumination sheets containing the optical fibers and moist cloth-like membranes on which the algae grow. By stacking the membranes vertically and better distributing the light, more algae can be produced via photosynthesis in a smaller area.
Photobioreactors use sunlight to sequestor carbon from coal-fired power plans as they produce biomass. The Ohio University reactor will ultimately remove the carbon generated by the production of about 125 MW of electricity in a coal fired plan.
This system is expected to sequester carbon at a cost of $5-8 per ton surpassing the U.S. Department of Energy's goal of $10 per ton. It will also reduce the space required by a factor of 10 or more, when compared to raceway cultivators.
Light delivery and distribution is the principle obstacle to using commercial-scale photobioreactors for algae production. In horizontal cultivator systems, light penetrates the suspension only to 5 cm, leaving most of the algae in darkness. The top layer of algae requires only about 1/10th the intensity of full sunlight to maximize growth, so the remaining sunlight is wasted.
The biomass has a variety of potential uses: hydrogen production, feedstocks, agriculture, pharmaceuticals.
Tuesday, December 23, 2008
UNINTERRUPTIBLE POWER SUPPLIES
Uninterruptible power supplies, or simply "UPS", is sometimes referred to as a battery backup system, which maintains a continuous supply of electric power to a building, or certain electrical devices within a building by supplying power from the UPS system whenever power is not available from the grid or utility company.
Typically, uninterruptible power supplies are located between the source of the normal power supply - such as the electric utility company - and the electric load the UPS system is protecting. When electric power from the grid fails - whether through a lightning strike, failed transformer, or a black-out occurs, the UPS will instantly recognize the loss or interruption of power from the grid, and switch from the grid power to UPS power.
Uninterruptible power supply systems can be designed to protect small or large loads, including systems small enough to protect one or more computers, to critical life support systems that may be found in a home or hospital, to telecommunications equipment where an unexpected power disruption could threaten life or health or serious business disruption or computer data loss.
Small UPS systems can protect loads as small as just one computer to large UPS systems that will power and protect a company's entire data center or a building such as an office building or hospital. These systems can be as large as 3-20 megawatts and typically work in conjunction with a genset or a cogeneration plant.
Typically, uninterruptible power supplies are located between the source of the normal power supply - such as the electric utility company - and the electric load the UPS system is protecting. When electric power from the grid fails - whether through a lightning strike, failed transformer, or a black-out occurs, the UPS will instantly recognize the loss or interruption of power from the grid, and switch from the grid power to UPS power.
Uninterruptible power supply systems can be designed to protect small or large loads, including systems small enough to protect one or more computers, to critical life support systems that may be found in a home or hospital, to telecommunications equipment where an unexpected power disruption could threaten life or health or serious business disruption or computer data loss.
Small UPS systems can protect loads as small as just one computer to large UPS systems that will power and protect a company's entire data center or a building such as an office building or hospital. These systems can be as large as 3-20 megawatts and typically work in conjunction with a genset or a cogeneration plant.
FLUE GAS DESULFURIZATION
Flue gas desulfurization is a chemical process to remove sulfur oxides from the flue gas at coal-burning power plants. Many FGD methods have been developed to varying stages of applicability.
Their goal is to chemically combine the sulfur gases released in coal combustion by reacting them with a sorbent, such as limestone (calcium carbonate, CaCO3), lime (calcium oxide, CaO) or ammonia (NH3). Of the FGD systems in the United States, 90 percent use limestone or lime as the sorbent. As the flue gas comes in contact with the slurry of calcium salts, sulfur dioxide (SO2) reacts with the calcium to form hydrous calcium sulfate (CaSO42H20) or gypsum.
Certain material produced by some power plants in an oxidizing and calcium based process for air emission scrubbing is called FGD (or synthetic) gypsum. FGD gypsum is precipitated gypsum formed through the neutralization of sulfuric acid. While the material may vary in purity, which is defined as the percentage of CaSO4٠2H2O, it is generally over 94% when it is used in wallboard manufacturing. Because this material is very consistent when produced by power plants, wallboard manufacturers will often be located adjacent to the power plant to allow the FGD material to be delivered directly to the wallboard plants. This synergistic relationship not only is economically attractive, but it reduces the need to mine natural gypsum and therefore has a positive environmental impact.
FGD material can be wet or dry. Definitions related to FGD material can be found on this website by clicking on the tab “What are CCPs?” on the Home Page. The PDF file “Glossary of Terms” can be downloaded. As many different terms are used for FGD material, and operational differences between systems may create slightly different types of FGD, this Glossary of Terms is a reliable source of information.
Their goal is to chemically combine the sulfur gases released in coal combustion by reacting them with a sorbent, such as limestone (calcium carbonate, CaCO3), lime (calcium oxide, CaO) or ammonia (NH3). Of the FGD systems in the United States, 90 percent use limestone or lime as the sorbent. As the flue gas comes in contact with the slurry of calcium salts, sulfur dioxide (SO2) reacts with the calcium to form hydrous calcium sulfate (CaSO42H20) or gypsum.
Certain material produced by some power plants in an oxidizing and calcium based process for air emission scrubbing is called FGD (or synthetic) gypsum. FGD gypsum is precipitated gypsum formed through the neutralization of sulfuric acid. While the material may vary in purity, which is defined as the percentage of CaSO4٠2H2O, it is generally over 94% when it is used in wallboard manufacturing. Because this material is very consistent when produced by power plants, wallboard manufacturers will often be located adjacent to the power plant to allow the FGD material to be delivered directly to the wallboard plants. This synergistic relationship not only is economically attractive, but it reduces the need to mine natural gypsum and therefore has a positive environmental impact.
FGD material can be wet or dry. Definitions related to FGD material can be found on this website by clicking on the tab “What are CCPs?” on the Home Page. The PDF file “Glossary of Terms” can be downloaded. As many different terms are used for FGD material, and operational differences between systems may create slightly different types of FGD, this Glossary of Terms is a reliable source of information.
ESTERIFICATION
Esterification is the chemical process of combining an alcohol and an acid which results in the formation of an ester.
• Acid Esterification. Oil feedstocks containing more than 4% free fatty acids go through an acid esterification process to increase the yield of biodiesel. These feedstocks are filtered and preprocessed to remove water and contaminants, and then fed to the acid esterification process. The catalyst, sulfuric acid, is dissolved in methanol and then mixed with the pretreated oil. The mixture is heated and stirred, and the free fatty acids are converted to biodiesel. Once the reaction is complete, it is dewatered and then fed to the transesterification process.
• Transesterification. Oil feedstocks containing less than 4% free fatty acids are filtered and preprocessed to remove water and contaminants and then fed directly to the transesterification process along with any products of the acid esterification process. The catalyst, potassium hydroxide, is dissolved in methanol and then mixed with and the pretreated oil. If an acid esterification process is used, then extra base catalyst must be added to neutralize the acid added in that step. Once the reaction is complete, the major co-products, biodiesel and glycerin, are separated into two layers.
• Methanol recovery. The methanol is typically removed after the biodiesel and glycerin have been separated, to prevent the reaction from reversing itself. The methanol is cleaned and recycled back to the beginning of the process.
• Biodiesel refining. Once separated from the glycerin, the biodiesel goes through a clean-up or purification process to remove excess alcohol, residual catalyst and soaps. This consists of one or more washings with clean water. It is then dried and sent to storage. Sometimes the biodiesel goes through an additional distillation step to produce a colorless, odorless, zero-sulfur biodiesel.
• Glycerin refining. The glycerin by-product contains unreacted catalyst and soaps that are neutralized with an acid. Water and alcohol are removed to produce 50%-80% crude glycerin. The remaining contaminants include unreacted fats and oils. In large biodiesel plants, the glycerin can be further purified, to 99% or higher purity, for sale to the pharmaceutical and cosmetic industries.
• Acid Esterification. Oil feedstocks containing more than 4% free fatty acids go through an acid esterification process to increase the yield of biodiesel. These feedstocks are filtered and preprocessed to remove water and contaminants, and then fed to the acid esterification process. The catalyst, sulfuric acid, is dissolved in methanol and then mixed with the pretreated oil. The mixture is heated and stirred, and the free fatty acids are converted to biodiesel. Once the reaction is complete, it is dewatered and then fed to the transesterification process.
• Transesterification. Oil feedstocks containing less than 4% free fatty acids are filtered and preprocessed to remove water and contaminants and then fed directly to the transesterification process along with any products of the acid esterification process. The catalyst, potassium hydroxide, is dissolved in methanol and then mixed with and the pretreated oil. If an acid esterification process is used, then extra base catalyst must be added to neutralize the acid added in that step. Once the reaction is complete, the major co-products, biodiesel and glycerin, are separated into two layers.
• Methanol recovery. The methanol is typically removed after the biodiesel and glycerin have been separated, to prevent the reaction from reversing itself. The methanol is cleaned and recycled back to the beginning of the process.
• Biodiesel refining. Once separated from the glycerin, the biodiesel goes through a clean-up or purification process to remove excess alcohol, residual catalyst and soaps. This consists of one or more washings with clean water. It is then dried and sent to storage. Sometimes the biodiesel goes through an additional distillation step to produce a colorless, odorless, zero-sulfur biodiesel.
• Glycerin refining. The glycerin by-product contains unreacted catalyst and soaps that are neutralized with an acid. Water and alcohol are removed to produce 50%-80% crude glycerin. The remaining contaminants include unreacted fats and oils. In large biodiesel plants, the glycerin can be further purified, to 99% or higher purity, for sale to the pharmaceutical and cosmetic industries.
BIOMASS GASIFICATION
Biomass fuels such as firewood and agriculture-generated residues and wastes are generally organic. They contain carbon, hydrogen, and oxygen along with some moisture. Under controlled conditions, characterized by low oxygen supply and high temperatures, most biomass materials can be converted into a gaseous fuel known as producer gas, which consists of carbon monoxide, hydrogen, carbon dioxide, methane and nitrogen. This thermo-chemical conversion of solid biomass into gaseous fuel is called biomass gasification.
The producer gas so produced has low a calorific value (1000-1200 Kcal/Nm3), but can be burnt with a high efficiency and a good degree of control without emitting smoke. Each kilogram of air-dry biomass (10% moisture content) yields about 2.5 Nm3 of producer gas. In energy terms, the conversion efficiency of the gasification process is in the range of 60%-70%.
Conversion of solid biomass into combustible gas has all the advantages associated with using gaseous and liquid fuels such as clean combustion, compact burning equipment, high thermal efficiency and a good degree of control. In locations, where biomass is already available at reasonable low prices (e.g. rice mills) or in industries using fuel wood, gasifier systems offer definite economic advantages.
Biomass gasification technology is also environment-friendly, because of the firewood savings and reduction in CO2 emissions.Biomass gasification technology has the potential to replace diesel and other petroleum products in several applications, foreign exchange.
The producer gas so produced has low a calorific value (1000-1200 Kcal/Nm3), but can be burnt with a high efficiency and a good degree of control without emitting smoke. Each kilogram of air-dry biomass (10% moisture content) yields about 2.5 Nm3 of producer gas. In energy terms, the conversion efficiency of the gasification process is in the range of 60%-70%.
Conversion of solid biomass into combustible gas has all the advantages associated with using gaseous and liquid fuels such as clean combustion, compact burning equipment, high thermal efficiency and a good degree of control. In locations, where biomass is already available at reasonable low prices (e.g. rice mills) or in industries using fuel wood, gasifier systems offer definite economic advantages.
Biomass gasification technology is also environment-friendly, because of the firewood savings and reduction in CO2 emissions.Biomass gasification technology has the potential to replace diesel and other petroleum products in several applications, foreign exchange.
PLASMA GASIFICATION
Plasma Gasification is able to get the energy it needs from waste-streams such as municipal solid waste (MSW) and even hazardous and toxic wastes, without the need to bury these wastes in a landfill.
There are two methods used in plasma gasification - the first one is a "plasma arc" and second is called a "plasma torch."
A "plasma arc" plasma gasification plant operates on principles similar to an arc-welding machine, where an electrical arc is struck between two electrodes. The high-energy arc creates a high temperature, highly ionized gas. The plasma arc is enclosed in a chamber. Waste material is fed into the chamber and the intense heat of the plasma breaks down organic molecules (such as oil, solvents, and paint) into their elemental atoms. In a carefully controlled process, these atoms recombine into harmless gases such as carbon dioxide. Solids such as glass and metals are melted to form materials, similar to hardened lava, in which toxic metals are encapsulated. With plasma arc technology there is no burning or incineration and no formation of ash.
"Plasma arc" plasma gasification plant have a very high destruction efficiency. They are very robust; they can treat any waste with minimal or no pretreatment; and they produce a stable waste form. The arc melter uses carbon electrodes to strike an arc in a bath of molten slag. The consumable carbon electrodes are continuously inserted into the chamber, eliminating the need to shut down for electrode replacement or maintenance. The high temperatures produced by the arc convert the organic waste into light organics and primary elements.
Combustible gas is cleaned in the off-gas system and oxidized to CO2 and H2O in ceramic bed oxidizers. The potential for air pollution is low due to the use of electrical heating in the absence of free oxygen. The inorganic portion of the waste is retained in a stable, leach-resistant slag.
In "plasma torch" systems, an arc is struck between a copper electrode and either a bath of molten slag or another electrode of opposite polarity. As with "plasma arc" systems, plasma torch systems have very high destruction efficiency; they are very robust; and they can treat any waste or medium with minimal or no pre-treatment. The inorganic portion of the waste is retained in a stable, leach-resistant slag. The air pollution control system is larger than for the plasma arc system, due to the need to stabilize torch gas.
There are two methods used in plasma gasification - the first one is a "plasma arc" and second is called a "plasma torch."
A "plasma arc" plasma gasification plant operates on principles similar to an arc-welding machine, where an electrical arc is struck between two electrodes. The high-energy arc creates a high temperature, highly ionized gas. The plasma arc is enclosed in a chamber. Waste material is fed into the chamber and the intense heat of the plasma breaks down organic molecules (such as oil, solvents, and paint) into their elemental atoms. In a carefully controlled process, these atoms recombine into harmless gases such as carbon dioxide. Solids such as glass and metals are melted to form materials, similar to hardened lava, in which toxic metals are encapsulated. With plasma arc technology there is no burning or incineration and no formation of ash.
"Plasma arc" plasma gasification plant have a very high destruction efficiency. They are very robust; they can treat any waste with minimal or no pretreatment; and they produce a stable waste form. The arc melter uses carbon electrodes to strike an arc in a bath of molten slag. The consumable carbon electrodes are continuously inserted into the chamber, eliminating the need to shut down for electrode replacement or maintenance. The high temperatures produced by the arc convert the organic waste into light organics and primary elements.
Combustible gas is cleaned in the off-gas system and oxidized to CO2 and H2O in ceramic bed oxidizers. The potential for air pollution is low due to the use of electrical heating in the absence of free oxygen. The inorganic portion of the waste is retained in a stable, leach-resistant slag.
In "plasma torch" systems, an arc is struck between a copper electrode and either a bath of molten slag or another electrode of opposite polarity. As with "plasma arc" systems, plasma torch systems have very high destruction efficiency; they are very robust; and they can treat any waste or medium with minimal or no pre-treatment. The inorganic portion of the waste is retained in a stable, leach-resistant slag. The air pollution control system is larger than for the plasma arc system, due to the need to stabilize torch gas.
ADSORPTION CHILLER
Absorption chillers use heat instead of mechanical energy to provide cooling. A thermal compressor consists of an absorber, a generator, a pump, and a throttling device, and replaces the mechanical vapor compressor.
In the chiller, refrigerant vapor from the evaporator is absorbed by a solution mixture in the absorber. This solution is then pumped to the generator. There the refrigerant re-vaporizes using a waste steam heat source. The refrigerant-depleted solution then returns to the absorber via a throttling device. The two most common refrigerant/ absorbent mixtures used in absorption chillers are water/lithium bromide and ammonia/water.
Compared with mechanical chillers, absorption chillers have a low coefficient of performance (COP = chiller load/heat input). However, absorption chillers can substantially reduce operating costs because they are powered by low-grade waste heat. Vapor compression chillers, by contrast, must be motor- or engine-driven.
Low-pressure, steam-driven absorption chillers are available in capacities ranging from 100 to 1,500 tons. Absorption chillers come in two commercially available designs: single-effect and double-effect. Single-effect machines provide a thermal COP of 0.7 and require about 18 pounds of 15-pound-per-square-inch-gauge (psig) steam per ton-hour of cooling. Double-effect machines are about 40% more efficient, but require a higher grade of thermal input, using about 10 pounds of 100- to 150-psig steam per ton-hour.
A single-effect absorption machine means all condensing heat cools and condenses in the condenser. From there it is released to the cooling water. A double-effect machine adopts a higher heat efficiency of condensation and divides the generator into a high-temperature and a low-temperature generator.
In the chiller, refrigerant vapor from the evaporator is absorbed by a solution mixture in the absorber. This solution is then pumped to the generator. There the refrigerant re-vaporizes using a waste steam heat source. The refrigerant-depleted solution then returns to the absorber via a throttling device. The two most common refrigerant/ absorbent mixtures used in absorption chillers are water/lithium bromide and ammonia/water.
Compared with mechanical chillers, absorption chillers have a low coefficient of performance (COP = chiller load/heat input). However, absorption chillers can substantially reduce operating costs because they are powered by low-grade waste heat. Vapor compression chillers, by contrast, must be motor- or engine-driven.
Low-pressure, steam-driven absorption chillers are available in capacities ranging from 100 to 1,500 tons. Absorption chillers come in two commercially available designs: single-effect and double-effect. Single-effect machines provide a thermal COP of 0.7 and require about 18 pounds of 15-pound-per-square-inch-gauge (psig) steam per ton-hour of cooling. Double-effect machines are about 40% more efficient, but require a higher grade of thermal input, using about 10 pounds of 100- to 150-psig steam per ton-hour.
A single-effect absorption machine means all condensing heat cools and condenses in the condenser. From there it is released to the cooling water. A double-effect machine adopts a higher heat efficiency of condensation and divides the generator into a high-temperature and a low-temperature generator.
POWER PLANTS
Simple Cycle Power Plants (Open Cycle)
The modern power gas turbine is a high-technology package that is comprised of a compressor, combustor, power turbine, and generator, as shown in the figure "Simple-Cycle Gas Turbine".
In a gas turbine, large volumes of air are compressed to high pressure in a multistage compressor for distribution to one or more combustion gases from the combustion chambers power an axial turbine that drives the compressor and the generator before exhausting to atmosphere. In this way, the combustion gases in a gas turbine power the turbine directly, rather than requiring heat transfer to a water/steam cycle to power a steam turbine, as in the steam plant. The latest gas turbine designs use turbine inlet temperatures of 1,500C (2,730F) and compression ratios as high as 30:1 (for aeroderivatives) giving thermal efficiencies of 35 percent or more for a simple-cycle gas turbine.
Combined Cycle Power Plants
The combined-cycle unit combines the Rankine (steam turbine) and Brayton (gas turbine) thermodynamic cycles by using heat recovery boilers to capture the energy in the gas turbine exhaust gases for steam production to supply a steam turbine as shown in the figure "Combined-Cycle Cogeneration Unit". Process steam can be also provided for industrial purposes
Fossil fuel-fired (central) power plants use either steam or combustion turbines to provide the mechanical power to electrical generators. Pressurized high temperature steam or gas expands through various stages of a turbine, transferring energy to the rotating turbine blades. The turbine is mechanically coupled to a generator, which produces electricity.
Steam Turbine Power Plants:
Steam turbine power plants operate on a Rankine cycle. The steam is created by a boiler, where pure water passes through a series of tubes to capture heat from the firebox and then boils under high pressure to become superheated steam. The heat in the firebox is normally provided by burning fossil fuel (e.g. coal, fuel oil or natural gas). However, the heat can also be provided by biomass, solar energy or nuclear fuel. The superheated steam leaving the boiler then enters the steam turbine throttle, where it powers the turbine and connected generator to make electricity. After the steam expands through the turbine, it exits the back end of the turbine, where it is cooled and condensed back to water in the surface condenser. This condensate is then returned to the boiler through high-pressure feedpumps for reuse. Heat from the condensing steam is normally rejected from the condenser to a body of water, such as a river or cooling tower.
The modern power gas turbine is a high-technology package that is comprised of a compressor, combustor, power turbine, and generator, as shown in the figure "Simple-Cycle Gas Turbine".
In a gas turbine, large volumes of air are compressed to high pressure in a multistage compressor for distribution to one or more combustion gases from the combustion chambers power an axial turbine that drives the compressor and the generator before exhausting to atmosphere. In this way, the combustion gases in a gas turbine power the turbine directly, rather than requiring heat transfer to a water/steam cycle to power a steam turbine, as in the steam plant. The latest gas turbine designs use turbine inlet temperatures of 1,500C (2,730F) and compression ratios as high as 30:1 (for aeroderivatives) giving thermal efficiencies of 35 percent or more for a simple-cycle gas turbine.
Combined Cycle Power Plants
The combined-cycle unit combines the Rankine (steam turbine) and Brayton (gas turbine) thermodynamic cycles by using heat recovery boilers to capture the energy in the gas turbine exhaust gases for steam production to supply a steam turbine as shown in the figure "Combined-Cycle Cogeneration Unit". Process steam can be also provided for industrial purposes
Fossil fuel-fired (central) power plants use either steam or combustion turbines to provide the mechanical power to electrical generators. Pressurized high temperature steam or gas expands through various stages of a turbine, transferring energy to the rotating turbine blades. The turbine is mechanically coupled to a generator, which produces electricity.
Steam Turbine Power Plants:
Steam turbine power plants operate on a Rankine cycle. The steam is created by a boiler, where pure water passes through a series of tubes to capture heat from the firebox and then boils under high pressure to become superheated steam. The heat in the firebox is normally provided by burning fossil fuel (e.g. coal, fuel oil or natural gas). However, the heat can also be provided by biomass, solar energy or nuclear fuel. The superheated steam leaving the boiler then enters the steam turbine throttle, where it powers the turbine and connected generator to make electricity. After the steam expands through the turbine, it exits the back end of the turbine, where it is cooled and condensed back to water in the surface condenser. This condensate is then returned to the boiler through high-pressure feedpumps for reuse. Heat from the condensing steam is normally rejected from the condenser to a body of water, such as a river or cooling tower.
OCEAN THERMAL ENERGY CONVERSION
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.
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.
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.
GEO THERMAL ENERGY
The Earth's crust is a bountiful source of energy—and fossil fuels are only part of the story. Heat or thermal energy is by far the more abundant resource. To put it in perspective, the thermal energy in the uppermost six miles of the Earth's crust amounts to 50,000 times the energy of all oil and gas resources in the world!
The word "geothermal" literally means "Earth" plus "heat." The geothermal resource is the world's largest energy resource and has been used by people for centuries. In addition, it is environmentally friendly. It is a renewable resource and can be used in ways that respect rather than upset our planet's delicate environmental balance.
Geothermal power plants operating around the world are proof that the Earth's thermal energy is readily converted to electricity in geologically active areas. Many communities, commercial enterprises, universities, and public facilities in the western United States are heated directly with the water from underground reservoirs. For the homeowner or building owner anywhere in the United States, the emergence of geothermal heat pumps brings the benefits of geothermal energy to everyone's doorstep.
There's a relatively simple concept underlying all the ways geothermal energy is used: The flow of thermal energy is available from beneath the surface of the Earth and especially from subterranean reservoirs of hot water. Over the years, technologies have evolved that allow us to take advantage of this heat.
In fact, electric power plants driven by geothermal energy provide over 44 billion kilowatt hours of electricity worldwide per year, and world capacity is growing at approximately 9% per year. To produce electric power from geothermal resources, underground reservoirs of steam or hot water are tapped by wells and the steam rotates turbines that generate electricity. Typically, water is then returned to the ground to recharge the reservoir and complete the renewable energy cycle.
Underground reservoirs are also tapped for "direct-use" applications. In these instances, hot water is channeled to greenhouses, spas, fish farms, and homes to fill space heating and hot water needs.
The word "geothermal" literally means "Earth" plus "heat." The geothermal resource is the world's largest energy resource and has been used by people for centuries. In addition, it is environmentally friendly. It is a renewable resource and can be used in ways that respect rather than upset our planet's delicate environmental balance.
Geothermal power plants operating around the world are proof that the Earth's thermal energy is readily converted to electricity in geologically active areas. Many communities, commercial enterprises, universities, and public facilities in the western United States are heated directly with the water from underground reservoirs. For the homeowner or building owner anywhere in the United States, the emergence of geothermal heat pumps brings the benefits of geothermal energy to everyone's doorstep.
There's a relatively simple concept underlying all the ways geothermal energy is used: The flow of thermal energy is available from beneath the surface of the Earth and especially from subterranean reservoirs of hot water. Over the years, technologies have evolved that allow us to take advantage of this heat.
In fact, electric power plants driven by geothermal energy provide over 44 billion kilowatt hours of electricity worldwide per year, and world capacity is growing at approximately 9% per year. To produce electric power from geothermal resources, underground reservoirs of steam or hot water are tapped by wells and the steam rotates turbines that generate electricity. Typically, water is then returned to the ground to recharge the reservoir and complete the renewable energy cycle.
Underground reservoirs are also tapped for "direct-use" applications. In these instances, hot water is channeled to greenhouses, spas, fish farms, and homes to fill space heating and hot water needs.
POWER TOWER SYSTEMS
A power tower converts sunshine into clean electricity for the world’s electricity grids. The technology utilizes many large, sun-tracking mirrors (heliostats) to focus sunlight on a receiver at the top of a tower. A heat transfer fluid heated in the receiver is used to generate steam, which, in turn, is used in a conventional turbine-generator to produce electricity. Early power towers (such as the Solar One plant) utilized steam as the heat transfer fluid; current designs (including Solar Two, pictured) utilize molten nitrate salt because of its superior heat transfer and energy storage capabilities. Individual commercial plants will be sized to produce anywhere from 50 to 200 MW of electricity.
A power tower converts sunshine into clean electricity for the world’s electricity grids. The technology utilizes many large, sun-tracking mirrors (heliostats) to focus sunlight on a receiver at the top of a tower. A heat transfer fluid heated in the receiver is used to generate steam, which, in turn, is used in a conventional turbine-generator to produce electricity. Early power towers (such as the Solar One plant) utilized steam as the heat transfer fluid; current designs (including Solar Two, pictured) utilize molten nitrate salt because of its superior heat transfer and energy storage capabilities. Individual commercial plants will be sized to produce anywhere from 50 to 200 MW of electricity
Power towers enjoy the benefits of two successful, large-scale demonstration plants. The 10-MW Solar One plant near Barstow, CA, demonstrated the viability of power towers, producing over 38 million kilowatt-hours of electricity during its operation from 1982 to 1988. The Solar Two plant was a retrofit of Solar One to demonstrate the advantages of molten salt for heat transfer and thermal storage.
Utilizing its highly efficient molten-salt energy storage system, Solar Two successfully demonstrated efficient collection of solar energy and dispatch of electricity, including the ability to routinely produce electricity during cloudy weather and at night. In one demonstration, it delivered power to the grid 24 hours per day for nearly 7 straight days before cloudy weather interrupted operation.
A power tower converts sunshine into clean electricity for the world’s electricity grids. The technology utilizes many large, sun-tracking mirrors (heliostats) to focus sunlight on a receiver at the top of a tower. A heat transfer fluid heated in the receiver is used to generate steam, which, in turn, is used in a conventional turbine-generator to produce electricity. Early power towers (such as the Solar One plant) utilized steam as the heat transfer fluid; current designs (including Solar Two, pictured) utilize molten nitrate salt because of its superior heat transfer and energy storage capabilities. Individual commercial plants will be sized to produce anywhere from 50 to 200 MW of electricity
Power towers enjoy the benefits of two successful, large-scale demonstration plants. The 10-MW Solar One plant near Barstow, CA, demonstrated the viability of power towers, producing over 38 million kilowatt-hours of electricity during its operation from 1982 to 1988. The Solar Two plant was a retrofit of Solar One to demonstrate the advantages of molten salt for heat transfer and thermal storage.
Utilizing its highly efficient molten-salt energy storage system, Solar Two successfully demonstrated efficient collection of solar energy and dispatch of electricity, including the ability to routinely produce electricity during cloudy weather and at night. In one demonstration, it delivered power to the grid 24 hours per day for nearly 7 straight days before cloudy weather interrupted operation.
RECOVERY OF WASTE HEAT FROM COGENERATION AND TRIGENERATION PLANT
In most cogeneration and trigeneration power and energy systems, the exhaust gas from the electric generation equipment is ducted to a heat exchanger to recover the thermal energy in the gas. These heat exchangers are air-to-water heat exchangers, where the exhaust gas flows over some form of tube and fin heat exchange surface and the heat from the exhaust gas is transferred to make hot water or steam. The hot water or steam is then used to provide hot water or steam heating and/or to operate thermally activated equipment, such as an absorption chiller for cooling or a desiccant dehumidifer for dehumidification.
Many of the waste heat recovery technologies used in building co/trigeneration systems require hot water, some at moderate pressures of 15 to 150 psig. In the cases where additional steam or pressurized hot water is needed, it may be necessary to provide supplemental heat to the exhaust gas with a duct burner.
In some applications air-to-air heat exchangers can be used. In other instances, if the emissions from the generation equipment are low enough, such as is with many of the microturbine technologies, the hot exhaust gases can be mixed with make-up air and vented directly into the heating system for building heating.
In the majority of installations, a flapper damper or "diverter" is employed to vary flow across the heat transfer surfaces of the heat exchanger to maintain a specific design temperature of the hot water or steam generation rate.
In some co/trigeneration designs, the exhaust gases can be used to activate a thermal wheel or a desiccant dehumidifier. Thermal wheels use the exhaust gas to heat a wheel with a medium that absorbs the heat and then transfers the heat when the wheel is rotated into the incoming airflow.
A professional engineer should be involved in designing and sizing of the waste heat recovery section. For a proper and economical operation, the design of the heat recovery section involves consideration of many related factors, such as the thermal capacity of the exhaust gases, the exhaust flow rate, the sizing and type of heat exchanger, and the desired parameters over a various range of operating conditions of the co/trigeneration system — all of which need to be considered for proper and economical operation.
Many of the waste heat recovery technologies used in building co/trigeneration systems require hot water, some at moderate pressures of 15 to 150 psig. In the cases where additional steam or pressurized hot water is needed, it may be necessary to provide supplemental heat to the exhaust gas with a duct burner.
In some applications air-to-air heat exchangers can be used. In other instances, if the emissions from the generation equipment are low enough, such as is with many of the microturbine technologies, the hot exhaust gases can be mixed with make-up air and vented directly into the heating system for building heating.
In the majority of installations, a flapper damper or "diverter" is employed to vary flow across the heat transfer surfaces of the heat exchanger to maintain a specific design temperature of the hot water or steam generation rate.
In some co/trigeneration designs, the exhaust gases can be used to activate a thermal wheel or a desiccant dehumidifier. Thermal wheels use the exhaust gas to heat a wheel with a medium that absorbs the heat and then transfers the heat when the wheel is rotated into the incoming airflow.
A professional engineer should be involved in designing and sizing of the waste heat recovery section. For a proper and economical operation, the design of the heat recovery section involves consideration of many related factors, such as the thermal capacity of the exhaust gases, the exhaust flow rate, the sizing and type of heat exchanger, and the desired parameters over a various range of operating conditions of the co/trigeneration system — all of which need to be considered for proper and economical operation.
COMPRESSED AIR ENERGY STORAGE
On nights and weekends, Compressed Air Energy Storage ("CAES") systems compresses air on the surface and then pumps the air underground to a cavern or former mine. There, it is stored as an energy source. During the day and at peak times, air is released and heated using a small amount of natural gas. The heated air flows through a turbine generator to produce electricity.
In conventional gas-turbine power generation, the air that drives the turbine is compressed and heated using natural gas. On the other hand, compressed air energy storage technology needs less gas to produce power during periods of peak demand because it uses air that has already been compressed and stored underground.
Two major compressed air energy storage plants exist worldwide: a CAES plant in Alabama, which is 11-years-old and rated at 110 megawatts, and a German facility that is 23-years-old and 290 MW. A new CAES plant is under development located near Cleveland and will be capable of generating 2,700 MW. Currently, manufacturers can create CAES machinery for facilities ranging from 5 to 350 MW. Palo Alto, Calif.-based EPRI has estimated that more than 85 percent of the U.S. has geological characteristics will accommodate underground compressed air energy storage. Studies have concluded that the technology is competitive with combustion turbines and combined-cycle units, even without attributing some of the uncommon benefits of energy storage.
Compressed air energy storage utilities can use off-peak electricity to compress air and store it in airtight underground caverns. When the air is released from the underground mine or cavern, the air expands through a combustion turbine to create electricity. Nearly two-thirds of the natural gas in a conventional power plant is consumed by a typical natural gas turbine because the gas is used to drive the machine's compressor. By comparison, a compressed-air storage plant uses low-cost heated compressed air to power the turbines and create off-peak electricity, conserving some natural gas.
Compressed air energy storage has a few disadvantages. The disadvantage is that energy is lost when it is “pumped” into the cavern and then re-extracted as compressed air. Some estimates say that it could be as high as 80 percent. That, in effect, means that the selling price must accommodate that shortcoming, which may drive up rates for consumers. Also, building underground storage can be expensive, which might make some prospective projects infeasible. But, with gas prices estimated to be in the $5-6 per million BTU range in the short to medium term, an investment in underground storage could pay for itself over time. Moreover, if the nation develops an energy policy that pushes renewable power sources, the idea may catch on. If that happens and a debate over the technology ensues, developers say that they can win approval from stakeholders. Because storage is used with renewable forms of power, capital costs can be more readily recouped. And furthermore, wind and solar energy, for example, can be stored whenever it is generated and then released on demand—helping to negate the argument that those power sources are intermittent and therefore unreliable.
In conventional gas-turbine power generation, the air that drives the turbine is compressed and heated using natural gas. On the other hand, compressed air energy storage technology needs less gas to produce power during periods of peak demand because it uses air that has already been compressed and stored underground.
Two major compressed air energy storage plants exist worldwide: a CAES plant in Alabama, which is 11-years-old and rated at 110 megawatts, and a German facility that is 23-years-old and 290 MW. A new CAES plant is under development located near Cleveland and will be capable of generating 2,700 MW. Currently, manufacturers can create CAES machinery for facilities ranging from 5 to 350 MW. Palo Alto, Calif.-based EPRI has estimated that more than 85 percent of the U.S. has geological characteristics will accommodate underground compressed air energy storage. Studies have concluded that the technology is competitive with combustion turbines and combined-cycle units, even without attributing some of the uncommon benefits of energy storage.
Compressed air energy storage utilities can use off-peak electricity to compress air and store it in airtight underground caverns. When the air is released from the underground mine or cavern, the air expands through a combustion turbine to create electricity. Nearly two-thirds of the natural gas in a conventional power plant is consumed by a typical natural gas turbine because the gas is used to drive the machine's compressor. By comparison, a compressed-air storage plant uses low-cost heated compressed air to power the turbines and create off-peak electricity, conserving some natural gas.
Compressed air energy storage has a few disadvantages. The disadvantage is that energy is lost when it is “pumped” into the cavern and then re-extracted as compressed air. Some estimates say that it could be as high as 80 percent. That, in effect, means that the selling price must accommodate that shortcoming, which may drive up rates for consumers. Also, building underground storage can be expensive, which might make some prospective projects infeasible. But, with gas prices estimated to be in the $5-6 per million BTU range in the short to medium term, an investment in underground storage could pay for itself over time. Moreover, if the nation develops an energy policy that pushes renewable power sources, the idea may catch on. If that happens and a debate over the technology ensues, developers say that they can win approval from stakeholders. Because storage is used with renewable forms of power, capital costs can be more readily recouped. And furthermore, wind and solar energy, for example, can be stored whenever it is generated and then released on demand—helping to negate the argument that those power sources are intermittent and therefore unreliable.
COMPRESSED NATURAL VEHICLE
According to the Natural Gas Vehicle Coalition (NGVC), as of 2005 there are 130,000 light- and heavy-duty compressed natural gas (CNG) and liquefied natural gas (LNG) vehicles in the United States and 5 million worldwide.
Dedicated natural gas vehicles (NGVs) are designed to run only on natural gas; bi-fuel NGVs have two separate fueling systems that enable the vehicle to use either natural gas or a conventional fuel (gasoline or diesel). In general, dedicated NGVs demonstrate better performance and have lower emissions than bi-fuel vehicles because their engines are optimized to run on natural gas. In addition, the vehicle does not have to carry two types of fuel, thereby increasing cargo capacity and reducing weight.
There are a few light-duty NGVs still available, but if you want a specific type of vehicle, you may want to consider retrofitting a vehicle to an NGV by using an aftermarket conversion system. Heavy-duty NGVs are also available as trucks, buses, and shuttles. Approximately one of every five new transit buses in the United States is powered by natural gas.
As a new twist, tests are being conducted using natural gas vehicles that are fueled with a blend of compressed natural gas and hydrogen.
This model year, auto manufacturers are producing fewer models than in years past. In order to get more vehicle options, you may choose to retrofit your own vehicle.
CNG fueling stations are located in most major cities and in many rural areas. Public LNG stations are limited and used mostly by fleets and heavy-duty trucks. LNG is available through suppliers of cryogenic liquids.
Dedicated natural gas vehicles (NGVs) are designed to run only on natural gas; bi-fuel NGVs have two separate fueling systems that enable the vehicle to use either natural gas or a conventional fuel (gasoline or diesel). In general, dedicated NGVs demonstrate better performance and have lower emissions than bi-fuel vehicles because their engines are optimized to run on natural gas. In addition, the vehicle does not have to carry two types of fuel, thereby increasing cargo capacity and reducing weight.
There are a few light-duty NGVs still available, but if you want a specific type of vehicle, you may want to consider retrofitting a vehicle to an NGV by using an aftermarket conversion system. Heavy-duty NGVs are also available as trucks, buses, and shuttles. Approximately one of every five new transit buses in the United States is powered by natural gas.
As a new twist, tests are being conducted using natural gas vehicles that are fueled with a blend of compressed natural gas and hydrogen.
This model year, auto manufacturers are producing fewer models than in years past. In order to get more vehicle options, you may choose to retrofit your own vehicle.
CNG fueling stations are located in most major cities and in many rural areas. Public LNG stations are limited and used mostly by fleets and heavy-duty trucks. LNG is available through suppliers of cryogenic liquids.
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