Conventional coal-fired power plant

(CC) Photo: Daniel Ullrich
Coal-fired power plant in Voerde, Germany

A conventional coal-fired power plant produces electricity by the burning of coal and air in a steam generator, where it heats water to produce high pressure and high temperature steam. The steam flows through a series of steam turbines which spin an electrical generator to produce electricity. The exhaust steam from the turbines is cooled, condensed back into water, and returned to the steam generator to start the process over.

Conventional coal-fired power plants are highly complex and custom designed on a large scale for continuous operation 24 hours per day and 365 days per year. Such plants provide most of the electrical energy used in many countries.

Most plants built in the 1980s and early 1990s produce about 500 MW (500•10⁶ watt) of power, while many of the modern plants produce about 1000 MW. Also the efficiencies (ratio of electrical energy produced to energy released by the coal burned) of conventional coal-fired plants increased from under 35% to close to 45%.

Coal transport and delivery

Coal is delivered by highway truck, rail, barge or collier ship. Some plants are even built near coal mines and the coal is delivered from the mines by conveyors or by massive trucks.

A large coal train called a "unit train" may be two kilometers (over a mile) long, containing 100 railcars with 90 metric tons in each one, for a total load of 9,000 metric tons. A large plant under full load requires at least one coal delivery this size every day. Plants may get as many as three to five trains a day, especially in "peak season", during the summer months when electrical energy consumption is high. A large coal-fired power plant such as the one in Nanticoke, Canada stores several million metric tons of coal for winter use when delivery via the Great Lakes is not possible.

Modern unloaders use rotary dump devices, which eliminate problems with coal freezing in bottom dump cars. The unloader includes a train positioner arm that pulls the entire train to position each car sequentially over a coal hopper. The dumper clamps an individual car against a platform that swivels the car upside down to dump the coal. Swiveling couplers enable the entire operation to occur while the cars are still coupled together. Unloading a unit train takes about three hours.

Shorter trains may use railcars with an "air-dump", which relies on air pressure from the engine plus a "hot shoe" on each car. This "hot shoe" when it comes into contact with a "hot rail" at the unloading trestle, shoots an electric charge through the air dump apparatus and causes the doors on the bottom of the car to open, dumping the coal through the opening in the trestle. Unloading one of these trains takes anywhere from an hour to an hour and a half. Older unloaders may still use manually operated bottom-dump rail cars and a "shaker" attached to the cars to dump the coal.

A collier (cargo ship carrying coal) may hold 35,000 metric tons of coal and takes several days to unload. Colliers are large, seaworthy, self-powered ships. For transporting coal in calmer waters, such as rivers and lakes, flat-bottomed vessels called barges pulled by towboats are used.

Some power plants receive coal via a coal slurry pipeline between the power plant and a coal mine. For example, the Mohave power plant at Laughlin, Nevada receives coal slurry from a coal mine approximately 112 kilometers (70 miles) away. The coal is ground to approximately the size of coffee grounds and mixed with water to form the slurry. At the power plant the coal is either fed directly to the fuel preparation system or to a pond where the coal settles out and, at a later date, is re-slurried and then pumped to the fuel preparation system.

For startup or auxiliary purposes, a coal-fired power plant may use fuel oil as well. Fuel oil can be delivered to plants by pipeline, tanker, tank car or truck.

Fuel preparation

For most coal-fired power plants, coal is prepared for use by first crushing the delivered coal into pieces less than 5 cm in size. The crushed coal is then transported from the storage yard to in-plant storage silos by rubberized conveyor belts.

In plants that burn pulverized coal, coal from the storage silos is fed into pulverizers that grind the crushed coal into the consistency of face powder and mix it with primary combustion air which transports the pulverized coal to the steam generator furnace. A 500 MW coal-fired power plant will have about six such pulverizers, five of which will supply the steam generator at full load with about 225 metric tons per hour.

In plants that do not burn pulverized coal, the crushed coal may be directly fed into cyclone burners, a specific kind of combustor that can efficiently burn larger pieces of coal.

In plants fueled with slurried coal, the slurry is fed directly to the pulverizers and then mixed with air and fed to the steam generator. The slurry water is separated and removed during pulverizing of the coal.

(PD) Image: Milton Beychok
Diagram of a tray-type boiler feed water deaerator (with vertical, domed aeration section and horizontal water storage section

Feedwater heating and deaeration

The feedwater used in the steam generator consists of recirculated condensate water and makeup water. Because the metallic materials it contacts are subject to corrosion at high temperatures and pressures, the makeup water is highly purified in a system of water softeners and ion exchange demineralizers. The makeup water in a 500 MW plant amounts to about 75 litres per minute to offset the small losses from steam leaks in the system and blowdown from the steam drum (see steam generator diagram below).

The condensate and feedwater system begins with the water condensate being pumped out of the low pressure turbine exhaust steam condenser (commonly referred to as a surface condenser). The condensate water flow rate in a 500 MW coal-fired power plant is about 23,000 litres per minute.

The feedwater plus makeup water flows through feedwater heaters heated with steam extracted from the steam turbines. Typically, the total feedwater also flows through a deaerator that removes dissolved air from the water, further purifying and reducing its corrosivity.

In the deaerator of following the deaeration, the water may be dosed with hydrazine, a chemical that scavenges (removes) the remaining oxygen in the water to below 5 parts per billion (ppb). It is also dosed with pH control agents such as ammonia or morpholine to keep the residual acidity low and thus non-corrosive.

(PD) Image: Milton Beychok
Simplified diagram of a conventional coal-fired steam generator.

The steam generator

A conventional coal-fired steam generator is a rectangular furnace about 15 metres on a side and 40 metres tall. Its walls are made of insulated steel with a web of high pressure steel boiler tubes attached to the inner surface of the walls.

The deaerated boiler feedwater enters the economizer (see the adjacent diagram) where it is preheated by the hot combustion flue gases and then flows into the boiler steam drum at the top of the furnace. Water from that drum circulates through the boiler tubes in the furnace walls using the density difference between water in the steam drum and the steam-water mixture in the boiler tubes.

Pulverized coal is air-blown into the furnace from fuel nozzles at the four corners and it rapidly burns, forming a large fireball at the center. The thermal radiation of the fireball heats the water that circulates through the boiler tubes mounted on the furnace walls. As the water circulates, it absorbs heat and partially changes into steam at about 362 °C and at a pressure of 190 bar (19 MPa). In the boiler steam drum, the steam is separated from the circulating water. The steam then flows through superheat tubes that hang in the hottest part of the combustion flue gases path as it exits the furnace. Here the steam is superheated to about 540 °C before being routed into the high pressure steam turbine.

The steam turbines and the electrical generator

(CC) Photo: Siemens AG, Germany
Rotor of a large modern steam turbine, used in a power plant.

The staged series of steam turbines includes a high pressure turbine, an intermediate pressure turbine and two low pressure turbines. A common configuration is that the series of turbines are connected to each other and on a common shaft, with the electrical generator also being on that common shaft.

As steam moves through the system, it loses pressure and thermal energy and expands in volume, which requires increasing turbine diameter and longer turbine blades at each succeeding stage. The entire rotating mass may weigh over 180 metric tons and be 30 metres long. It is so heavy and the internal clearances are so close that it must be kept turning slowly at 3 rpm (using a turning gear mechanism) when shut down so that the shaft will not thermally bow even slightly and become bound.

Another essential system is the turbine lubricating oil system which supplies oil to all turbine bearings to prevent metal-to-metal contact between the turbine shaft and the shaft bearings. The turbine shaft literally floats on a film of oil at the bearing points. This is so important that it is one of the only major functions to be maintained by the emergency power batteries on site.

Superheated steam from the steam generator flows through a control valve into the high pressure turbine. The control valve regulates the steam flow in accordance with the power output needed from the plant. The exhaust steam from the high pressure turbine (reduced in pressure and in temperature) returns to the steam generator's reheating tubes (see the steam generator diagram above) where it is reheated back to 540 °C before it flows into the intermediate pressure turbine. The exhaust steam from the intermediate pressure turbine flows directly into the two low pressure turbines and the exhaust steam from the low pressure turbines flows into the surface condenser. A small fraction of steam from the turbines is used to heat the deaerator and/or the boiler feedwater preheater(s).

The turbine-driven electrical generator, about 10 metres long and 4 metres in diameter, contains a stationary stator and a spinning rotor. In operation, it generates up to 21,000 amperes at 24,000 volts of three-phase alternating current (about 500 MW). A two-pole rotor would spin at 3000 rpm for a 50 Hz output or 3600 rpm for a 60 Hz output synchronized to the power grid frequency in Hz. If a four-pole rotor is used, it would spin at 1500 rpm for 50 Hz output or 1800 rpm for 60 Hz output.

The rotor spins in a sealed chamber cooled with hydrogen gas, selected because it has the highest known thermal conductivity of any gas and it has a low viscosity which reduces windage losses from friction between the generator rotor and the cooling gas. The system requires special handling during startup, with air in the chamber first displaced by carbon dioxide before filling with hydrogen. This ensures that a highly explosive hydrogen-oxygen environment is not created.

The power grid frequency is 60 Hz across North America and 50 Hz in Europe, Oceania, Asia (Korea and parts of Japan are notable exceptions) and parts of Africa.

The electricity flows to a distribution yard where three-phase transformers step the voltage up to 115, 230, 500 or 765 kV as needed for transmission to its destination.

Steam condensing and cooling towers

(GNU) Image: Milton Beychok
Diagram of a typical water-cooled surface condenser.

(GNU) Photo: Stefan Kühn
Hyperboloid cooling towers (with water vapor plumes).

(PD) Photo: Tennessee Valley Authority
Rectangular, mechanically induced draft cooling towers (with water vapor plumes).

The exhaust steam from the low pressure turbines is condensed into water in a water-cooled surface condenser. The condensed water is commonly referred to as condensate. The surface condenser operates at an absolute pressure of about 35 to 40 mmHg (i.e., a vacuum of about 720 to 725 mmHg) which maximizes the overall power plant efficiency.

The surface condenser is usually a shell and tube heat exchanger. Cooling water circulates through the tubes in the condenser's shell and the low pressure exhaust steam is cooled and condensed by flowing over the tubes as shown in the adjacent diagram. Typically the cooling water causes the steam to condense at a temperature of about 35 °C. A lower condensing temperature results in a higher vacuum (i.e., a lower absolute temperature) at the exhaust of the low pressure turbine and a higher overall plant efficiency. The limiting factor in providing a low condensing temperature is the temperature of the cooling water and that, in turn, is limited by the prevailing average climatic conditions at the power plant's location.

The condensate from the bottom of the surface condenser is pumped back to the deaerator to be reused as feedwater.

The heat absorbed by the circulating cooling water in the condenser tubes must also be removed to maintain a constant cooling water supply temperature. This is done by pumping the warm water from the condenser through either natural draft, forced draft or induced draft cooling towers (as seen in the images to the right) that reduce the temperature of the water by about 11–17 °C and expel the low-temperature waste heat to the atmosphere. The circulation flow rate of the cooling water in a 500 MW unit is about 14.2 m³/s (225,000 US gal/minute) at full load.

Some older power plants use river water or lake water as cooling water. In these installations, the water is filtered to remove debris and aquatic life from the water before it passes through the condenser tubes.

The condenser tubes are are often made of a copper alloy, stainless steel or sometimes titanium to resist corrosion from either side. Nevertheless they may become internally fouled during operation by bacteria or algae in the cooling water or by mineral scaling, all of which inhibit heat transfer and reduce the condenser efficiency. In an enclosed system, the cooling water can be treated with biocidal chemicals to inhibit growth of bacteria and algae and with other chemicals to inhibit scaling. Many plants include an automatic cleaning system that circulates sponge rubber balls through the tubes to scrub them clean without the need to take the system off-line. Hot water flushes may also be used to thermally shock aquatic life buildup on the inner walls of the condenser tubes.

The cooling water used to condense the steam in the condenser returns to its source without having been changed other than having been warmed. If the water returns to a local water body (rather than a circulating cooling tower), it is mixed with cool raw water to lower its temperature and prevent thermal shock to aquatic biota when discharged into that body of water.

Another method sometimes utilized for condensing turbine exhaust steam is the use of an air-cooled condenser. Exhaust steam from the low pressure steam turbines flows through the air-cooled condensing tubes which usually have metal fins on their external surface to increase their heat transfer capacity. Ambient air from a large fan is directed over the fins to cool the tubes and condense the low pressure steam in the tubes. Air-cooled condensers typically operate at a higher temperature than water-cooled surface condensers. While reducing the amount of water used in a power plant, the higher condensing temperature results in a higher exhaust pressure for the low pressure turbines which reduces the overall efficiency of the power plant.

Diagram of the overall conventional coal-fired power plant

Simplified coal-fired power plant

1. Cooling tower	11. High pressure steam turbine	20. Fan
2. Cooling water pump	12. Deaerator	21. Reheater
3. transmission line (3-phase)	13. Feedwater heater	22. Combustion air intake
4. transformer (3-phase)	14. Coal conveyor	23. Economiser
5. Electrical generator (3-phase)	15. Coal hopper	24. Air preheater
6. Low pressure steam turbines	16. Coal pulverizer	25. Cold-side Electrostatic precipitator
7. Condensate and feedwater pumps	17. Steam drum	26. Fan
8. Surface condenser	18. Bottom ash hopper	27. Flue gas desulfurization scrubber
9. Intermediate pressure steam turbine	19. Superheater	28. Flue gas stack
10. Steam control valve

Stack gas path

As the combustion flue gas exits the steam generator, it flows through a heat exchange device where it is cooled by exchanging heat with the incoming combustion air. The device is called an air preheater (referred to as an APH). The gas exiting the steam generator is laden with particulate matter (PM), referred to as fly ash, which consists of very small ash particles. The flue gas contains nitrogen along with combustion products carbon dioxide (CO₂), sulfur dioxide (SO₂) and nitrogen oxides (NO_x).

Various processes (known as De-NOx processes) are often used to reduce the amount of NO_x in the flue gas before the flue gas exits the steam generator. After the exiting flue gas has been cooled by heat exchange with the incoming combustion air, the fly ash in the flue gas is removed by fabric bag filters or electrostatic precipitators. Finally, after removal of the fly ash, many coal-fired power plants use one of the available flue gas desulfurization (FGD) processes to reduce sulfur dioxide emissions. The flue gas then exits to the atmosphere via tall flue gas stacks. A typical flue gas stack may be about 150 to 250 metres tall to disperse the remaining flue gas components in the atmosphere.

In the United States and a number of other countries, air pollution dispersion modeling studies are required to determine the flue gas stack height needed to comply with the local air pollution regulations. The United States also requires the height of a flue gas stack to comply with what is known as the "Good Engineering Practice (GEP)" stack height. In the case of existing flue gas stacks that exceed the GEP stack height, any air pollution dispersion modeling studies (to determine environmental impacts) for such stacks must use the GEP stack height rather than the actual stack height.

Supercritical steam generators

Above the critical point for water of 374 °C and 22 MPa, there is no phase transition from water to steam, but only a gradual decrease in density. Boiling does not occur and it is not possible to remove impurities via steam separation.

Supercritical steam generators operating at or above the critical point of water are referred to as once-through plants because boiler water does not circulate multiple times as in a conventional steam generator. Supercritical steam generators require additional water purification steps to ensure that any impurities picked up during the cycle are removed. This purification takes the form of high pressure ion exchange units called condensate polishers between the steam condenser and the feedwater heaters.

Conventional coal-fired power plants operate at subcritical conditions and typically achieve 34–36% thermal efficiency. Supercritical coal-fired power plants, operating at 565 °C and 243 bar (24.3 MPa) have efficiencies in the range of 38–40%. New "ultra critical" designs, operating at 700–720 °C and 365–385 bar (36.5–38.5 MPa), are expected to achieve 44–46% efficiency.

Alternatives to coal-fired power plants

Alternatives to coal-fired power plants include using other fossil fuels (natural gas or fuel oil), nuclear power plants, geothermal power plants, hydroelectric power plants, solar power plants, wind power plants and tidal power plants.

There are also other types of coal-fired power plants:

• Integrated gasification combined cycle (IGCC): The coal is gasified to produce a synthetic gas (referred to as syngas). Impurities are removed from the syngas which is then burned in a gas turbine. The gas turbine drives an electrical generator and steam is produced by recovering heat from the gas turbine exhaust. The steam is used to drive another electrical generator.

• Fluidized bed combustion (FBC): The coal is burned in a fluidized bed and steam is produced by heating and vaporizing feedwater flowing through tubes in and above the fluidized bed. The steam is used to drive an electrical generator.

• Oxygen firing (Oxy firing): Using oxygen rather than air for combustion of the coal in coal-fired power plants.

Control of air pollutant emissions

The major designated air pollutants emitted by coal-fired power plants are sulfur dioxide (SO₂), nitrogen oxides (NOx), particulate matter (PM), and mercury (Hg). Trace amounts of radioactive elements are also emitted.

A major component of the combustion flue gases produced by burning coal is carbon dioxide (CO₂), which is not a pollutant in the traditional sense since it is essential to support photosynthesis for all plant life on Earth. However, carbon dioxide is a greenhouse gas considered to be a contributor to global warming. It is the most abundant anthropogenic (human caused) greenhouse gas in the Earth's atmosphere.

Control of particulate matter emissions

The removal of particulate matter (referred to as fly ash) from the combustion flue gas is typically accomplished with electrostatic precipitators (ESP) or fabric filters. ESPs or fabric filters are installed on all power plants in the United States that burn pulverized coal. They routinely achieve 99% or greater fly ash removal.

Typical particulate emissions from modern power plants in the United States that burn pulverized coal are less than 15 mg per cubic meter of flue gas (referenced at 0 °C and 101,325 kPa). New units in Japan achieve 5 mg per cubic meter by using wet flue gas desulfurization units that also remove condensible particulates.

Control of sulfur dioxide emissions

Partial flue gas desulfurization (FGD) can achieve about 50-70 % removal of sulfur dioxide by the injection of dry limestone just downstream of the air preheater. The resultant solids are recovered in the ESPs along with the fly ash.

In power plants burning pulverized coal, wet flue gas desulfurization (FGD) that contacts the flue gases with lime slurries (in what are called wet lime scrubbers) can achieve 95% sulfur dioxide removal without additives and 99+% removal with additives. Wet FGD has the greatest share of the FGD usage in the United States and it is commercially proven, well established technology.

The typical older FGD units in power plants burning pulverized coal within the United States achieve average sulfur dioxide emission levels of about 0.340 kg/MWh (0.22 lb/10⁶ Btu), which meets the level to which those units were permitted.

The lowest demonstrated sulfur dioxide emission level (in 2005) for power plants burning pulverized high-sulfur coal within the United States was 1.08 kg/MWh (0.07 lb/10⁶ Btu) and 0.046 kg/MWh (0.03 lb/10⁶ Btu) for plants burning low-sulfur pulverized coal.

In 2006, power plants in the United States that burned fossil fuels (coal, fuel oil or natural gas) generated 327 GW of electric power, of which about 70% was generated in plants burning coal. Only about 30% of that 327 GW of generated power was derived from plants equipped with flue gas desulfurization. The other 70% of the generated power was derived from power plants that met their permitted levels by burning low sulfur coals, fuel oil or natural gas.

In the 10 year period between 1996 and 2006, the sulfur dioxide emissions per year from coal-fired power plants in the United States declined from 12.9×10⁶ metric tons to 9.5×10⁶ metric tons which is a reduction of 26%. That decrease in sulfur dioxide emissions occurred despite the fact that the coal-fired power plant generation of electric power increased by 11%.

In March 2005, the U.S. Environmental Protection Agency promulgated the Clean Air Interstate Rule (CAIR) which sets emission caps for particulate matter, sulfur dioxide and nitrogen oxides that are expected to result in more efficient FGD units being installed and more coal-fired power plants using FGD units or switching to burning oil or natural gas. The CAIR rules are still in litigation as of November 2008.

Control of nitrogen oxides emissions

There are three technologies (known as De-NOx processes) available for reducing the emissions of NOx from combustion sources:

• The lowest cost combustion control technology for reducing NOx emissions is referred to as Lo-NOx and can achieve up to a 50% reduction in NOx emissions compared to uncontrolled combustion.

• The most most effective, but most expensive, NOx emission reduction technology is Selective Catalytic Reduction (SCR). It can achieve 90% NOx reduction and is currently (2008) the technology of choice for achieving very low levels of NOx emissions.

• Selective non-catalytic reduction (SNCR) falls between Low-NOx and SCR in both cost and effectiveness.

The average NOx emissions from conventional coal-fired power plants in the United States typically range from about 0.14 kg/MWh (0.09 lb/10⁶ Btu) to 0.20 kg/MWh (0.13 lb/10⁶ Btu), which meets their permitted level of emissions.

In 2005, the 20 lowest NOx emitting coal-fired power plants in the United States in 2005 achieved emission levels ranging from 0.06 kg/MWh (0.04 lb/10⁶ Btu) to 0.10 kg/MWh (0.065 lb/10⁶ Btu).

In the 10 year period between 1996 and 2006, the NOx emissions per year from coal-fired power plants in the United States declined about 40% despite the fact that the coal-fired power plant generation of electric power increased by 11%.

Control of mercury emissions

Mercury in the flue gas exists as both elemental and oxidized mercury vapor as well as mercury that has reacted with the fly ash.

The removal of the fly ash in an ESP or a fabric filter also removes the mercury that has reacted with the fly ash, resulting in 10 to 30% removal for bituminous coals but less than 10% for sub-bituminous coals and lignite. The oxidized mercury vapor left in the flue gas after the fly ash removal is effectively removed by wet FGD scrubbing, resulting in 40-60% total mercury removal for bituminous coals and less than 30–40% total mercury removal for sub-bituminous coals and lignite.

For low-sulfur sub-bituminous coals and particularly lignite, most of the mercury vapor is in the elemental form, which is not removed by wet FGD scrubbing. In most tests of bituminous coals, SCR (for NOx control) converted 85-95% of the elemental mercury to the oxidized form, which is then effectively removed by wet FGD scrubbing. With sub-bituminous coals, the amount of mercury remained low even with addition of an SCR.

Additional mercury removal can be achieved by powdered activated carbon injection (PAC) and an added fiber filter to collect the carbon. This can achieve up to 85-95% removal of the mercury. Commercial short-duration tests with powdered, activated carbon injection have shown removal rates around 90% for bituminous coals but lower for sub-bituminous coals. For sub-bituminous coals, the injection of brominated, activated carbon has been shown to be highly effective in emissions tests lasting 10 to 30 days at 3 power plants. These tests demonstrated a potential mercury removal efficiency of 90%.

Ongoing research and development programs are evaluating improved technology that is expected to improve effectiveness. The general consensus in the industry is that this picture will change significantly within the next few years. The U.S. EPA states that they believe PAC injection and enhanced multi-pollutant controls will be available after 2010 for commercial application on most, if not all, key combinations of coal type and control technology to provide mercury removal levels between 60 and 90%. Optimization of this commercial multi-pollutant control technology by about 2015 should permit achieving mercury removal levels between 90 and 95% on most if not all coals, but the technology remains to be commercially demonstrated.

In March 2005, the U.S. EPA issued the Clean Air Mercury Rule (CAMR). The CAMR allocates a mercury emissions budget for each of the 50 states and other jurisdictions. If they so desire, the states can opt out of the EPA budget and implement a more stringent emissions reduction program than is required by CAMR. As in the CAIR situation (see above section on control of sulfur dioxide emissions), the CAMR is still in litigation as of 2008.

Carbon dioxide emissions

The emissions from conventional coal-fired power plants include carbon dioxide (CO₂) which is the major component of the combustion flue gases produced by burning coal. As discussed earlier above, carbon dioxide is not a pollutant in the traditional sense but it is considered to be a contributor to global warming.

Worldwide Energy Statistics for 2005 Energy Supply Sources TW (a) MWh (b) % Coal-based 4.0 35×109 26.9 Gas, oil, nuclear and other 10.8 95×109 73.1 Total supply sources 14.8 130×109 100.0 Electricity generation component of the total energy supply sources       Coal-fired generation 0.80 7×109 5.4 Total generation 2.05 18×109 13.9 (a) 1 TW = 1 terawatt = 1012 watts (b) 1 MWh = 1 megawatt-hour = 106 watt-hours

To better understand the discussion of carbon dioxide emissions from conventional coal-fired electricity generation plants, the adjacent table provides a perspective on the total global energy supply sources.
In 2005, coal-based energy sources constituted 26.9% of the total energy supply sources.

As shown in the table, the total electricity generation (from natural gas, fuel oil, coal, nuclear power, biomass, hydropower, wind power, solar power, geothermal and other plants) amounted to 13.9% of the total energy supply sources and the coal-fired power plant portion of the electricity generation amounted to 5.4% of the total global energy supply sources.

In 2005, the total carbon dioxide emissions from all sources to the atmosphere were about 28 Gt (28×10⁹ tonnes) and approximately 41 percent (11.5 Gt) of those emissions were from coal-based energy supply sources.

Carbon dioxide emissions from conventional coal-fired power plants

Carbon dioxide emissions for conventional coal-fired power plants will vary significantly because the those emissions are a function of the coal's carbon content and the plant's thermal efficiency. The coal's carbon content may range from about 50 weight percent for lignite coal to 90 weight percent for anthracite coal and the plant's thermal efficiency may vary from 32 to 42 percent.

A study of the future of coal, developed at the Massachusetts Institute of Technology (MIT) states that, as an average, a 500 MW coal coal-fired power plant produces 3 million tons of carbon dioxide per year. That amounts to a carbon dioxide emission factor of 0.62 kg/kWh. Other sources in the literature range up to 1.0 kg/kWh and, in fact, an emission factor of 0.96 can be derived from 1998 data available for all the coal-fired power plants in the United States.

Assuming an emission factor of 1.0 kg/kWh, a 500 MW coal-fired power plant would produce 4.4 million tonnes (4.4 Mt) per year of carbon dioxide emissions and the global total of 0.80 TW (800,000 MW) of conventional coal-fired electricity generation would produce 7 Gt per year of carbon-dioxide emissions. Thus, globally, the estimated amount of carbon dioxide emitted by conventional coal-fired power power plants amounted to approximately 25 % of the estimated 28 Gt of carbon dioxide emitted from all sources in 2005.

Reducing carbon dioxide emissions from coal-fired power plants

The leading technology for significantly reducing the CO₂ emissions from coal-fired power plants is known as Carbon capture and sequestration (CCS). It is currently (2008) regarded as the technology which could significantly reduce coal-fired power plant carbon dioxide emissions while also allowing the use of the Earth's abundant coal resources to provide the increasing global need for energy. However, CCS technology is still in development and it is not expected to be ready for widespread commercial implementation until about 2020.

It involves capturing the carbon dioxide produced by the combustion of coal and storing it in deep ocean areas or in underground geological structures deep within the Earth's upper crust.

The capture of the carbon dioxide from the coal combustion flue gases can be accomplished by using absorbents such as amines (see Amine gas treating). The carbon dioxide is then recovered from the absorbent and compressed into a supercritical fluid at about 150 atmospheres (15 MPA), dehydrated and transported to the storage sites for injection into the underground or undersea reservoirs. Compressing the carbon dioxide into a supercritical fluid greatly increases its density which greatly reduces its volume as compared to transporting and storing the carbon dioxide as a gas.

Since the current global emissions of carbon dioxide from all energy supply sources is 28 Gt per year, the scale of carbon dioxide storage required to make a major difference in those emissions is massive. For example, based on a carbon dioxide emission factor of 1 kg per kWh, 570 coal-fired plants, each producing 1000 MW of electricity, would emit about 5 Gt per year of carbon dioxide into the atmosphere. Storing 5 Gt per year of carbon dioxide requires injection of about 65 million barrels per day (about 10 x 10⁶ cubic meters per day) of supercritical carbon dioxide.

The worldwide capacity for storing carbon dioxide in depleted natural gas and crude oil production fields and in unminable deep coal seams has been estimated as about 1000 Gt which is equivalent to 140 years of the 7 Gt emissions (in 2005) from the worldwide total coal-fired power generation. In addition, the worldwide capacity in deep ocean formations has been estimated as 1000 to 10,000 Gt. There are currently four commercial sequestration sites in operation:

• The Weyburn-Midale facility in Saskatchewan, Canada constructed by a consortium of oil companies, research organizations and others
• The Sleipner facility in offshore Norway constructed by StatoilHydro
• The Snøvit facility in the Barents Sea constructed by StatoilHydro
• The Salah facility in Algeria constructed by StatoilHydro

There are many other sequestration sites currently in planning, development or construction.

No matter what governmental regulations are eventually adopted to mitigate the carbon dioxide emissions from coal-powered power plants (or other processes involving the combustion of substances containing carbon), there must be a successful, integrated large-scale demonstration of the technical, environmental and economic aspects of the major components of a CCS system, namely carbon dioxide capture, transportation and storage. Such an integrated demonstration must also provide a definition of regulatory protocols for sequestration projects including site selection, injection operation, and eventual transfer of custody to public authorities after a period of successful operation.

Control of radioactive trace element emissions

As most ores in the Earth's crust, coal also contains trace levels of uranium, thorium, and other naturally-occurring radioactive elements.

A report developed at the Oak Ridge National Laboratory (ORNL) estimated that the amount of coal burned each year in a typical 1000 MW coal-fired power plant contained about 5.2 tonnes of uranium and about 12.8 tonnes of thorium. The basis of ORNL estimate was that the annual coal consumption was 4 Mt and that the coal contained 1.3 ppm of uranium and 3.2 ppm of thorium.

Assuming that all of the uranium and thorium would be emitted into the fly ash and that the electrostatic precipitators would capture and remove 99% of the fly ash, the emissions of radioactive trace elements to the atmosphere from a 1000 MW coal-fired power plant would be 52 kg/yr of uranium and 128 kg/yr of thorium.

The average annual radiation dose received by a person from all sources (cosmic radiation, radioactivity in the soil, food, water, air and miscellaneous other sources) is 360 millirem. The annual radiation dose (from naturally occurring radioactivity in coal) received by persons living within 80 km of a coal-fired power plant is estimated to be 0.03 millirem.

The ORNL report discussed earlier,states that All studies of potential health hazards associated with the release of radioactive elements from coal combustion conclude that the perturbation of natural background dose levels is almost negligible and a U.S. EPA report states that the lifetime fatal cancer risk from exposure to radionuclides to the vast majority of persons living within 50 km of an electric power plant is estimated to be less than 1×10^-6.