Flue gas desulphurisation (FGD) describes a process that removes sulphur dioxide (SO2) from a flue gas (exhaust gas) stream. Sulphur dioxide is released to the atmosphere when fossil fuels are burnt and it is a leading contributor to acid rain. The FGD process has become critical to many industrial plants due to increasingly stringent environmental legislation. Although the FGD process is present in many industries, this article focuses upon FGD equipment associated with the power generation industry, particularly for coal fired power stations.
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Good to know - &#;Desulphurisation&#; is also spelt &#;desulfurization&#;, the former is British English whilst the latter is American English.
Coal Power Station Exhaust System with Flue Gas Desulphuriser Highlighted
Most fossil fuels (coal, oils etc.) contain some sulphur. When a fossil fuel is burnt, the sulphur it contains is released to atmosphere via the process of combustion. Some coals may contain up to 4% sulphur, which is a significant amount considering that a coal power station may burn in excess of 5,000 tonnes of coal per day.
Sulphur dioxide combines readily with water and consequently combines readily with moisture clouds in the atmosphere. Once a cloud has become sufficiently saturated with moisture, water droplets form and fall to the ground due to gravity; this process is known as precipitation (rain).
Unfortunately, as water absorbs sulphur dioxide it becomes more acidic. Consequently, as clouds of moisture absorb the sulphur dioxide gas in the atmosphere, the pH value of the suspended water molecules (moisture) decreases, and it becomes more acidic. The acidic rain -colloquially referred to as acid rain- then falls to the ground due to gravity.
Forest Damaged by Acid Rain
Acid rain damages crops, infrastructure, vegetation, soil and contributes to ocean acidification. Because sulphur dioxide is a large contributor to the causes of acid rain, environmental laws have been enacted to force SO2 producers to reduce the amount of SO2 they generate. One of the main produces of sulphur dioxide are coal fired power stations, consequently, they are forced to install FGD systems in order to reduce their SO2 emissions and comply with environmental legislation.
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FGD processes are termed either &#;wet&#; or &#;dry&#;. Dry type FGD systems utilise a reagent in powder form (dry form). Wet type FGD systems utilise an alkaline slurry that is formed after mixing a dry reagent with water. Although two main types of FGD designs are possible, more than 75% of power generation FGD systems are wet.
Wet Flue Gas Desulphuriser Schematic
The most economical means of removing SO2 from a flue gas stream is via a chemical reaction with a reagent. A reagent is a substance or compound added to a system to cause a chemical reaction. Suitable reagents should render the SO2 harmless to the environment whilst also producing a by-product that does not damage the environment.
The most common reagents used in FGD systems are lime (calcium oxide) and limestone (CaCO3). Other reagent alternatives exist e.g. ammonia, but limestone is the most widely adopted. The main reason for limestones widespread adoption is that it is plentiful, cheap and easy to access; all these factors depend however upon geographical location.
By-products of the flue gas desulphurisation process are usually calcium sulphite (CaSO3) and/or calcium sulphate (CaSO4). The by-product produced depends upon which reagent and which FGD system design is used. Irrespective of the reagent and design, the by-product is usually calcium based.
The wet &#;throwaway&#; FGD design is the most common FGD design employed by fossil fired power stations today. The next section describes how a typical wet limestone absorber tower works.
Wet Flue Gas Scrubber Tower
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Limestone is delivered to the plant in crushed, or whole form. Crushed limestone may be delivered directly to a storage silo before being mixed with water in a dedicated mixing unit. Un-crushed limestone will need to pass through a size reduction stage prior to being mixed with water or stored. Size reduction may be achieved using on-site crushers or mills e.g. jaw crushers, gyratory crushers, ball mills, cone crushers etc.).
Pulverised limestone is mixed with water to form an alkaline based slurry. An alkaline slurry is any slurry with a pH exceeding 7.0, but for operational purposes the pH desired for the slurry is usually 8.0 (system design dependent).
Flue gas is discharged from the power station watertube boiler(s), passes through a bag house or electrostatic precipitator (ESP) and is then passed to the desulphuriser. The flue gas temperature is approximately 150 &#;C (300 &#;F) or more when it enters the flue gas desulphuriser. Sulphur dioxide gas entrained within the flue gas and is separated via wet scrubbing.
Wet Flue Gas Desulphuriser
Wet scrubbing is achieved by passing the flue gas from the bottom of the scrubber tower to the top. The alkaline slurry travels in the opposing direction (top to bottom); this arrangement is termed &#;counter flow&#; due to the opposing flow directions of the two flowing mediums. Note that the counter flow design is also sometimes referred to as contra-flow. Of all the flow designs (counter, cross and parallel flow), the counter flow design is the most efficient for the transferring heat and mixing of flowing mediums.
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In order to ensure efficient direct contact between the alkaline slurry and flue gas, a series of spray decks fitted with spray nozzles are used. Spray nozzles discharge the alkaline slurry uniformly within the tower, which ensures the flowing mediums have a high contact surface area with each other. The lower spray decks operate at a pH of approx. 4.0 whilst the higher decks operate at a pH of approx. 6.0 or more. Spray nozzles operate at low pressure, approximately 1 bar (14.5 psi).
The alkaline slurry falls from the spray deck to a perforated tray. The perforated tray forces the flue gas to bubble through the slurry as it passes through the tower, this ensures good direct contact between the slurry and flue gas.
After passing through the holes in the perforated tray, the slurry falls to the base of the tower due to gravity and is collected in the effluent holding tank (EHT) (sometimes called a reaction delay tank). Slurry that is entrained with the flue gas, is separated by a demister at the top of the tower and returned to the EHT.
Demister (green indicates gas, blue indicates slurry)
Water in the slurry readily absorbs the sulphur dioxide gas whilst the alkaline nature of the slurry neutralises the gas&#; acidity. The water is termed the absorbent whilst the limestone is termed the reagent. The remaining flue gas is discharged at the top of the tower, but up to 99% of the SO2 may have now been removed (typically 90% to 95% is removed).
Reacting the alkaline slurry with sulphur dioxide produces calcium sulphite (CaSO3), this chemical reaction can be expressed as:
CaCO3 + 1 SO2 &#; CaSO3 + CO2
Further oxidation of calcium sulphite produces calcium sulphate (CaSO4), this chemical reaction can be expressed as:
CaSO3 + 2H2O + ½O2 &#; CaSO4 · 2H2O
Compressed air (pressure of approx. 1 bar / 14.5 psi) is injected into the base of the effluent holding tank where it bubbles upwards through the slurry. Due to the injection of compressed air into the slurry, forced oxidation of the calcium sulphite occurs and calcium sulphate is formed. Some slurry held by the EHT is circulated back to the spray deck, but some of the slurry is discharged from the tower for dewatering. Agitators (propellers connected to three phase motors) prevent calcium solidification within the EHT.
The dewatering process separates FGD by-products from the slurry. The slurry contains approximately 10-15% calcium-based solids when discharged from the tower. Machinery items used in the dewatering process often include vacuum filters, hydro-cyclones and clarifiers (thickeners). Once the crystalline calcium-based substance has been extracted, it can be either sold or disposed of.
FGD by-products are often saleable and can be sold to reduce the plant&#;s overall operating costs. Calcium sulphate is also known as &#;gypsum&#; and is used for many commercial products. The most common usage of gypsum is for plasterboard (wallboard) in the construction industry, but it also used in the agricultural industry as fertiliser. If the by-product can not be sold, it is often mixed with fly ash and sent to a landfill site.
Man Holding Plasterboard
It is necessary to select tower construction materials carefully due to the corrosive and abrasive environment within the tower. Construction materials depend upon the components and design of the tower, but stainless steel, fibreglass and rubber lined carbon steel, are common construction materials.
The liquid to gas (L/G) flow rates through a wet scrubber tower have a large effect upon its operating efficiency. Typically, a high L/G ratio is desired as this ensures as much SO2 is removed from the flue gas as is economically possible, whilst also preventing solidification of the alkaline slurry within the tower. Solidification of the slurry leads to reduce flow paths within the tower, blocked spray nozzles, and it is difficult to remove (very hard and adhesive).
The pH of the alkaline slurry increases when it reacts with sulphur dioxide, it is therefore necessary to continually supply limestone to the EHT so that the pH of the slurry can be held constant. A reduction in the slurry pH will lead to a resultant reduction in FGD efficiency.
https://en.wikipedia.org/wiki/Flue-gas_desulfurization
https://www.mhps.com/products/aqcs/lineup/flue-gas-desulfurization
https://www.lime.org/lime-basics/uses-of-lime/enviromental/flue-gas-desulfurization
Lime plays a key role in many air pollution control applications. Lime is used to remove acidic gases, particularly sulfur dioxide (SO2) and hydrogen chloride (HCl), from flue gases. Lime-based technology is also being evaluated for the removal of mercury. Lime is more reactive than limestone, and requires less capital equipment. SO2 removal efficiencies using lime scrubbers range from 95 to 99 percent at electric generating plants. HCl removal efficiencies using lime range from 95 to 99 percent at municipal waste-to-energy plants. There are two main methods for cleaning flue gases from coal combustion at electric generating stations: dry scrubbing and wet scrubbing. Lime is used in both systems. Dry scrubbing is also used at municipal waste-to-energy plants and other industrial facilities, primarily for HCl control.
In dry scrubbing, lime is injected directly into flue gas to remove SO2 and HCl. There are two major dry processes: &#;dry injection&#; systems inject dry hydrated lime into the flue gas duct and &#;spray dryers&#; inject an atomized lime slurry into a separate vessel. A spray dryer is typically shaped like a silo, with a cylindrical top and a cone bottom. Hot flue gas flows into the top. Lime slurry is sprayed through an atomizer (e.g., nozzles) into the cylinder near the top, where it absorbs SO2 and HCl. The water in the lime slurry is then evaporated by the hot gas. The scrubbed flue gas flows from the bottom of the cylindrical section through a horizontal duct. A portion of the dried, unreacted lime and its reaction products fall to the bottom of the cone and are removed. The flue gas then flows to a particulate control device (e.g., a baghouse) to remove the remainder of the lime and reaction products. Both dry injection and spray dryers yield a dry final product, collected in particulate control devices. At electric generating plants, dry scrubbing is used primarily for low-sulfur fuels. At municipal waste-to-energy plants, dry scrubbing is used for removal of SO2 and HCl. Dry scrubbing is used at other industrial facilities for HCl control. Dry scrubbing methods have improved significantly in recent years, resulting in excellent removal efficiencies.
In wet lime scrubbing, lime is added to water and the resulting slurry is sprayed into a flue gas scrubber. In a typical system, the gas to be cleaned enters the bottom of a cylinder-like tower and flows upward through a shower of lime slurry. The sulfur dioxide is absorbed into the spray and then precipitated as wet calcium sulfite. The sulfite can be converted to gypsum, a salable by-product. Wet scrubbing treats high-sulfur fuels and some low-sulfur fuels where high-efficiency sulfur dioxide removal is required. Wet scrubbing primarily uses magnesium-enhanced lime (containing 3-8% magnesium oxide) because it provides high alkalinity to increase SO2 removal capacity and reduce scaling potential.
More than ninety percent of U.S. flue gas desulfurization (FGD) system capacity uses lime or limestone. This trend will likely continue into the next phase of federally mandated SO2 reduction from coal burning power plants. In , the National Lime Association sponsored a study by Sargent and Lundy to compare the costs of leading lime and limestone-based FGD processes utilized by power generating plants in the United States. The study included developing conceptual designs with capital and O&M cost requirements using up-to-date performance criteria for the processes. The results of the study are summarized in two reports: Wet FGD Technology Evaluation and Dry FGD Technology Evaluation. The reports present the competitive position of wet and dry limestone and lime-based processes relative to reagent cost, auxiliary power cost, coal sulfur content, dispatch, capital cost, and by-product production (gypsum and SO3 aerosol mitigation chemicals). The reports were updated in a report comparing wet limestone and dry lime based systems.
Because lime also reacts readily with other acid gases such as HCl, lime scrubbing is used to control HCl at municipal and industrial facilities. For example, at municipal waste-to-energy plants, dry lime scrubbing is used to control emissions from about 70 percent of the total U.S. capacity (as of ). HCl removal efficiencies using lime range from 95 to 99 percent. At secondary aluminum plants, for example, EPA identifies lime scrubbing as a maximum achievable control technology for HCl. EPA tests demonstrate removal efficiencies greater than 99 percent.
Different methods for controlling mercury emissions are being evaluated in the United States. One control technology being evaluated combines hydrated lime with activated carbon. The reagent, a registered product, consists of 95-97 percent lime and 3-5 percent activated carbon. Other calcium-based sorbents are also being evaluated as cost-effective alternatives for combined SO2 and mercury removal.
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