Sulfur as an element is ubiquitous. In the universe, it ranks 10th inprevalence; on the earth, it comes in fifth. It is found in vitamins, amino acids, the earth&#;s crust, and virtually every plant and animal. There are myriad uses of sulfur in industry and agriculture, including herbicides, pesticides and fertilizers. Needless to say, it is a critical element in nature and in the economy. Nevertheless, when present in certain chemical compounds and mixtures, sulfur does not play well with others. These compounds can be hazardous to health; damaging to the ecology; and corrosive to many materials utilized for industrial purposes. The organisms and matter where these dangerous compounds are found must be subject to the desulfurization process.
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The desulfurization meaning is actually two-fold: it could refer to removing elemental sulfur at the molecular level or, alternatively, extracting sulfur compounds from chemical mixtures. On its own, sulfur can be extricated from subterranean deposits by melting it through the injection of water heated above the boiling point. Once melted, the sulfur is piped out to the surface. Simple enough. What, though, about those dangerous compounds that find themselves in diverse compositions like natural gas, biomass and petroleum, for instance? What does desulfurization look like when the element is bonded to others?
Natural gas formations exist all over the world. The largest deposits are located in the Middle East, the Russian Federation and Europe. In North America, natural gas is most abundant in Texas, Oklahoma, New Mexico, Wyoming, and Louisiana. In the United States, over 50 percent of homes are heated by natural gas and this fuel accounts for 24 percent of energy use overall. Natural gas is also a constituent ingredient of many paints, plastics and even medicines. Propane gas &#; popular with avid grillers and barbecue enthusiasts &#; is also derived from natural gas.
Natural gas is often retrieved from its earthen deposits in the same manner as petroleum &#; through drilling or hydraulic fracturing. Sometimes a &#;horse head&#; pump is employed to draw both natural gas and oil to the surface. This resource is found in shale formations, coal beds and sandstone. Once the gas is drawn from its source, it is transported via 300,000 miles of pipeline to locations throughout the U.S., eventually available to customers. Before this lengthy trip, however, the gas must be treated to remove the hydrogen sulfide (H2S) and carbon dioxide (CO2).
The desulfurization of natural gas is necessary for two very important reasons. The H2S that is present is not only toxic to workers and consumers but it is also detrimental to the very pipeline networks that deliver the fuel. At its worst, it can induce respiratory failure, coma and even death to those exposed. Meanwhile, it can quickly oxidize the metal interiors of natural gas pipelines, thereby damaging their safety and overall efficiency. Therefore, natural gas needs treatment at a desulfurization plant soon after its retrieval from wherever it is deposited.
If hydrogen sulfide presence surpasses 5.7 milligrams per cubic meter of natural gas, the gas passes a threshold from user-grade to &#;sour&#; gas. Under such a circumstance the gas is ordinarily run through a tower or column that contains amine, i.e. a derivative of ammonia. The amine solution absorbs the H2S compound as the gas stream passes through, leaving a purer effluent natural gas in its wake. The amine solution is available for further use over many cycles of H2S removal. This procedure for H2S removal is performed in the vast majority of occasions when hydrogen sulfide absorbtion is necessary.
Essentially, biogas is the methane (and CO2) that gets released from organic matter under anaerobic &#; or oxygen-deprived &#; conditions. This can take place naturally, as at the core of a compost heap or landfill, or it can be induced by human technology, i.e. engineered anaerobic digesters. Absent oxygen, bacterial micro-organisms operate on the organic material, breaking it down so that biogas is released from the solids that had retained it. The material is as diverse as sewage, food waste, compost, wastewater, rotting vegetation and animal manure. Once captured, the biogas powers combustion engines which, subsequently, charge electrical generators. Biogas can provide energy to vehicles, farms, neighborhoods and even public transit systems.
Still, biogas, too, has an H2S problem, the very same problem evident with natural gas. The public health threat and infrastructure impairment are equally real with biogas production. Fortunately, biogas desulfurization is available by means of two distinct methods.
1. Wet de-sulfurization &#; can be further broken down into three versions:
2. Dry de-sulfurization &#; rather than using a solvent or solution, dry de-sulfurization utilizes powder/particle agents to treat the biogas. Doing so minimizes the possibility of corrosion in the biogas tank. In general, this method works better when sulfur content is on the low side.
Once properly purified, biogas is an unsung hero of renewable fuels. Not only is it environmentally friendly and cost-effective, it answers a large part of the seemingly eternal waste management question.
Hydrogen sulfide is not the only problematic sulfur compound in energy production. Sulfur dioxide (AO2) is emitted from exhaust flues at energy plants that burn fossil fuels and facilities that incinerate solid wastes. In nature, SO2 is released when volcanoes erupt. On a smaller scale, it is emitted whenever a match is lighted. Implicated in acid rain, SO2 is a major air pollutant that affects habitat livability and the survival of various plant and animal species.
How does flue gas desulfurization work? As with the categories noted above, there are multiple ways to do this. One such procedure is wet scrubbing. This involves an alkaline absorbent slurry &#; limestone, lime or even seawater &#; that is sprayed directly on the gas stream or pooled to receive the stream. At other times the slurry is converted to powder by means of hot gas. When the flue gas makes contact with the particles, a similar reaction removes the sulfur molecules. This method is known as spray-dry scrubbing. Other means of flow gas desulfurization are employed depending on sulfur content and related factors. Like atmospheric CO2 scrubbers, these treatments isolate the SO2 from the flue gas stream before it is released into the air.
The atmospheric residue desulfurization process helps to keep toxic particulates from doing damage to ecosystems and the air we breathe. The various methods heretofore mentioned take place in an atmospheric residue desulfurization unit where not only sulfur dioxide, but nitrogen oxides and other particulates are captured and isolated.
Many of the agents responsible for neutralizing H2S can separate the sulfur from its compounds. However, research demonstrates that an iron oxide sold sponge &#; i.e. wood shavings infused with iron, or ferric, oxide &#; is effective in hydrogen desulfurization by first absorbing the H2S, and then converting ferric oxide into ferric sulfide. The ferric sulfide subsequently reverts to ferric oxide after releasing elemental sulfur.
Adsorptive Desulfurization is an innovative technique that has transformed the way we address the presence of sulfur in gas streams. At Gazpack, we pride ourselves on leveraging cutting-edge technology such as Adsorptive Desulfurization to remove sulfur from a variety of gases. This process involves adsorbents like zeolites, activated carbons, or metal-oxides that selectively trap sulfur compounds, resulting in a cleaned gas stream. Importantly, Adsorptive Desulfurization provides a more efficient, economical, and environmentally friendly alternative to conventional desulfurization methods, particularly when dealing with gas streams containing low concentrations of sulfur.
Energy sources with less CO2 emission than traditional fossil fuels promise greater energy independence and a cleaner environment. Yet even these gases have contaminants that require removal before they are burned for electrical generation or combusted for vehicular performance. The good news is that technology (desulfurization plant) provides for the removal of sulfur compounds before the energy is consumed.
Before flue gas desulfurization was installed, the emissions from the Four Corners Generating Station in New Mexico contained a significant amount of sulfur dioxide.
Flue-gas desulfurization (FGD) is a set of technologies used to remove sulfur dioxide (SO2) from exhaust flue gases of fossil-fuel power plants, and from the emissions of other sulfur oxide emitting processes such as waste incineration, petroleum refineries, cement and lime kilns.
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Since stringent environmental regulations limiting SO2 emissions have been enacted in many countries, SO2 is being removed from flue gases by a variety of methods. Common methods used:
For a typical coal-fired power station, flue-gas desulfurization (FGD) may remove 90 per cent or more of the SO2 in the flue gases.[2]
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Methods of removing sulfur dioxide from boiler and furnace exhaust gases have been studied for over 150 years. Early ideas for flue gas desulfurization were established in England around .
With the construction of large-scale power plants in England in the s, the problems associated with large volumes of SO2 from a single site began to concern the public. The SO
2 emissions problem did not receive much attention until , when the House of Lords upheld the claim of a landowner against the Barton Electricity Works of the Manchester Corporation for damages to his land resulting from SO2 emissions. Shortly thereafter, a press campaign was launched against the erection of power plants within the confines of London. This outcry led to the imposition of SO
2 controls on all such power plants.[3]
The first major FGD unit at a utility was installed in at Battersea Power Station, owned by London Power Company. In , an FGD system similar to that installed at Battersea went into service at Swansea Power Station. The third major FGD system was installed in at Fulham Power Station. These three early large-scale FGD installations were suspended during World War II, because the characteristic white vapour plumes would have aided location finding by enemy aircraft.[4] The FGD plant at Battersea was recommissioned after the war and, together with FGD plant at the new Bankside B power station opposite the City of London, operated until the stations closed in and respectively.[5] Large-scale FGD units did not reappear at utilities until the s, where most of the installations occurred in the United States and Japan.[3]
The Clean Air Act of (CAA) and it amendments have influenced implementation of FGD.[6] In , the revised PTC 40 Standard was published. This revised standard (PTC 40-) covers Dry and Regenerable FGD systems and provides a more detailed Uncertainty Analysis section. This standard is currently in use today by companies around the world.
As of June , there were 42 FGD units in operation, 36 in Japan and 6 in the United States, ranging in capacity from 5 MW to 250 MW.[7] As of around and , FGD units were being used in 27 countries, and there were 678 FGD units operating at a total power plant capacity of about 229 gigawatts. About 45% of the FGD capacity was in the U.S., 24% in Germany, 11% in Japan, and 20% in various other countries. Approximately 79% of the units, representing about 199 gigawatts of capacity, were using lime or limestone wet scrubbing. About 18% (or 25 gigawatts) utilized spray-dry scrubbers or sorbent injection systems.[8][9][10]
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The International Maritime Organization (IMO) has adopted guidelines on the approval, installation and use of exhaust gas scrubbers (exhaust gas cleaning systems) on board ships to ensure compliance with the sulphur regulation of MARPOL Annex VI. [11] Flag States must approve such systems and port States can (as part of their port state control) ensure that such systems are functioning correctly. If a scrubber system is not functioning properly (and the IMO procedures for such malfunctions are not adhered to), port States can sanction the ship. The United Nations Convention on the Law Of the Sea also bestows port States with a right to regulate (and even ban) the use of open loop scrubber systems within ports and internal waters.[12]
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Fossil fuels such as coal and oil can contain a significant amount of sulfur. When fossil fuels are burned, about 95 percent or more of the sulfur is generally converted to sulfur dioxide (SO2). Such conversion happens under normal conditions of temperature and of oxygen present in the flue gas. However, there are circumstances under which such reaction may not occur.
SO2 can further oxidize into sulfur trioxide (SO3) when excess oxygen is present and gas temperatures are sufficiently high. At about 800 °C, formation of SO3 is favored. Another way that SO3 can be formed is through catalysis by metals in the fuel. Such reaction is particularly true for heavy fuel oil, where a significant amount of vanadium is present. In whatever way SO3 is formed, it does not behave like SO2 in that it forms a liquid aerosol known as sulfuric acid (H2SO4) mist that is very difficult to remove. Generally, about 1% of the sulfur dioxide will be converted to SO3. Sulfuric acid mist is often the cause of the blue haze that often appears as the flue gas plume dissipates. Increasingly, this problem is being addressed by the use of wet electrostatic precipitators.
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Most FGD systems employ two stages: one for fly ash removal and the other for SO2 removal. Attempts have been made to remove both the fly ash and SO2 in one scrubbing vessel. However, these systems experienced severe maintenance problems and low removal efficiency. In wet scrubbing systems, the flue gas normally passes first through a fly ash removal device, either an electrostatic precipitator or a baghouse, and then into the SO2-absorber. However, in dry injection or spray drying operations, the SO2 is first reacted with the lime, and then the flue gas passes through a particulate control device.
Another important design consideration associated with wet FGD systems is that the flue gas exiting the absorber is saturated with water and still contains some SO2. These gases are highly corrosive to any downstream equipment such as fans, ducts, and stacks. Two methods that may minimize corrosion are: (1) reheating the gases to above their dew point, or (2) using materials of construction and designs that allow equipment to withstand the corrosive conditions. Both alternatives are expensive. Engineers determine which method to use on a site-by-site basis.
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Schematic design of the absorber of an FGDSO2 is an acid gas, and, therefore, the typical sorbent slurries or other materials used to remove the SO2 from the flue gases are alkaline. The reaction taking place in wet scrubbing using a CaCO3 (limestone) slurry produces calcium sulfite (CaSO3) and may be expressed in the simplified dry form as:
CaCO3 +SO2 &#; CaSO3 + CO2
Wet scrubbing can be conducted with a Ca(OH)2 (hydrated lime) and Mg(OH)2:
M(OH)2 + SO2 &#;CaSO3 + H2O
(M = Ca, Mg)To partially offset the cost of the FGD installation, some designs, particularly dry sorbent injection systems, further oxidize the CaSO3 (calcium sulfite) to produce marketable CaSO4·2H2O (gypsum) that can be of high enough quality to use in wallboard and other products. The process by which this synthetic gypsum is created is also known as forced oxidation:
CaSO3 + H2O + O2 &#; 2 CaSO4·2H2O
A natural alkaline usable to absorb SO2 is seawater. The SO2 is absorbed in the water, and when oxygen is added reacts to form sulfate ions SO2&#;4 and free H+. The surplus of H+ is offset by the carbonates in seawater pushing the carbonate equilibrium to release CO2 gas:
SO2 + H2O + O &#;H2SO4
HCO
&#;
For more information, please visit Desulfurizer.
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+ H+ &#; H2O + CO2In industry caustic soda (NaOH) is often used to scrub SO2, producing sodium sulfite:[13]
NaOH + SO2 &#; Na2SO3 +H2O
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To promote maximum gas&#;liquid surface area and residence time, a number of wet scrubber designs have been used, including spray towers, venturis, plate towers, and mobile packed beds. Because of scale buildup, plugging, or erosion, which affect FGD dependability and absorber efficiency, the trend is to use simple scrubbers such as spray towers instead of more complicated ones. The configuration of the tower may be vertical or horizontal, and flue gas can flow concurrently, countercurrently, or crosscurrently with respect to the liquid. The chief drawback of spray towers is that they require a higher liquid-to-gas ratio requirement for equivalent SO2 removal than other absorber designs.
FGD scrubbers produce a scaling wastewater that requires treatment to meet U.S. federal discharge regulations.[14] However, technological advancements in ion-exchange membranes and electrodialysis systems has enabled high-efficiency treatment of FGD wastewater to meet EPA discharge limits.[15] The treatment approach is similar for other highly scaling industrial wastewaters.
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A venturi scrubber is a converging/diverging section of duct. The converging section accelerates the gas stream to high velocity. When the liquid stream is injected at the throat, which is the point of maximum velocity, the turbulence caused by the high gas velocity atomizes the liquid into small droplets, which creates the surface area necessary for mass transfer to take place. The higher the pressure drop in the venturi, the smaller the droplets and the higher the surface area. The penalty is in power consumption.
For simultaneous removal of SO2 and fly ash, venturi scrubbers can be used. In fact, many of the industrial sodium-based throwaway systems are venturi scrubbers originally designed to remove particulate matter. These units were slightly modified to inject a sodium-based scrubbing liquor. Although removal of both particles and SO2 in one vessel can be economic, the problems of high pressure drops and finding a scrubbing medium to remove heavy loadings of fly ash must be considered. However, in cases where the particle concentration is low, such as from oil-fired units, it can be more effective to remove particulate and SO2 simultaneously.
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A packed scrubber consists of a tower with packing material inside. This packing material can be in the shape of saddles, rings, or some highly specialized shapes designed to maximize the contact area between the dirty gas and liquid. Packed towers typically operate at much lower pressure drops than venturi scrubbers and are therefore cheaper to operate. They also typically offer higher SO2 removal efficiency. The drawback is that they have a greater tendency to plug up if particles are present in excess in the exhaust air stream.
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A spray tower is the simplest type of scrubber. It consists of a tower with spray nozzles, which generate the droplets for surface contact. Spray towers are typically used when circulating a slurry (see below). The high speed of a venturi would cause erosion problems, while a packed tower would plug up if it tried to circulate a slurry.
Counter-current packed towers are infrequently used because they have a tendency to become plugged by collected particles or to scale when lime or limestone scrubbing slurries are used.
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As explained above, alkaline sorbents are used for scrubbing flue gases to remove SO2. Depending on the application, the two most important are lime and sodium hydroxide (also known as caustic soda). Lime is typically used on large coal- or oil-fired boilers as found in power plants, as it is very much less expensive than caustic soda. The problem is that it results in a slurry being circulated through the scrubber instead of a solution. This makes it harder on the equipment. A spray tower is typically used for this application. The use of lime results in a slurry of calcium sulfite (CaSO3) that must be disposed of. Fortunately, calcium sulfite can be oxidized to produce by-product gypsum (CaSO4·2H2O) which is marketable for use in the building products industry.
Caustic soda is limited to smaller combustion units because it is more expensive than lime, but it has the advantage that it forms a solution rather than a slurry. This makes it easier to operate. It produces a "spent caustic" solution of sodium sulfite/bisulfite (depending on the pH), or sodium sulfate that must be disposed of. This is not a problem in a kraft pulp mill for example, where this can be a source of makeup chemicals to the recovery cycle.
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It is possible to scrub sulfur dioxide by using a cold solution of sodium sulfite; this forms a sodium hydrogen sulfite solution. By heating this solution it is possible to reverse the reaction to form sulfur dioxide and the sodium sulfite solution. Since the sodium sulfite solution is not consumed, it is called a regenerative treatment. The application of this reaction is also known as the Wellman&#;Lord process.
In some ways this can be thought of as being similar to the reversible liquid&#;liquid extraction of an inert gas such as xenon or radon (or some other solute which does not undergo a chemical change during the extraction) from water to another phase. While a chemical change does occur during the extraction of the sulfur dioxide from the gas mixture, it is the case that the extraction equilibrium is shifted by changing the temperature rather than by the use of a chemical reagent.
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A new, emerging flue gas desulfurization technology has been described by the IAEA.[16] It is a radiation technology where an intense beam of electrons is fired into the flue gas at the same time as ammonia is added to the gas. The Chendu power plant in China started up such a flue gas desulfurization unit on a 100 MW scale in . The Pomorzany power plant in Poland also started up a similar sized unit in and that plant removes both sulfur and nitrogen oxides. Both plants are reported to be operating successfully.[17][18] However, the accelerator design principles and manufacturing quality need further improvement for continuous operation in industrial conditions.[19]
No radioactivity is required or created in the process. The electron beam is generated by a device similar to the electron gun in a TV set. This device is called an accelerator. This is an example of a radiation chemistry process[18] where the physical effects of radiation are used to process a substance.
The action of the electron beam is to promote the oxidation of sulfur dioxide to sulfur(VI) compounds. The ammonia reacts with the sulfur compounds thus formed to produce ammonium sulfate, which can be used as a nitrogenous fertilizer. In addition, it can be used to lower the nitrogen oxide content of the flue gas. This method has attained industrial plant scale.[17][20]
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Flue gas desulfurization scrubbers have been applied to combustion units firing coal and oil that range in size from 5 MW to 1,500 MW. Scottish Power are spending £400 million installing FGD at Longannet power station, which has a capacity of over 2,000 MW. Dry scrubbers and spray scrubbers have generally been applied to units smaller than 300 MW.
FGD has been fitted by RWE npower at Aberthaw Power Station in south Wales using the seawater process and works successfully on the 1,580 MW plant.
Approximately 85% of the flue gas desulfurization units installed in the US are wet scrubbers, 12% are spray dry systems, and 3% are dry injection systems.
The highest SO2 removal efficiencies (greater than 90%) are achieved by wet scrubbers and the lowest (less than 80%) by dry scrubbers. However, the newer designs for dry scrubbers are capable of achieving efficiencies in the order of 90%.
In spray drying and dry injection systems, the flue gas must first be cooled to about 10&#;20 °C above adiabatic saturation to avoid wet solids deposition on downstream equipment and plugging of baghouses.
The capital, operating and maintenance costs per short ton of SO2 removed (in US dollars) are:
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An alternative to removing sulfur from the flue gases after burning is to remove the sulfur from the fuel before or during combustion. Hydrodesulfurization of fuel has been used for treating fuel oils before use. Fluidized bed combustion adds lime to the fuel during combustion. The lime reacts with the SO2 to form sulfates which become part of the ash.
This elemental sulfur is then separated and finally recovered at the end of the process for further usage in, for example, agricultural products. Safety is one of the greatest benefits of this method, as the whole process takes place at atmospheric pressure and ambient temperature. This method has been developed by Paqell, a joint venture between Shell Global Solutions and Paques.[22]
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