31/5/00 3:59 pm
Page 14
TECHNOLOGY STATUS REPORT
FLUE GAS DESULPHURISATION (FGD) TECHNOLOGIES
MARCH 2000 Department of Trade and Industry
CLEANER COAL TECHNOLOGY PROGRAMME
1751 TSR 012
T ECHNOLOGY S TATUS R EPORT 012
1751 TSR 012
31/5/00 3:59 pm
Page 15
Further information on the Cleaner Coal Technology Programme, and copies of publications, can be obtained from:
Roshan Kamall, Location 1124, Department of Trade and Industry, 1 Victoria Street, London SW1H 0ET Tel: +44 (0) 207 215 6261 Fax: +44 (0) 207 215 2674 E-mail:
[email protected] Web: www.dti.gov.uk/ent/coal
1751 TSR 012
31/5/00 3:59 pm
Page 1
FLUE GAS DESULPHURISATION (FGD) TECHNOLOGIES
Figure 1. Ratcliffe-on-Soar FGD (Courtesy of PowerGen UK plc)
SUMMARY Flue gas desulphurisation (FGD) technologies are widely used to control the emissions of sulphur dioxide (SO2) and sulphur trioxide (SO3) from large stationary sources such as coal- and oil-fired power stations and refineries. They are to be distinguished from the flue gas treatment (FGT) processes used for removing pollutants from waste incinerators. A variety of FGD processes are available; most use an alkali sorbent to recover the acidic sulphur compounds from the flue gas. The most widely used processes are the limestone gypsum process, which produces a saleable gypsum by-product, variants of the limestone process that produce a disposable sludge, and the spray dry process, which produces a mixed solid waste. Capital costs of FGD processes have been steadily falling and current costs are in the range US$100-125 kW-1 (£65-80 kW-1), with further falls in cost predicted for 2000 and beyond. The total market for FGD plant is likely to exceed £1Bn pa over the next decade, with North America and China being the largest markets. Current research and development (R&D) needs are to further reduce costs, increase desulphurisation efficiencies and improve the reliability of plant components.
BENEFITS OF THE TECHNOLOGY FGD is widely applicable as a means of controlling SO2 emissions from large, stationary sources such as power stations, refineries and metallurgical plant (eg Figure 1). The widespread adoption of FGD, together with measures to reduce SO2 emissions from other sources (eg replacement of coal by electricity or gas for domestic heating; low sulphur motor fuels) will significantly reduce anthropogenic sulphur emissions worldwide and thus help to improve air quality to the benefit of both human health and the environment.
DEPARTMENT OF TRADE AND INDUSTRY SUPPORT Since 1990, the Department of Trade and Industry (DTI) has supported 8 projects associated with FGD, contributing £320k to total project costs of £1887k.
INTRODUCTION Sulphur is one of the most common elements in the earth’s crust, and occurs widely as an impurity in coal, crude oil and many ores. It is therefore produced on a large scale during such industrial processes as the combustion of coal, oil and oil-derived fuels, oil refining and the production of metals from their ores. Currently, global SO2 emissions arising from human activity amount to ~140 million tonnes (Mt) per year, of which ~2Mt (1.4%) is produced by the UK. The UK’s SO2 emissions have, however, fallen significantly over the past 30 years (Figure 2). SO2 is one of the principal gaseous pollutants emitted by human activity. It can be a hazard to human health and damages both the natural and built environments. High levels of SO2 can cause respiratory illness and its presence in the environment causes acid rain that damages both vegetation and buildings. Control and reduction of SO2 emissions has therefore been recognised as important for safeguarding human health and protecting the environment since the mid-19th century; many countries now set limits on the amount and concentration of sulphur compounds emitted from the stacks of industrial plant. Emissions of SO2 can be controlled in several ways. It may be possible to switch to a fuel or ore that has a lower sulphur content, or improve the efficiency of the industrial process so that less fuel is required. The sulphur in the fuel or ore can in principle be removed before use; however, in practice, it is uneconomic to remove more than a small percentage of the sulphur. The sulphur can also be removed during use. However, in many applications, the most efficient means of controlling
1751 TSR 012
31/5/00 3:59 pm
Page 2
SO2 Emitted (kt)
SO2 emissions is to remove the SO2 from the flue gases before they are released to the atmosphere. Several differing FGD technologies have been developed to this end.
Technical considerations include the degree of desulphurisation that the process can offer, the flexibility of the process, the amount of space that the FGD plant requires and the technical risks. Economic issues include the capital and operating costs, including consideration of the cost of the plant itself (which may be appreciably more if the plant is to be retrofitted to an existing boiler), the costs of the sorbent used, any revenues or expenses arising from disposal of the by-products and maintenance costs. Commercial considerations include the degree of commercial risk, the maturity of the technology, the number and size of units already in operation (and how they have performed) and suppliers’ guarantees. Some of the major FGD processes are described below. These are:
1970
1980
1985
1988
1989
1990
1991
1992
1993
1994
1995
1996
Year
Large combustion plant
Total
Figure 2. Trends in UK SO 2 emissions
FUNDAMENTALS OF FGD Chemical Principles Almost all commercial FGD processes are based on the fact that SO2 is acidic in nature, and remove the SO2 from flue gases by reaction with a suitable alkaline substance. The most commonly used alkaline materials are limestone (calcium carbonate), quicklime (calcium oxide, CaO) and hydrated lime (calcium hydroxide). Limestone is an abundant and therefore relatively cheap material and both quicklime and hydrated lime are produced from limestone by heating. Other alkalis sometimes used include sodium carbonate, magnesium carbonate and ammonia. The alkali used reacts with SO2 in the flue gas to produce a mixture of sulphite and sulphate salts (of calcium, sodium, magnesium or ammonium, depending on the alkali used). The proportions of sulphite and sulphate are determined by the process conditions; in some processes, all the sulphite is converted to sulphate.
• Wet Processes: - limestone gypsum - sea-water washing - ammonia scrubbing - Wellman-Lord. • Semi-dry Processes: - circulating fluidised bed - spray dry - duct spray dry. • Dry Processes - furnace sorbent injection - sodium bicarbonate injection.
FGD PROCESSES Limestone Gypsum In the limestone gypsum wet scrubbing process, the flue gas is treated with limestone slurry, in order to remove the SO2 and neutralise it. The final product is calcium sulphate dihydrate (gypsum).
The reaction between the SO2 and the alkali can take place either in bulk solution (‘wet’ FGD processes) or at the wetted surface of the solid alkali (‘dry’ and ‘semi-dry’ FGD processes). In wet FGD systems, the alkali (usually as a solution or, more commonly, a slurry) and flue gas are contacted in a spray tower. The SO2 in the flue gas dissolves in the water to form a dilute solution of acid that then reacts with and is neutralised by the dissolved alkali. The sulphite and sulphate salts produced precipitate out of solution, depending on the relative solubility of the different salts present. Calcium sulphate, for example, is relatively insoluble and readily precipitates out. Sodium and ammonium sulphates are very much more soluble. In dry and semi-dry systems, the solid alkali ‘sorbent’ is brought into contact with the flue gas, either by injecting or spraying the alkali into the gas stream or by passing the flue gas through a bed of alkali. In either case, the SO2 reacts directly with the solid to form the corresponding sulphite and sulphate. For this to be effective, the solid has to be quite porous and/or finely divided. In semi-dry systems, water is added to the flue gas to form a liquid film on the particles in which the SO2 dissolves, promoting the reaction with the solid.
Selection of FGD Processes There are a wide range of FGD processes on offer, differing significantly in terms of sorbent used, by-products produced, removal efficiency and capital cost. Selection of the most appropriate FGD process for a particular application will normally be made on economic grounds, ie the process with the lowest overall through-life cost. However, there are many different factors that affect the overall cost. These include: • Technical considerations. • Economic issues - operating costs - capital costs. • Commercial considerations.
Figure 3. Ratcliffe-on-Soar FGD (under construction) (Courtesy of PowerGen UK plc)
This is the most common FGD process now being installed worldwide, and has evolved over almost 30 years. Nowadays, a plant would normally be designed to achieve a high-quality gypsum product, which is suitable for wallboard manufacture. Earlier limestone-based FGD processes produced sulphite sludge or gypsum for dumping, but these types of design are not often adopted now. Both of the large UK power plant with FGD, Ratcliffe (Figure 3) and Drax, use the limestone gypsum process. There are a number of process variants and equipment arrangements which can be adopted; eg the absorber type and reheat methods can vary with the supplier and with the client’s requirements. The design chosen here for illustrative purposes (Figure 4) is one of the most common limestone gypsum (wallboard) plant types, and consists of an open spray tower with a rotary regenerative reheater. The limestone gypsum plant is located downstream of the electrostatic precipitator (ESP) or bag filter, so that most of the fly ash from combustion is removed before the gas reaches the FGD plant. For coal-fired plant, fly ash removal would be ~99.5%.
1751 TSR 012
31/5/00 3:59 pm
Page 3
Flue gas from the ESP passes through an induced draught (ID) and/or booster fan and enters the gas/gas reheater. Here the gas is cooled as heat is extracted. The warm gas from the reheater enters the absorber and mixes with the process liquor. Some of the water is evaporated, and the gas is further cooled. The gas is scrubbed with the recirculating limestone slurry to remove the required amount of SO2. FGD plant manufacturers generally claim that over 95% of the SO2 can be removed within the absorber. This process also removes almost 100% of any hydrogen chloride (HCl) in the flue gas. At the top of the absorber, the gas passes through de-misters to remove suspended water droplets. After leaving the absorber, the gas is passed through the reheater again, to raise its temperature before being exhausted to the stack. Absorber outlet temperatures are typically 50-70ºC, depending mainly on the type of fuel burnt. The minimum gas temperature at the stack is often specified in national emission standards. In the UK this is 80ºC, but in mainland Europe it is slightly lower. Most plant have a by-pass duct, fitted with a (normally closed) damper. This would be opened in an emergency or during start-up, to allow flue gas to be diverted past the FGD plant, directly to the stack. Limestone/gypsum slurry is pumped from the absorber sump to the spray headers at the top of the scrubber. As the slurry falls down the tower it contacts the rising flue gas. The SO 2 is dissolved in the water, neutralised and thus removed from the flue gas. Calcium carbonate from the limestone reacts with the SO2 and oxygen (O2 from air), ultimately to produce gypsum, which precipitates from solution in the sump. HCl is also dissolved in the water and neutralised to produce calcium chloride solution. Fresh limestone slurry is pumped into the sump to maintain the required pH. At many plant, crushed limestone is milled on site before being slurried and pumped into the absorber sump. Although a certain amount of liquor oxidation occurs naturally due to excess air in the flue gas, the sump liquor is sparged with air, oxidising any remaining bisulphite to sulphate. Gypsum slurry (contaminated with ~3% limestone) is extracted from the absorber sump, thickened, de-watered and washed for subsequent storage before dispatch from site. As described above, HCl is removed from the flue gas in the scrubber, to produce calcium chloride in solution. In addition to this, trace quantities of fly ash are also removed from the flue gas. These and impurities in the limestone will accumulate in the process liquor as dissolved metal salts and suspended minerals such as quartz. The concentrations of these contaminants must be controlled to ensure the gypsum purity is maintained at the required level and high concentrations of chloride do not inhibit the desulphurisation process chemistry. The system is purged with water to control the concentration of these contaminants. Fresh water is added to the absorber via the de-mister wash. The purge stream is taken off as the overflow from the hydrocyclone system used for gypsum thickening. The purge stream, which contains dissolved solids and very fine suspended particles, is sent to the waste-water treatment plant. Here lime is added to raise the pH and precipitate heavy metals from solution. The treated water is then normally discharged from site.
;;
Despite falling prices, the limestone gypsum process should still be regarded as relatively high in capital cost, significantly higher than most other processes except ammonia scrubbing and the regenerative types. It is also more complex than some other process types. However, for many applications it will provide a lower operating cost than other, lime-based processes. This is because limestone is normally much cheaper than lime, and normally the by-product gypsum can be sold rather than incurring a disposal cost. This becomes particularly important for plant with a high sorbent consumption. The limestone gypsum process will usually offer the lowest through-life cost option for large inland plant with medium- to high-sulphur fuel, a high load factor and a long residual life. The limestone gypsum process is the most well-developed and widely adopted FGD process worldwide, and is the one normally adopted for a large power station. The total worldwide installed capacity is approximately 149,000MWe for coal-fired plant alone. The technology is very well understood and is offered by many contractors. It probably offers a lower commercial risk than any other process, and a plant can be obtained at a competitive price. The process is capable of high sulphurremoval efficiency, even with fairly high-sulphur fuel. Most suppliers would now offer 95% removal for use with European coals. Some recent plant have been designed for up to 98% removal. As already noted, there are several design variations, centred on the layout of the absorber itself. The most common design type today is the single loop open spray tower with the flue gas flowing upward through the scrubber. Marsulex, ABB, Lurgi Lentjes Bischoff (LLB), Babcock Borsig, Kawasaki and IHI produce this type. Babcock and Wilcox (B&W) and Babcock Hitachi have a very similar design but theirs includes a tray at the bottom of the gas treatment zone. This provides gas/liquid contact and presents a more even flow profile to the spray headers. The traditional Mitsubishi Heavy Industries (MHI) design is very different from the others. It is not an open spray tower, but has a layer of packing in order to obtain effective gas/liquid contact. Also the flue gas is normally drawn down the tower rather than upward. Recently MHI has adopted a type of open spray tower which it calls the double-contact flow scrubber (DCFS).
Sea-water Washing The sea-water washing (SWW) process uses untreated sea water to scrub the flue gas, taking advantage of sea water’s natural alkalinity in order to neutralise the SO2. After scrubbing, the water used is treated with air to reduce its chemical oxygen demand and its acidity, and is then discharged back to the sea. This is a relatively new technology for desulphurisation of power plant flue gases, although it has been used on small-scale industrial applications for over 30 years. There are only two suppliers, ABB and LLB, the former having the most experience; LLB is currently commissioning its first plant.
Precipitator
Flue gas
Fly ash
Flue
By-pass damper
ID fan
Hydrocyclones
Booster fan Reheater
v v
Limestone mills
Figure 4. Schematic of a limestone gypsum FGD process
Water discharge
v v
Limestone store
Waste-water treatment
Absorber
Sludge
Slurry tank
Air Gypsum
1751 TSR 012
31/5/00 3:59 pm
Page 4
The ABB design is shown schematically in Figure 5. Flue gas from the ESP and ID fan passes through a booster fan before entering the gas/gas reheater. The gas from the reheater enters the absorber and mixes with the relatively cold sea water. The flue gas is cooled and saturated with water vapour. This low temperature arises because the sea water passes directly through the scrubber, and is not recycled as in other wet scrubbing processes. The gas is scrubbed with the (alkaline) sea water to remove the SO2. The manufacturers claim that up to 99% of the SO2 can be removed within the absorber. This process also removes almost 100% of any HCl in the flue gas. At the top of the absorber, the gas passes through a de-mister to remove suspended water droplets. After leaving the absorber, the gas is passed through the reheater again, to raise its temperature before being exhausted to the stack. Because the flue gas leaves the absorber at a low temperature, perhaps 15-40ºC depending upon the local sea water temperature, an additional form of reheat is sometimes required. One option is to force a small percentage of hot untreated flue gas into the cold treated gas stream, after it has left the absorber, but before it reaches the gas/gas reheater. This dries as well as warms the treated gas, and helps prevent reheater fouling and corrosion. In all applications of the SWW process on power plant, raw sea water is obtained from the steam turbine condenser outlet. In most plant, all the condenser outlet water is used in the FGD plant, so as to utilise all the available alkali from this source. Part of this water is pumped into the top of the absorber tower. As the water falls down the tower, it passes through the packing and comes into close contact with the rising flue gas and dissolves the SO2 and any HCl. The acidified liquor is collected in the absorber sump. It is not recirculated back to the top of the tower, but flows into the external mixing basin and aeration lagoon. Here it is combined with the remainder of the sea water from the condenser outlet, and air is blown through to reduce the chemical oxygen demand, and raise its pH by driving off carbon dioxide (CO2). The treated liquor is then discharged to the sea. SWW FGD is a rapidly expanding technology, particularly in tropical countries. ABB has built 21 plant with a total installed capacity equivalent to 2470MWe. LLB is currently commissioning two 610MWe plant in Indonesia. SWW’s main advantage is that it requires no solid sorbent as a reagent, unlike nearly all other FGD processes. The plant design is relatively simple. The most obvious disadvantage is that it is limited to use at coastal sites. The process is capable of very high SO2 removal (up to ~97-98%), but only if the fuel sulphur content is below 2.5-3.0 wt%. High SO2-removal efficiencies at higher SO2 loadings would require additional sea water, above that used by the power plant for cooling, and would significantly increase capital and operating costs.
Ammonia Scrubbing The ammonia/ammonium sulphate or ammonium scrubbing process works in a similar way to the limestone gypsum process except that aqueous ammonia is used as the scrubbing agent. SO2 is removed from the flue gas by reaction with ammonia, and the final product is ammonium sulphate. Ammonia scrubbing has been used intermittently since the 1950s. The only plant currently operational is installed on a 350MWe oil-fired boiler system at Dakota Gas Company’s Great Plains plant. This has been designed for 93% SO2 removal, treating gas from high-sulphur oil. The plant is operating successfully. FGD plant manufacturers indicate that SO2-removal efficiencies in the region of 98-99% can be achieved within the absorber systems, although commercial plant have been designed for 91-93% removal. There are two known suppliers with successful commercial experience, LLB and Marsulex. Flue gas from the ESP and ID fan is passed through a booster fan before entering the gas/gas reheater (Figure 6). The gas then enters a prescrubber where it comes into contact with a recirculating ammonium sulphate slurry. The gas is cooled and becomes saturated with water vapour. The saturated gas leaves the pre-scrubber through a mist eliminator, and then enters the absorber, where it is scrubbed with subsaturated ammonium sulphate solution, which removes the required amount of SO2 from the flue gas. At the top of the absorber, the gas passes through two stages of de-misters to remove suspended water droplets. The aqueous solution leaving the absorber is processed to produce ammonium sulphate, which is a relatively high-value product that can be used in fertilisers. The high value of this by-product is the principal advantage of this process. With high-sulphur fuels, the receipts from the sale of the sulphate can exceed the costs of operating the FGD plant. However, there could be commercial risks associated with this, because the price of ammonium sulphate and ammonia are both very volatile. A potential risk arises from the need to store ammonia on site, either in anhydrous form, or as a concentrated aqueous solution. This might cause serious difficulties in the planning stage, at certain sites. These plant are expensive to build, and require a large ‘footprint’ similar to a limestone gypsum plant. The process has the advantage that there is no waste-water discharge, and there are unlikely to be problems of scaling and blockage. At certain sites, particularly those burning high-sulphur fuels, or with the potential to do so, this process could be a very attractive one. However, it is unlikely to achieve very widespread use because very few plant are needed to satisfy the market for ammonium sulphate fertiliser in a particular country or region.
Precipitator
By-pass damper
Flue gas
Flue ID fan
Flue
By-pass
Damper
Outlet damper Reheater
Purge
Absorber
Absorber Water Reheater Pre-scrubber
Sea water from condenser Hydrocyclone
Packing
Air
v v v v
Centrifuge
Return v v v v v v to sea
Figure 5. The SWW process
Bleed Compactor
Oxidation air
Ammonia storage tank
v v v
Booster fan
Booster fan Fly ash
v v v v v v
Inlet damper
Dryer
Figure 6. The ammonia scrubbing process
Bleed
1751 TSR 012
31/5/00 3:59 pm
Page 5
Precipitator ID fan
By-pass
Condenser
Flue
Damper Absorber
Booster fan
Fly ash
Reheater v v v v v v
Sodium carbonate/ hydroxide
v v v
Blowdown Sulphate solids
Water
EDTA Sodium carbonate or hydroxide make-up
Regenerated Liquor
Tank
Tank
Figure 7. The Wellman-Lord process
The Wellman-Lord Process
absorber, the gas is passed through the reheater again, to raise its temperature before being exhausted to the stack.
The Wellman-Lord Process is regenerative, ie the active reagent used for removal of SO2 from the flue gas is regenerated in a second process stage, and returned to the first stage (absorber tower) for re-use. Consequently, the process does not involve the large-scale consumption of lime or limestone, unlike other processes described here. The process involves the wet scrubbing of SO2 from the flue gas with aqueous sodium sulphite solution. It produces a saleable by-product that, depending on the plant’s design, could be elemental sulphur, sulphuric acid or liquid SO2. The Wellman-Lord process has been installed on nearly 40 plant, in Japan, the USA and Germany. This includes over 3000MWe of electric utility boilers, and many industrial plant. However, there appears to have been no new plant built in recent years. Flue gas from the ESP and ID fan is passed through a booster fan before entering the gas/gas reheater (Figure 7). Here the gas is cooled as heat is extracted. The warm gas from the reheater enters the pre-scrubber/absorber and mixes with the process liquor. An equilibrium temperature is established, when the flue gas becomes saturated with water vapour. In the pre-scrubbing stage, fly ash and HCl are removed. In the main absorber, the gas is scrubbed with the process liquor, to remove the required amount of SO2. Typically 95-98% of the SO2 can be removed within the absorber. At the top of the absorber, the gas passes through de-misters to remove suspended water droplets. After leaving the
A pre-scrubber is usually fitted upstream of the absorber, primarily to remove any HCl present in the flue gas. If HCl were to dissolve in the main absorber liquor, the concentration of sodium chloride in the liquor would progressively increase to levels where it would interfere with the chemistry governing the removal of SO2. The degree of desulphurisation attained would hence progressively fall off. In the main absorber, the flue gas is scrubbed with aqueous sodium sulphite solution, forming sodium bisulphite. The sodium bisulphite is decomposed by steam heating in an evaporative crystalliser to produce sodium sulphite and SO2. The sodium sulphite is returned to the flue gas absorber tower circuit for re-use, while the concentrated SO2 gas stream can then be treated as appropriate to produce a by-product suitable for export. Whether this is concentrated SO2 liquid, sulphuric acid or elemental sulphur would depend on the local commercial environment. This process can achieve a SO2-removal efficiency of well over 95% on high-sulphur fuels. It is expensive to install but relatively cheap to operate and, as such, in relation to other processes, is best suited to high SO2removal requirements, high-sulphur fuel, and plant with a long residual life. Comparative studies have suggested that the operating cost is very similar to that of the limestone gypsum process. The process also has the advantages that it does not require the consumption of large quantities of sorbent and does not produce large quantities of solid waste.
CFB reactor
New FF or ESP
From boiler air heater
Recycle
ID fan
Water Lime storage silo
Disposal silo
Lime feed bin
Lime reception system
V Blower
Dry product for disposal
Hydrator
Blower Blower Figure 8. The CFB process
1751 TSR 012
31/5/00 3:59 pm
Page 6
Circulating Fluidised Bed (CFB) In the CFB process, the flue gas is passed through a dense mixture of lime (calcium hydroxide), reaction products and sometimes fly ash, which removes the SO2, SO3 and HCl. The final product is a dry powdered mixture of calcium compounds. The process has been commercially available for over 10 years, and is an expanding technology, particularly for retrofitting to small- to mediumsized power plant. Because of its simplicity, higher performance, lower spatial requirement, and sometimes lower cost, it is nowadays being chosen instead of the more widely established spray dry process in certain applications. The process and variants on it are now supplied by several vendors, whose designs vary significantly, although the process chemistries are the same. The originator and most experienced vendor is LLB. Flue gas from the airheater (Figure 8) is carried through the inlet venturi throat of the CFB reactor and passes upwards through a fluidised bed of lime, reaction products and fly ash particles contained within the vertical reactor tower. This removes up to 99% of the SO2 and all of the SO3 and HCl from the flue gas. From here the gas is carried through the dust arrestor and the ID fan to the stack. A large quantity of the particulate matter in the CFB reactor is carried with the flue gas into the ESP or fabric filter (FF) located downstream. Most of the solids collected in the pre-collector and ESP are returned to the reactor, so as to achieve a high dust loading within the fluidised bed. The normal sorbent is quicklime, which is hydrated on site to make calcium hydroxide powder (hydrated lime). This is injected into the base of the reactor. Water is also added to humidify the flue gas and so improve SO2 and particulate removal. The water flow is controlled to achieve a temperature ~20ºC above the adiabatic saturation temperature of the gas. The solid by-product from the process, including fly ash, is transported from the bottom of the ESP to a silo, prior to dispatch from site.
atomiser. The water in the slurry will humidify the flue gas and so improve both SO2 and particulate removal. The water flow rate is controlled so as to achieve a temperature approximately 20ºC above the adiabatic saturation temperature of the gas. When firing bituminous coal, the humidified gas temperature would be ~70ºC. The solid by-product from the process, including fly ash, is transported from the bottom of the ESP to a silo, prior to dispatch from site. As with other semi-dry systems producing a throw-away by-product, the spray-dry process is relatively cheap to install, typically being ~70% of the cost of the equivalent limestone gypsum system. However, the variable operating costs are among the highest of the major FGD processes, due to both the high lime usage and the costs of by-product disposal. The lower sorbent utilisation of the spray-dry process, compared with the CFB, means that additional costs are incurred twice: extra lime has to be bought and then a portion of this is dumped at a cost. The spray-dry process is one of the most well-developed and widely used worldwide. The total installed capacity is in excess of 15,000MWe. The technology is well understood, and offered by a number of contractors. The process is very similar in many respects to the CFB process and the two are in competition. The process can achieve 85-90% SO2 removal with moderately high-sulphur fuels. The spray-dry process is cheaper to install than a limestone gypsum plant, and similar to or slightly more expensive than a CFB-type plant. However, like the CFB it can be relatively expensive to operate, depending on the relative costs of labour, power, lime and limestone. The disposal cost of the residues produced also adds to the overall operating cost.
Spray-dryer
CFB FGD plant have been fitted to a total of over 3000MWe of power plant, as well as units fitted to a variety of industrial processes (such as hydrogen fluoride removal), at sizes of up to 300MWe. Major suppliers of the technology are LLB (Germany), Wulff (Germany), FLS Miljø of Denmark (gas suspension absorber (GSA) process) and ABB (new integrated desulphurisation (NID) technology). The CFB process is capable of very high SO2-removal efficiency, even with very high inlet SO2 concentrations. For example, one German plant achieved 97% SO2 removal with an inlet SO2 concentration of 13,000mg Nm-3. Several CFB/GSA plant have achieved >99% SO2 removal. The process can also achieve complete removal of SO3. This is a well-established FGD process with rapidly growing experience. It is cheaper to install than a limestone gypsum plant and costs about the same as a spray-dry plant. It has a much lower space requirement than a limestone gypsum plant, at least as high SO2-removal efficiency, and is capable of complete removal of SO3. It has almost unlimited turndown capability and accommodates very rapid changes in inlet SO2 concentration. Also, it does not normally suffer from serious scaling, plugging or corrosion problems. However, it can be relatively expensive to operate and, in common with all other semi-dry processes, it generates a waste product that normally has to be disposed of.
Spray-dry Process In the spray-dry process, concentrated lime (calcium hydroxide) slurry is injected into the flue gas, to react with and remove acidic compounds such as SO2, SO3 and HCl. The final product is a dry powdered mixture of calcium compounds. The spray-dry process is supplied by several vendors, whose designs vary significantly - although the process chemistries are the same. The flue gas from the air heater is carried into the spray-dryer vessel, where it comes into contact with a finely atomised spray of lime and by-product slurry, delivered from a single high-speed rotary atomiser (Figure 9). This removes up to ~95% of the SO2 and most if not all of the SO3 and HCl from the flue gas. From here the gas is carried through the dust arrestor and the ID fan before discharge through the stack. The normal sorbent fed to this process is quicklime. This is slaked on site, with excess water, to produce a calcium hydroxide slurry (slaked lime). This is mixed with recycled by-product before being pumped to the rotary
Flue
ESP or FF
From boiler air heater
ID fan Disposal silo
Lime storage silo
Blower
Water
Lime reception system
V Blower
Lime feed bin
Blower
Slaker Lime slurry feed tank
Figure 9. The spray-dry FGD process
The Duct Spray-dry Process This process is essentially the same as conventional spray-drying, except that in this case the spray-dryer vessel is omitted, and the lime slurry is sprayed directly into the duct. The lime reacts with and removes the acid gases. The final product is a dry powdered mixture of calcium compounds. The process has been developed by two suppliers, but has not yet reached full-scale continuous commercial operation. It is one of a number of FGD processes developed or being developed primarily for those instances in which a moderate degree of desulphurisation (50-75%) is required on plant with limited operating hours and remaining lifetimes.
Fur nace Sorbent Injection This is another process developed for moderate degrees of desulphurisation with low capital costs. The process involves the injection of hydrated lime into the furnace cavity of the boiler to absorb SO2. Spent sorbent is extracted with the fly ash, in an ESP or FF. The final product is a mixture of ash and calcium compounds. This process was first investigated in the 1950s and a second phase has been under way since the 1970s. However, there are very few plant now in commercial operation, most being in Poland. Dry hydrated lime is
1751 TSR 012
31/5/00 3:59 pm
Page 7
blown pneumatically into the furnace, typically above the burners (Figure 10). This removes up to ~70% of the SO2 from the flue gas. From the boiler, the gas is carried through the air heater, dust arrestor and ID fan before discharge through the stack.
Sodium bicarbonate is pneumatically injected into the flue gas stream as a dry fine powder. This removes up to ~70% of the SO2 from the flue gas. SO3 and HCl are removed to some extent. From here the gas is carried through the dust arrestor and the ID fan before discharge through the stack. All of the particulate matter from the process and the fly ash are carried with the flue gas into the dust arrestor – an ESP or FF.
It is one of the cheapest FGD processes to install but can be expensive to operate because it is inefficient in its use of sorbent. Because of this, furnace sorbent injection is most suitable for retrofit situations. It is well suited to a situation where only a low SO2-removal efficiency is required, and where there is little space available in the unit plant area. The fly ash can not be collected separately from the spent sorbent. Consequently all the furnace ash as well as the solid by-product mixture must be dumped.
The process has been demonstrated on four full-scale, coal-fired boilers of 80-575MWe in the USA. It has also been demonstrated on a 120MWe boiler in the UK by PowerGen.
Combined SO x /NO x Removal Systems
The Sodium Bicarbonate Injection Process
Both SO2 and oxides of nitrogen (NOx) are present in flue gases. Since emissions of both are regulated, it would, in principle, be highly desirable to remove both using the same process. However, despite the fact that both are acidic (and therefore amenable to reaction with a range of alkaline substances), in practice, separate methods are normally used for the control of each: conventional FGD processes are used to restrict SO2 emissions and NOx are limited either by combustion measures or selective catalytic reduction (SCR). One reason for this is that any combined SOx/NOx-removal system would have to be sufficiently effective at removing both species that no further system was required.
This process involves the direct injection of dry sodium bicarbonate into the flue gas duct downstream of the airheater, to react with and remove acidic compounds such as SO2, SO3 and HCl. The final product is a dry powdered mixture of sodium compounds and fly ash. It is suitable primarily for those applications where a moderate degree of desulphurisation is required at low capital cost, although it should be noted that the reagent itself, sodium bicarbonate, is relatively expensive.
Several combined SOx/NOx-removal systems have, however, been developed to the point where they are suitable for deployment on utilityscale boilers. One of the most advanced of these is the SNOX process (Figure 11).
Boiler ESP
Flue
The SNOX process has been developed by the Danish company Haldor Topsøe. The process is located downstream of the particulate control device. The flue gas is reheated and then undergoes SCR. The flue gas is then further heated and a second catalytic reactor oxidises SO2 to SO3. The gas is then cooled to condense out the SO3 as sulphuric acid. The condenser uses glass tubes to prevent excessive acid corrosion.
ID fan Blower Disposal silo Water for humidification
Air compressor
Dry product for disposal
A further point about the process is that, since both the oxidation of SO2 to SO3 and the reaction of water vapour with SO3 to form sulphuric acid are exothermic, for high-sulphur coals (ie >~2.5%) the heat released is sufficient to offset the auxiliary power consumption. The process uses no reagents other than ammonia and produces sulphuric acid of saleable quality.
Water Lime reception system
V Blower
Lime feed bin
Hydrator
Blower
Large SNOX units have been built on plant in Denmark, Italy and the USA, with smaller units in Japan, the Czech Republic, Italy and Denmark. A SNOX unit has been operational on Unit 2 (305MWe) of Elsam’s Nordjyllansværket
Figure 10. FGD using furnace sorbent injection
Electrostatic precipitator
Stack Cooling air
Boiler Flue gas
Support burner
To disposal Air preheater
Air
Clean flue gas Hot air discharge
Flue gas Flue gas heater
Condenser (WSA Tower) Sulphuric acid
Coal
Acid collector
Baghouse
Ash
Support burner
Ammonia Acid storage tank
Catalytic NOx reactor Ash to disposal Hot air Natural gas Support burner
Figure 11. The SNOX process for the combined removal of NO x and SO x (From the USDOE Website)
Catalytic SO2 reactor
31/5/00 3:59 pm
Page 8
in Denmark since 1991. SNOX has also been installed in the USA under the United States Department of Energy’s (USDOE’s) Clean Coal Technology Demonstration Program. A small unit was installed on a slip-stream (35MWe equivalent) of Unit 2 at Ohio Edison’s Niles station in Ohio.
FGD COSTS
Total plant cost
1751 TSR 012
Costs of FGD plant are very site-specific. The capital costs of FGD plant are difficult to accurately assess as they are considerably influenced by market conditions and other factors, eg geographical location and the amount of preparatory site work required. Running costs depend on the costs of sorbents, the costs associated with disposal of the by-products and power costs, all of which are influenced by local conditions.
Limestone Gypsum
Lime spray-dry
CFB
Ammonia scrubbing
WellmanLord
Reagent handling
SO2 removal
Flue gas handling
By-product handling
General & additional equipment
Engineering & contingency
Capital Costs Bid costs of FGD plant depend on market conditions and other commercial factors. Such costs are seldom disclosed. In addition, the cost of the FGD plant obviously depends on technical factors, eg:
Figure 13. Indicative relative costs of FGD processes (After EPRI, 1992)
Operating Costs
• volume of flue gas to be treated Operating Costs can be split into variable and fixed costs. • concentration of SO2 in the flue gas • degree of desulphurisation required • quality of the by-products produced • other environmental constraints, eg permitted waste water discharges • the need or otherwise for flue gas reheat • the degree of reliability and redundancy required • design life.
Reagent and by-product costs can be considerably influenced by the location of the plant. The total cost of a reagent to the plant will include a transport cost, and so the proximity (or otherwise) of a suitable limestone mine, for example, can be an important consideration. Similarly, the economics of an FGD process benefit from the proximity of a convenient disposal point for the by-products; eg the limestone/gypsum FGD plant at Ratcliffe-on-Soar Power Station benefits from having a major user of gypsum located nearby. Indicative relative variable running costs for several FGD processes are shown in Figure 14.
500 Variable costs
Installed cost ($ kW-1)
Capital costs of FGD plant have been falling in real terms over many years. This is partly due to improvements in design and also partly due to less redundancy as suppliers become more knowledgeable about the abilities of the technology. For example, many early FGD units had multiple and/or spare absorber towers – this is now seldom the case. The downward trend in FGD costs is shown schematically in Figure 12. Current costs of FGD plant are roughly in the range $100-125 kW-1 (£65-80 kW-1), with further falls in cost anticipated in 2000 and beyond.
Variable costs cover such aspects of operation as reagents, by-product disposal and utilities (steam, power, water etc). Reagent costs will be approximately proportional to the amount of SO2 removed, although they will also be influenced by the chemical stoichiometry, which may vary as the degree of desulphurisation changes. Similarly, by-product disposal costs will be proportional to the amount of by-product produced (and will be negative if the by-product can be sold). Costs of steam, power, water etc will be determined both by the amount of flue gas processed and by the throughput of reagents and by-products.
400 300 200 100 0
Limestone Lime Gypsum spray-dry
1970
1980
1990
1997
CFB
Ammonia Wellmanscrubbing Lord
Utilities
By-products
2000
Year
Reagents
Figure 12. Reductions in the cost of retrofit FGD units in the USA (After Broward & Brinkmann)
Figure 14. Indicative relative variable operating costs (After EPRI, 1992)
Differences in the capital costs of different FGD processes are determined by the degree of complexity of the process, the amount of engineering required and other factors. FGD processes in which the sorbent is processed to give a saleable by-product (eg limestone gypsum, ammonia scrubbing) or in which the sorbent is regenerable (eg Wellman-Lord) have higher capital costs than other processes (see Figure 13).
In general, those processes that produce a saleable by-product, such as gypsum (limestone gypsum) or ammonium sulphate (ammonia scrubbing), have lower nett operating costs than those processes that produce a nonsaleable by-product that incurs disposal costs. Actual variable operating costs can depend critically on the actual market conditions for sorbents, byproducts, disposal costs etc, and these can be very location-specific. As a general guide, variable operating costs can be in the order of £2 per MWh.
31/5/00 3:59 pm
Page 9
A survey of potential markets for clean coal technologies, published by the International Energy Agency (IEA) in 1996, identified opportunities for FGD retrofits to existing coal-fired units. It also estimated the market for new pulverised fuel (pf)-fired units; since some or many of these new units will be fitted with FGD as a matter of course, an overall estimate of the market for FGD plant, for coal-fired plant, can be made for the next decade.
Fixed cost
1751 TSR 012
The total market for FGD plant is likely to exceed £1Bn per year over the next 10 years. Limestone Gypsum
CFB
Lime Spray-dry
Operations
Ammonia scrubbing
Maintenance
WellmanLord
Admin & support
Figure 15. Comparative fixed operating and maintenance costs for FGD processes
Fixed costs cover such aspects as operating labour, maintenance (both materials and labour) and administration. Maintenance costs are usually correlated or estimated as a percentage of the total plant cost. The actual percentage of plant cost depends on the type of unit operation, with unit operations such as solids handling, or those involving high temperatures or pressures, requiring more maintenance than a process that involves liquids and gases at ambient conditions (see Figure 15). Maintenance costs are usually taken to be independent of plant operating hours or operating regime. In reality both these affect maintenance costs. The number of start-ups, in particular, can have a very significant effect on the rate of degradation of plant components, due to the mechanical and thermal stresses that the start-up procedure imposes on the plant. Specific examples include the effects of thermal cycling on the linings used in FGD absorbers and the additional rotational loads on motors and pumps as they are accelerated to operating speed. This, however, is still a relatively poorly understood area.
FUTURE MARKETS FOR FGD The future market for FGD plant will be mostly, although not exclusively, for use with coal-fired power stations. This market can be divided into two classes: retrofits to existing units and FGD equipment for new units. The former will be more important for parts of the world such as Western Europe, where there is unlikely to be any significant new build of coal-fired power stations in the next 10 years. The latter will be more important for parts of the world such as India and China. Other potential markets for FGD include: oil-fired boilers, sulphuric acid plant, cement kilns, other industrial boilers and oil refinery fluid catalytic cracking units (FCCUs).
50 45 Retrofits
40
New Units
Capacity in GWe
A considerable fraction of the coal-fired capacity in Canada and the USA has FGD (retro)fitted. However, there is significant scope for further FGD retrofits, as legislation governing air quality is being progressively tightened. In addition, there will be some new build of coal-fired units. Although a substantial proportion of this build will be integrated gasification combined cycle (IGCC) or fluidised bed combustion (FBC) that do not require FGD, there will be some new pf-fired units that will certainly require FGD. Overall, therefore, North America will continue to be one of the major markets for FGD plant worldwide.
Europe The two factors limiting the future market for FGD plant in Western Europe are (i) a large proportion of coal-fired plant are already fitted with FGD, thus reducing the market for further retrofits, and (ii) the switch to gas as the preferred fuel for power generation limits the amount of new coal-fired capacity that will be built. Overall, therefore, the market for FGD in Western Europe is in its mature phase, with the majority of units having already been (retro)fitted with FGD. Parts of Eastern Europe and the Former Soviet Union (FSU) are very dependent on coal, not only for power generation but also for industrial and domestic use. Under Communist regimes, environmental protection was sacrificed to economic development and there was no desulphurisation. In the last 10 years, FGD has been introduced into parts of Eastern Europe; however, this has been constrained by cost. The countries in this region most dependent on coal are the Czech Republic, Poland, Bulgaria, Russia and Ukraine. Nearly all of the coal-fired power stations in the Czech Republic have now been retrofitted with FGD. The most important market for FGD in Eastern Europe at the moment is probably Poland. Poland has ~28GWe of coal-fired plant; of this, 10GWe has been or is currently being retrofitted with FGD. Plans exist to retrofit most of the main coal-fired power stations there. Bulgaria is another country with significant coal-burning capacity; its indigenous lignite is very high in both sulphur and ash, making Bulgarian power stations highly polluting. As yet, only a very small proportion of its coal-fired plant has been fitted with FGD. The major factor limiting the uptake of FGD is the cost. The same applies to both the Russian Federation and Ukraine, both of which have very significant coal-fired generating capacity and coal-fired industrial boilers.
Total
South Asia
35 30 25 20 15 10 5
Central & South America
Africa
Japan, Australia and New Zealand
East Asia
China
South Asia
Central & Eastern Europe and Former Soviet Union
Western Europe
North America
0
Figure 16. Estimated total market for FGD for coal-fired power plant, 1996-2010 (After IEA)
North America
Both Pakistan and India rely heavily on thermal power plant for power supply. India has a large number of coal-fired units burning indigenous coals. These coals are generally high in ash but low in sulphur, and the emphasis on environmental control so far has been mostly on fitting or retrofitting ESPs to control particulate emissions. Very few Indian power plant have FGD (one exception is the Tata-owned plant at Trombay near Mumbai, which uses SWW – Figure 17) and very few if any of the new coal-fired plant have provision for FGD. Recent units commissioned in Pakistan have been based on fluidised bed boilers. There will be some market for retrofit FGD and a larger market for FGD for new plant.
1751 TSR 012
31/5/00 3:59 pm
Page 10
The massive increase in electrical generating capacity required to keep pace with increasing power demand means that the emphasis for FGD will be on new units rather than retrofits. However, it should be noted that most current coal-fired independent power projects (IPPs) in China lack FGD.
Japan, Australia and New Zealand These three developed countries of the Pacific Rim vary in terms of electricity generation. Coal plays a very minor role in the generation of power in New Zealand. Australia, particularly the eastern part, depends heavily on coal for power generation. Australian coal is relatively low in sulphur, thus sulphur emissions have not hitherto been a major issue and none of the major coal-burning stations is fitted with FGD. Japan generates power mostly from gas, oil and nuclear. Its coal-fired units are all equipped with FGD. The absolute amount of power generated from coal is set to rise as older oil-fired units are replaced, and these new coalfired units will require FGD, although a significant proportion of new coalfired units in Japan may well employ pressurised fluidised bed combustion (PFBC).
East Asia Many of the countries in this region have recently undergone (South Korea) or are currently undergoing (eg Malaysia, Indonesia) rapid economic expansion with a consequent increase in power demand. However, economic growth in many of these countries has recently, albeit temporarily, stalled. It is anticipated that much of the new generating capacity will be coalfired. Environmental problems resulting from the use of coal have already been significant in some areas and some of the countries in this region have already installed FGD.
Figure 17. SWW FGD plant at Tata Electric’s Trombay plant, India (Courtesy of ABB Alstom Power)
China Coal is China’s primary indigenous fuel source and is in widespread use for power generation and for industrial and domestic purposes. The widespread use of coal on a significant scale with very few environmental controls has resulted in China having significant pollution problems. China’s ninth Five Year Plan (1996-2000) is the first to address environmental protection, and includes provision to reduce emissions from the coal and oil industries. FGD plant was introduced into China in the early 1990s (Figure 18). So far, very few plant have been built, and the emphasis has been on trying one of each type in an attempt to determine which are the most suitable technologies for China. Many of the plant so far built have been supported by the World Bank.
Figure 19. LLB SWW plant at Paiton, Indonesia (Courtesy of LLB)
Figure 18. Luohuang FGD plant under construction in China (Courtesy MHI)
1751 TSR 012
31/5/00 3:59 pm
Page 11
Central and South America Coal plays only a very minor role in power generation in Central and South America. The market for FGD for new and retrofit units is unlikely to exceed 1GWe in the next 10 years.
Africa Coal is the predominant source of power in South Africa and in some neighbouring states. The IEA forecasts that there could be 4GWe of FGD retrofitted to existing plant; in addition, a further 4GWe of FGD could be required for new units.
As FGD plant designs have improved and environmental standards have become more onerous, there has been a need to upgrade the performance of older and less well-designed plant. Many of the leading suppliers have been involved in this already, eg fitting trays or improved spray header arrangements, improved nozzles, or better packing. There will be a steady demand for this type of improvement of older plant in the future, including such recent innovations as double open-ended hollow cone nozzles, to provide co-current scrubbing, as well as increased limestone loading, finer grinds and/or organic additives.
NEW DEVELOPMENTS Improvements to Existing Processes Work is ongoing in a number of fields to improve currently-existing FGD processes. Much of the work is focused on limestone/gypsum and other wet scrubbing processes, since these represent the most common type worldwide. Specific areas of improvement include higher desulphurisation efficiencies, lower capital and operating costs and better reliability. One of the most noticeable developments is in the scale-up in absorber size. At one time, it was not uncommon to have multiple scrubbers for one boiler, partly for redundancy reasons. Experience with larger FGD units, and confidence in the high reliability of FGD plant, has given suppliers the confidence to move firstly to single absorbers for even the largest units (up to 1000MWe) and, recently, to install one FGD unit serving two large (~400MWe) boilers. Scaling-up plant size in this way considerably reduces the overall capital costs, since one absorber is usually cheaper than two of half the throughput: the amount of steel etc used is much less and fabrication procedures are also reduced. Costs have also been reduced by increases in the gas velocity, and thus flowrate, through the absorber. This results in a smaller (and thus cheaper) absorber for the same gas flow. Until recently, a design velocity of ~3m s-1 was usual; however, velocities of ~4m s-1 are now being adopted and 4.5m s-1 is considered possible. Reductions in tower height are also being investigated, as the processes in the scrubber and sump are better understood and this allows scrubbers to be designed with shorter gas and particle residence times. Aerodynamic modelling and computational fluid dynamics (CFD) simulations of the gas and liquid flows in absorbers are proving invaluable in ensuring better gas/liquid contact and increased rates of mass transfer. This aids the development of better nozzle and contacter designs and mist eliminators. A further improvement to the limestone gypsum process is the use of higher-concentration limestone slurries. This gives better mass transfer and also reduces running costs, as the amount of liquid or slurry to be pumped is reduced. There have been important developments in the major plant components throughout the last 30 years, in parallel with the process developments. These include larger booster fans and a move towards axial rather than centrifugal designs. These require far less power at reduced boiler loads. The development of larger and more efficient fans will be advantageous to the development and acceptance of very large absorbers. Gas/gas exchangers are another area of work, with the use of liquid-coupled heaters (or other low-leakage exchangers) reducing the amount of gas leakage between the clean and raw gas sides of the flue gas path.
Figure 20. GSA absorber (Courtesy of FLS Miljø)
New Processes Processes are under development in which the flue gas is irradiated with electron beams in order to convert the SOx (and NOx) into more reactive species that can be removed from the flue gas more easily. Most variants of this process combine the process with the injection of ammonia for NOx control. High-energy electrons react with molecules in the flue gas to produce radicals that then react with the SOx and NOx in the flue gas to produce sulphuric and nitric acids that in turn react with ammonia or some other alkali.
Further development of corrosion-resistant materials continues. Some slightly improved or lower cost alloys have come onto the market, and a vinyl ester resin with mica rather than glass flakes has been developed, which will withstand slightly higher flue gas temperatures. Glass reinforced fibre (GRP) pipe sizes have increased to the point where they are now used for the manufacture of small absorbers, up to ~80MWe equivalent or larger in size. Further use of (larger) GRP scrubbers can be expected, in many cases offering lower costs, with better corrosion and weather resistance and easier maintenance than for metal absorbers.
Research on electron beam processes was started in Japan in 1970, but they are only now reaching the point of commercial-scale demonstration. One of the most advanced of the processes under development is that of the EBARA Corporation (Figure 21). Flue gas from the ESPs is cooled and enters the process vessel in which ammonia is added and the gas irradiated with electrons. Ammonium sulphate and nitrate are formed and are carried in the gas as an aerosol. The ammonium salts are removed downstream of the reaction vessel using a further ESP, and the salts are recovered and sold as fertiliser. The process has recently been tested at the 90MW e scale on the Chengdu Power Station belonging to the Sichuan Electric Power Company; 80% SOx and 20% NOx reductions were achieved.
One area where there is a need for improved materials is in FGD recycle pumps. Under certain operating conditions these can have a relatively short life. Rubber internals can suffer damage through contact with solids, and metal casings and impellers can suffer corrosion and cracking, particularly in high-chloride environments.
Considerable research effort has been expended on the development of dry sorbent-based FGD systems that are also capable of removing NOx. Up to 90% NOx reduction has been achieved in some pilot-scale reactors. MHI and Hokkaido Electric have been jointly developing the LILAC (lively intensified lime ash compound) process. The reagent is a mixture of lime,
1751 TSR 012
31/5/00 3:59 pm
Page 12
fly ash and spent sorbent (or gypsum). It is claimed that this is made highly reactive towards SO2 and NOx through curing with hot water. The reagent can be sprayed into the flue gas as a slurry or as a dry powder, and can be used with a spray drier, or injected directly into the flue gas duct. This process is still at the development/demonstration stage. It has recently been retrofitted to the Huangdao Power Station in China. A combined SOx/NOx system using regenerable copper oxide adsorbent is under development in the USA, named COBRA (copper oxide bed regenerable application). In the process a copper oxide sorbent is used to remove SO2 in a moving-bed adsorber. The copper oxide is converted to copper sulphate and also acts as a catalyst for the reduction of NOx to nitrogen using ammonia. The sorbent is regenerated using methane and the SO2 liberated is processed to give elemental sulphur or sulphuric acid. Tests on the 1MWth scale have shown desulphurisation of >98%.
;
Spray cooler
Ammonia
Materials development is required to underpin the work on component improvement outlined above. In addition, the application of metals, organic linings and GRP for FGD absorbers, could reduce costs, and improve operational flexibility and reliability.
CONCLUSIONS • A wide variety of FGD technologies are available. The most widely used processes are the limestone/gypsum (and its variations) and the spray dry process, but newer technologies such as CFB and SWW are rapidly gaining acceptance.
Flue gas from ESPs
Water
dozen or more centrifuges, which can represent a considerable expense; scale-up of the technology could reduce costs. Furthermore, centrifuges work on a cyclic basis, with rapid acceleration and deceleration that puts high stresses on the equipment. An alternative, the decanter centrifuge, has so far found only very limited application on FGD plant but development work to improve its de-watering efficiency could reduce both capital and maintenance costs. The further development of steam-heated vacuum belt filters capable of high levels of de-watering would also be advantageous.
E-beam system
• Overall, there is ~275GWe of FGD plant currently installed worldwide. • A steady improvement in process design over the years means that modern designs can achieve 95%+ sulphur removal.
ESP Clean flue gas to stack Process vessel Ammonium sulphate/nitrate fertiliser to agglomerator
• At the same time, costs have fallen steadily and are now equivalent to $100-125 kW-1 (~£65-80 kW-1). • Most FGD plant currently operational are in North America, Western Europe and Japan. FGD technology is rapidly being deployed in parts of Eastern Europe, East Asia and South East Asia, and there could be major market opportunities in China and India.
Figure 21. The EBARA process
• Several new processes are under development, many of which are designed to remove both SOx and NOx.
R&D Needs
• At the same time, further improvements are being made to absorber design and to plant components such as heaters and fans.
Key requirements for FGD systems and plant are: • high SO2 removal • high reliability • low auxiliary power consumption • use of a single absorber (where applicable) • saleable or usable by-product. R&D work required to support these requirements can be split into process, component and materials development. Process improvement entails such R&D aspects as better understanding of the flow regimes in absorbers and the nature of the mass transfer phenomena in both wet and semi-dry processes. In addition, the more onerous operating regimes that FGD plant are now operating under mean that work needs to be undertaken to understand the long-term effects of plant cycling and of repeated start-ups and shut-downs, and the optimum condition in which to leave FGD plant standing idle. Work is also required on the utilisation of semi-dry process by-products. The UK has a particular strength in the supply of components for FGD plant, particularly gas/gas reheaters, fans, pumps and gypsum de-watering equipment. Most gas/gas reheaters currently installed on FGD plant are of the rotary regenerative type. These generally perform well, but they can be susceptible to corrosion and inevitably there is a degree of gas leakage, with untreated sour gas crossing over to the clean gas side, reducing the SOx removal of the overall process. There is thus a need for the development of improved designs with greater corrosion resistance and better sealing. Gypsum slurry and recycle pumps are widely used in FGD plant but can suffer from corrosion (if not rubber-lined) or erosion (if rubber-lined). Increased corrosion/erosion resistance will reduce FGD plant downtime and maintenance costs. Gypsum de-watering is undertaken using basket centrifuges or vacuum belt filters. Large FGD plant typically require a
BIBLIOGRAPHY • Boward, W L and Brinkmann, M S (1998) ‘Retrofit FGD System Price Trends and Influence Factors’, Proceedings of the 60th American Power Conference, 14–16 April 1998, Chicago • EPRI (1992) ‘Economic Evaluation of Flue Gas Desulfurisation (FGD) Systems’, EPRI GS-7192, vols 1 and 2 • IEA/OECD (1996) ‘Clean Coal Technology: Markets and Opportunities to 2010’ • Singer, J G (1991) ‘Combustion Fossil Power – A Reference Book on Fuel Burning and Steam Generation’, Edited by J G Singer. Fourth Edition. Published by Combustion Engineering Inc. ABB Windsor Connecticut. ISBN 0-9605974-0-9 • Takeshita, M and Soud, H (1993) ‘FGD Performance and Experience on Coal Fired Plants’, IEACR/58, IEA Coal Research, London, July 1993.
1751 TSR 012
31/5/00 3:59 pm
Page 13
Department of Trade and Industry
DTI/Pub URN 00/652
