Dr Anupam Sanyal, International Environmental & Energy Consultants, USA
The US Department of Energy, the Electric Power Research Institute and a number of US utilities have been developing technologies to meet the proposed mercury regulation for coal fired power plants. A number of these new technologies are showing promise.
The US Environmental Protection Agency (EPA) has recently proposed to control mercury emissions from coal fired power plants from the current level of 48 t to 15 t a year by 2018 – around 70 per cent reduction.
Mercury is present in coal in very small quantities in the form of particulate, element and as compounds. Bituminous coal contains mercury mainly in form of compounds; the elemental form is present in higher concentration in the sub-bituminous variety. When coal is burnt mercury vapourizes and forms various compounds and also stays in its elemental form. This speciation is determined by various factors – rank of coal, type of plant, operating conditions, flyash quality etc. While the mercury compounds are water-soluble and readily captured in wet scrubbers, elemental mercury is insoluble and difficult to remove. Thus no single technology is applicable for every coal or power plant. Various technologies have therefore been under development e.g. sorbent injection, wet and dry scrubbers, fixed and fluidized beds, mercury adsorption, catalysts and pre-combustion coal cleaning.
The use of sorbent involves injecting a powdered material upstream of the electrostatic precipitator (ESP) or baghouse. Injection of activated carbon has long been in commercial use for mercury control for municipal waste incinerators. This technology was, therefore, a natural choice for exploring its applicability for coal fired plants. The results of the on-going development programmes indicate that this technology is promising for commercial application to meet the proposed mercury legislation for coal fired power plants.
A reliable retrofit technology should involve a minimum of new capital equipment and be applicable to the varying US coal quality. Powdered Activated Carbon (PAC) appears to meet these requirements. The mercury in the flue gas on contact with PAC attaches to its surface. Either an ESP or baghouse then collects this. The combined material consisting of about 99 per cent fly ash and one per cent sorbent is either disposed of or beneficially used.
Under a cooperative agreement with the US Department of Energy (DOE), ADA Environmental Solutions (ADA-ES) of Littleton, Colorado, USA, is working in partnership with utilities, coal companies and the Electric Power Research Institute (EPRI) on a series of test programmes at four sites that are representative of 75 per cent of coal fired power generation in the USA.
A typical carbon injection system consists of a silo and twin feeder trains. The reagent is metered by variable speed screw feeders into eductors that carry the reagent to the injection point. Regenerative blowers provide the conveying air. A PLC system controls operation and injection rates.
Figure 1. The sorbent injection system
The first site, the 275 MW Unit 3 of Gaston Station, uses a COHPAC baghouse installed downstream of a cold ESP. Full-scale carbon injection tests were carried out in 2001. The test results showed mercury removal of up to 95 per cent as the carbon injection rate increased. In this configuration, 97-99 per cent of the fly ash is collected in the ESP, the remainder in the baghouse.
A disadvantage of injecting activated carbon, is its impact on salability of flyash. Although mercury with carbon in the flyash is very stable, even trace amounts of activated carbon render the flyash unacceptable for use in concrete. While it meets the ASTM C-618 standard for Class C flyash, it does not pass the foam index test required for its use in concrete. This makes the PAC injected fly ash unsalable for concrete making and hence the plant loses revenue as well as incurs additional expenses for landfilling.
EPRI has developed a Toxecan process involving the use of COHPAC, which improves overall flyash collection efficiency. The Toxecan process is being used to address the flyash salability problem. PAC is injected upstream of the baghouse located downstream of ESP. The ash collected upstream of carbon injection, which constitutes 97 to 99 per cent, thus remains acceptable for sale.
ADA-ES has been selected by the DOE to mature the technology and conduct a one-year test programme at the Gaston Station. The objectives of the programme are to design and install a continuous PAC injection system, evaluate the long term performance of PAC and alternative sorbents whilst evaluating new high permeability fabrics for baghouse.
At the second programme conducted at Pleasant Prairie Station, PAC was injected upstream of the ESP carrying one quarter of the flue gas from the 600 MW Unit. Since PAC injection to remove mercury is facilitated by low temperature, a spray cooling system upstream of the injection point was used for temperature control. Mercury removal commenced immediately with sorbent injection but leveled off to 73 per cent after a certain period and did not increase with increasing injection concentrations above 10 lb per million actual cubic feet (MMacf), or 4.54 kg/28 300 actual m3.
Effective removal of elemental mercury by activated carbon requires a very low concentration of hydrogen chloride (HCl) in flue gas. Activated carbon adsorbs any contaminants in the flue gas – oxides of mercury or sulphur or gaseous HCl. The concentration of the latter at Pleasant Prairie was less than 1 ppm. It is believed that once activated carbon has adsorbed HCl, its effectiveness for mercury adsorption is greatly reduced. This is believed to be the reason for the ceiling phenomenon.
Figure 2. Comparison of Mercury removal performance with PAC
The third test completed in summer 2002 was at Brayton Point, a 245 MW unit which fires low sulphur bituminous coal. There are two cold ESPs in series and a SO3 conditioning system. Base line testing showed that most of the mercury capture took place in the first ESP. During the test PAC was injected at the inlet of the second ESP. Unlike at Pleasant Prairie, no ceiling on the amount of mercury removed was observed at Brayton Point. Removal of 70 per cent at 10 lb/MMacf increased to 90 per cent at 20 lb/MMacf. (Figure 2). This is believed to be due to the presence of 150 ppm of HCl in the flue gas. The removal is also believed to be facilitated by the presence of a high level of oxidized species of mercury, unlike in Pleasant Prairie where the mercury from the PRB coals was mostly in elemental form.
With high sulphur bituminous coal, while the removal efficiency increased with the sorbent concentration, percentage removal achieved was lowest at a little over 62 per cent. This may be due to the high concentration of SO3 in the flue gas compared to that of low sulphur bituminous or PRB coal. SO3 competes for the active sites of PAC and hence reduces the availability of sites for mercury.
The fourth test was at the 86 MW Unit of Salem Harbor. It fires low sulphur bituminous coal and has a cold ESP. SNCR (Selective Non-catalytic Reduction) is the NOx control system. Little data is available on the effect of SNCR on mercury capture. During the base line testing (without SNCR), mercury removal efficiency ranged from 80 to 95 per cent. With the SNCR system on, the efficiency remained unchanged showing no effect of SNCR on mercury removal. The high level of removal could be attributed to the high (17-35 per cent) level of unburned carbon in flyash. The programme also evaluated the effect of gas temperature on mercury removal without sorbent. Increasing the flue gas temperature to the ESP from 270°F to 350°F (132-177°C) reduced the natural mercury removal efficiency from around 90 per cent to 10-20 per cent. This site fired bituminous coal where the mercury in the flue gas was mostly in the oxidized form. Performance of activated carbon on gas stream with largely elemental mercury from firing PRB coal is not known. This would need additional testing to establish the maximum temperature for effective mercury capture.
The above full-scale field tests have shown that activated carbon injection is effective in reducing mercury emissions. It is effective for both bituminous and sub-bituminous coals. The removal can be as high as 95 per cent used with a baghouse. The technology can be integrated with any configuration of air pollution control equipment and scrubbers and is capable of meeting the proposed legislation.
Figure 3. The ECO process flow
An electro-catalytic oxidation (ECO) process has been developed by Powerspan of New Hampshire, USA, for multi-pollution control. It resolves the difficulty of capture of mercury in elemental form. On top of this, it removes SO2, NOx and PM2.5, and produces salable fertilizer products.
It uses a dielectric barrier discharge (DBD) which generates high-energy oxygen and hydroxyl radicals to oxidize elemental mercury to its oxide, SO2 to sulphuric acid, and NOx to nitric acid and NO2. It has achieved 90 per cent removal of mercury over nearly four years of pilot plant testing of a slip stream at First Energy’s 156 MW Burger Plant in Ohio under a cooperative agreement with the DOE.
Figure 4. Comparison of sorbent costs for fabric filters and ESPs
The ECO unit is located downstream of the ESP or baghouse. It treats the flue gas in three stages. A DBD oxidizes the pollutant. Next a scrubber removes the unconverted SO2 and NOx by ammonium sulphate solution. A wet ESP in the final stage aided by the scrubber captures oxides of mercury and the other pollutants. The effluent is sent to a product recovery system where mercury is adsorbed in a bed of sulphur-impregnated activated carbon and disposed of. Salable ammonium sulphate and nitrate are separated out in form of crystals or solution.
The promising results from the pilot plant have led to the award of funding from the Ohio Coal Development Office and First Energy for its commercial demonstration on the flue gas equivalent to 50 MW of the 156 MW Burger unit. It is due to start operation in 2004.
Independent cost analyses for application of the ECO system on a 500 MW size unit using different types of coal estimate a capital cost of $200/kW and operation and maintenance cost of $2.5-3mills/kWh. The variable cost of mercury contaminated sorbent and its disposal is estimated to be over $1616/kg.