Both the development of mercury control technology and its installation in power plants follow the evolution of emissions regulations. With a new standard in the works for Europe, Tildy Bayar investigates what it will mean for mercury control technology companies and Europe’s power plant operators.
New EU rules on mercury control are expected
Credit: Babcock & Wilcox
In a March note, Greenpeace EnergyDesk editor Christine Ottery wrote that European environmental regulations for power plants, which are expected to be finalized by 2016 and come into force by 2020 as part of the Industrial Emissions Directive (IED), “could change the face of Europe’s energy system … though hardly anyone knows they exist.”
Analysts have speculated that the regulations, known as the large combustion plant best available techniques reference document (LCP BREF), could force large numbers of coal-fired power plants across the EU into retirement by 2025.
Along with establishing stricter limits for SOx, NOx and particulate emissions, the regulations, known as the large combustion plant best available technology reference document (LCP BREF), will likely set standards for mercury emissions from power plants. Unlike the US, Europe currently has no set standard for these emissions, and thus the major market for mercury control technologies to date has been North American. In Europe, the need for legislation specifically dealing with mercury has largely been addressed by the mercury reduction co-benefits available from technologies used to comply with existing legislation (the Large Combustion Plant Directive and the current version of the IED) on SOx and NOx removal.
The mercury emissions limits being considered in the draft BREF for plants over 300 MW range between 0.2 àŽ¼/m3 and 10 àŽ¼/m3. Dr Lesley Sloss of the International Energy Agency’s Clean Coal Centre said in May that while “the actual value has yet to be agreed and the applicability of the proposed limits has yet to be defined,” the new BREF “could mean … there may be a new mercury control market opening up in Europe within the next few years.”
And this market could expand even further. Mandar Gadgil, Air Quality Control Systems Engineer with Babcock & Wilcox (B&W), notes that “in the next four to five years, Germany will enact the BREF regulation, and Europe may follow. China, India, South Africa, and other coal-burning countries will implement new regulations. It may take five years or so, but by 2025 I think all plants will have to control mercury all over the world.”
However, Jorgen Grubbstrom, Product Marketing Manager for Dry FGD Environmental Control Solutions with Alstom’s* Steam Business, says the European market may be slower to develop than expected. “Suppliers, member states and different stakeholders understand that it’s very important to have the correct conclusions as they may drive a lot of changes for the power industry,” he says. “[The BREF] is taking more time than expected – it’s a tedious process – so they are in delay.”
Bernd Volmer, Process Engineering & Design AQCS at Mitsubishi Hitachi Power Systems Europe (MHPSE), says his firm will be ready when the time comes. “The US, compared to Europe in regard to mercury reduction, is in front of us,” he says, “so we learn from our partners in the US about the technologies and will implement these also on the European market – the emission values will come into force in 2016-17, and plants will be required to comply in 2020-21.”
Standards development, Volmer notes, is “an ongoing, rotating process”. While power plant operators will be given four years to implement the expected BREF standard, he explains, a subsequent revision will be issued in eight years. “So there is a time interval between a revision of eight years and compliance duration of four years. Every four years a utility will comply with the regulation, then it has another four years’ time to implement a new revision of the standard reflecting the updated technology.
“We have to continuously improve the technology in response to the continuous challenge of emission values,” he says.
How it works
The basis of the control process is the oxidation of mercury, and then its removal within downstream equipment before it is emitted through the stack into the atmosphere. The most common technology involves injection of activated carbon into the plant’s exhaust stream.
Mercury comes in three forms: metallic, ionic and particulate. “The goal is to oxidize all metallic mercury to ionic mercury so it can be removed in the flue gas desulphurization (FGD) system,” explains MHPSE’s Volmer.
According to B&W’s Gadgil, “the main workhorse of the industry for mercury control in the US is powdered activated carbon (PAC) – both halogenated (usually bromine is the halogen of choice) or non-halogenated depending on how much mercury is in the gas phase.” Another “very efficient” and widely used technology is halogen injection into the coal itself.
“It’s very simple,” Gadgil says. “Calcium bromide or sodium iodide is added to the coal. It’s an inexpensive process and results in very high mercury oxidation. The only catch is that for halogen addition to work on its own as a mercury control technology, there has to be some sort of FGD system. Oxidized mercury is very soluble and can be taken out in the FGD.”
There are other sorbents in use, Gadgil adds, such as amended silicate, which is “as good as activated carbon but has not been as widely used due to economic reasons.”
Gadgil also confirms that “sometimes there is re-emission of mercury – this has happened in some plants. If there are 2àŽ¼g of elemental mercury going inside a wet scrubber and 3àŽ¼g coming out, that’s re-emission,” he explains. “This happens because of the chemical nature, processes and the atmosphere inside the scrubber, and as a result some of the oxidized mercury goes from the oxidation phase to the elemental phase. To address that, we have a sulphide-based additive, sodium hydrosulphide, which has proved very effective in controlling re-emission. Other companies have their own re-emission control additives.”
Alstom’s Grubbstrom notes that, “since re-emission is a function of the chemistry of the slurry, in particular the sulphite content is of importance to monitor and control this parameter.” To this end, his firm has recently launched a sulphite analyzer which also measures oxidation reduction potential (ORP) and controls the flow rate of oxidization air to the wet FGD.
MHPSE’s Volmer says the mercury reduction process involves looking at existing plant equipment and “how you can optimize it to meet requirements. For a system where you already have [mercury] mitigation through selective catalytic reduction (SCR), the use of SCR with special types of catalyst is a very low-cost mitigation process, together with a downstream wet FGD equipped for mercury removal.”
Control technologies oxidize mercury for removal in the flue gas desulphurization (FGD) system
Alstom’s Grubbstrom says his firm takes two main approaches. First, a system based on injecting an adsorbent such as PAC upstream of the air preheater in a high-temperature area and collecting it later in an area of at least 50 degrees lower to enhance adsorption. A milling system reduces the size of the PAC to increase the surface area of the sorbent and enhance mercury capture on the surface of the carbon particles, Grubbstrom says.
Secondly, an enhanced PAC process which includes a sorbent storage silo and an injection system comprised of a series of lances in the ductwork, designed to optimize contact between flue gas and PAC. The mercury, PAC and fly ash are removed in a fabric filter.
Gerhard Heinz, Director of Sales & Marketing for Alstom Thermal Services Central Europe & CIS, notes that higher temperatures favour the kinetics of oxidizing elemental mercury and increase the extent of chemical absorption. In addition, “injecting in a high-temperature area before the air heater increases absorption because the mercury is in contact with the flue gas for a longer time,” he says. The mercury is then collected in the electrostatic precipitator (ESP), which “might need to be upgraded a bit to fulfil lower particle emission requirements,” he notes.
Different strokes for different plants
Daniel Chang, Air Quality Control Service Area Leader with Black & Veatch Energy (B&V), notes that attention to site-specific constraints is needed to determine the best mercury compliance solution. “We take into consideration the performance of emissions control technology to reduce emissions to required limits, the ease of integrating into an existing power plant, and then the cost to implement the technology,” he explains.
“For example,” he says, “two different power plants located in different regions may be combusting different kinds of coal. This usually means a difference in the amount of mercury emitted, which could be in terms of quantity as well as composition. Secondly, coal-fired power plants can be configured very differently in terms of the way coal is combusted. The back end of the unit is also very different in terms of types of equipment installed for capturing emissions of SO2, particulate matter and NOx.”
Power plants burning bituminous coal, which has a higher sulphur content, are prevalent in the eastern US, Chang notes. This type of plant is generally equipped with a NOx reduction system such as an SCR. Depending on the age of the unit, some will have ESPs or, if built later or retrofitted, a pulse jet fabric filter (PJFF) to reduce particulate emissions from the flue gas stream, followed by a FGD system. Wet FGD is the most typical, Chang says.
When injected into the flue gas, PAC captures mercury in the pores of the carbon particles, he explains. Collection usually takes place within the ESP or the PJFF as well as within the wet FGD system, where water sprays collect it in the by-product area.
“This is a commonly used approach to mercury reduction,” says Chang. “However, there may be other approaches within this kind of configuration where PAC could be avoided or its consumption reduced” through co-benefit. “This happens when you have an SCR which has a catalyst system that will help oxidize mercury, and then the oxidized mercury can be captured in the wet FGD system,” he explains.
For the low-sulphur coal that comes from the western US, a typical power plant could be configured with a boiler, NOx reduction system, SCR, then a dry FGD system paired with a PJFF to collect particulate matter as well as by-product from the SO2 removal process. The primary mercury removal method for these plants is PAC. For these plants, Chang says, “due to the composition of the coal, the forms of mercury are usually less oxidized so you always need to consider a halogenated form of PAC where the halogens help promote a reaction that converts it to oxidized mercury to improve the capture rate.” For a lignite-fired plant, he notes, the optimal mercury compliance solution would be equivalent to this US example.
B&W’s Gadgil concurs that existing equipment installed at a plant can affect technology choices. “For example,” he says, “if the only air quality control equipment a plant has is an ESP for particulate control, even if there is a high degree of mercury oxidation, the plant will still need PAC or some other kind of sorbent. So you still need to install a carbon injection system and a halogen injection system – but instead of two systems, why not use brominated carbon? One system is better than two, and you can get the same effect as a bromine system and some kind of sorbent.
“The same goes for a baghouse as well. If you have SCR or FGD such as a circulating dry scrubber, then you might not need to use carbon at all. You may have enough high oxidation of mercury either with SCR or halogen addition to coal, so it can be removed almost 100 per cent by FGD equipment. This will save a lot of money on capital costs, and to a certain extent on operating costs as well.”
Chang notes that the capital cost is less intensive for mercury emissions reduction than for other pollutants. “Activated carbon is less capital-intensive than a wet FGD or SCR system,” he says – but this is then balanced by operating costs “because you have to buy activated carbon from a vendor and [the cost of] injection is considerable.” When selecting mercury removal technology, he advises that plant operators take into consideration both the capital and operating cost, including lifecycle costs, in order to “make sure they’re not spending a lot of capital on a unit that won’t have 20 years of remaining operation”.
Heinz concurs: “The main driver for total cost of operation of mercury reduction systems is the ongoing OPEX – mainly the cost of sorbents. The CAPEX for installations is a secondary driver,” he says.
When to implement?
Should plant operators wait until they are within the compliance period to purchase new mercury control equipment, or begin before the legislation comes into force?
Alstom’s Grubbstrom says, “Those customers that have a large fleet need to look into the various options right now in order to spread out the investment. We have already had contact with customers – some larger utilities, for example – that would like to discuss it, even if it will be one year until the [BREF] is published and then [they can] take four more years [to upgrade].”
What does the upgrade involve, and how easy is it? Alstom’s Heinz says his firm’s technology is designed for upgrading existing plants. “We can implement it in the existing environment [as it is] not very space-consuming. Especially when the customer is currently on the way to implementing retrofit measures to improve the plant’s performance, then he already has to consider the necessary steps for reduced mercury emission so as not to be in a position two years after a retrofit to start the next steps.”
B&V’s Chang says: “When you implement a compliance solution you have to take into account other anticipated future rules. We want to make sure our clients invest in a solution which will remain part of the overall compliance scheme in future.”
Current technology can remove around 90 per cent of the mercury emitted during the coal combustion process. Can this figure be improved – and could it ever reach 100 per cent?
MHPSE’s Volmer says that, from a technology perspective, “I cannot say 100 per cent – I can say 99.999 per cent (just joking). It’s a question between the possible technology and investment in its implementation,” he explains. “If [power plant operators] have to comply [with standards], they have to invest or close down the plant. Reaching 99.99 per cent is possible, but it also has to be economically feasible. The operator may not want 99.99 per cent mercury removal technology.”
Michael Wende, Process Engineering & Design AQCS with MHPSE, adds: “With the technologies required to cope with the regulations coming into force in 2016-17, a highly sophisticated standard for mercury removal will already be reached. In addition, the BREF revision in an eight-year cycle will be the driving force for additional efforts to improve mitigation technologies.”
Emissions rules drive technology R&D
Credit: Babcock & Wilcox
Volmer says his firm is working on a different composition of their product for different coal applications, aiming to increase the removal efficiency of mercury in the wet FGD system. “Our goal is not to build new equipment for modernization,” he notes. “We want to improve existing equipment, which is more cost-effective for the operator. Our improved technology can reach up to 90 per cent. But this always depends on the incoming mercury in coal, and on the requested emissions values. The lower emissions values are necessary – they are the incentive for all technology improvement.”
Wende adds that high US and European standards represent an impetus for continuous improvement in emissions reduction technology and optimized emissions mitigation in these regions. “However,” he adds, “from a global point of view, one of the next required steps for emission reduction is to focus on the implementation of the applicable flue gas cleaning technologies in countries and regions with less stringent standards.” For this purpose, he says “a huge portfolio of effective technologies is available.”
* Alstom’s Energy sectors are in the process of being acquired by GE as PEi goes to press