|Babcock Power recently completed an installation of its Turbosorp CDS at the Deerhaven Unit #2 Power Plant in Gainesville, Fla. owned by Gainesville Regional Utilities. Photo courtesy Babcock Power.|
By Lindsay Morris, Associate Editor
When it comes to emissions control, fossil-fired facilities are facing one of the biggest hurdles in U.S. history – a hurdle that must be cleared swiftly and seamlessly. The emission types slated to be controlled by U.S. Environmental Protection Agency (EPA) regulations are numerous, but the EPA's ruling to reduce mercury emissions will be the first federal limitation of mercury emissions if it goes into effect as scheduled in 2015. As with any new regulations, the mercury regulations come with a big compliance price tag. EPA's Mercury and Air Toxics Standards (MATS) are expected to cost the industry as much as $10 billion.
The hazardous air pollutants (HAPs) to be controlled by MATS include mercury, lead, arsenic, hydrogen chloride (HCl), hydrogen fluoride (HF), dioxins/furans and other toxic substances identified by Congress in the 1990 amendments to the Clean Air Act (CAA). The rule establishes "maximum achievable control technology" (MACT) limits for new and existing coal and oil-fired facilities and has therefore been pegged with the nickname "Utility MACT."
EPA's attempts to limit mercury emissions started in the 1990s with the CAA, which provided that EPA must take several steps before regulating air toxics emissions such as mercury from power plants. In 1997, EPA analyzed mercury emissions from power plants and other industrial sources for the first time in a study prepared for Congress.
In 2005, EPA issued the Clean Air Mercury Rule (CAMR), which established "standards of performance" limiting mercury emissions from new and existing utilities and created a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two phases. However, on Feb. 8, 2008, a federal court ruled that EPA violated the CAA by trying to regulate mercury-emitting power plants through the CAMR. The court said EPA failed to make a specific health-based finding in relation to mercury. On March 16, 2011, EPA proposed the CAMR replacement: the MATS rule, and the rule was finalized on Dec. 21, 2011.
The finalized rule calls for a 90 percent removal of mercury by Jan. 1, 2015. This allows a compliance timeline of three years for most units. EPA has also provided for a one-year extension in some cases. Beyond that, EPA has provided that facilities which cannot comply within four years and are critical to electric system reliability may seek a further extension through an administrative order. EPA has also said that it will take comment from experts, including FERC, on applications for such further extensions.
Prior to the release of MATS, mercury control regulations enforced by 17 states already required 80 to 95 percent mercury capture rates. Power plants in many of these states are therefore already operating at mercury control rates that meet the reduction levels sought in MATS, according to the Northeast States for Coordinated Air Use Management (NESCAUM).
In the study "Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired Power Plants," NESCAUM reports emissions controls that significantly reduce mercury emissions from coal-fired power plants have already been installed, demonstrated and put into operation at a "significant number of facilities in the U.S." As of March 2011, 25 units representing some 7,500 MW were using commercial technologies for mercury control, according to the report.
But a number of facilities still need to install mercury control devices, or newer, more stringent mercury controls. Through a recent survey entailing interviews with 55 power plant operators, The Associated Press found that MATS will cost the industry approximately $10 billion to implement. The EPA estimates the rule will cost industry $9.6 billion.
While a number of mercury control options exist, many utilities are worried about the small window of time they have to comply with mercury-related regulations, as well as other rules from the EPA slated at controlling emissions from power generating facilities.
"We're hearing from policymakers that they believe the rules will be effective at cleaning pollutants up, but the compliance dates are extremely tight," said Kevin Crapsey, vice president of corporate strategy and development at Eco Power Solutions, a manufacturer of multipollutant control systems. Most utilities would be more comfortable with the compliance timeline if 60 to 72 months were allotted for compliance instead of just 36 months, he said.
Crapsey said a typical installation of a multipollutant control system on a larger unit could take up to 48 months, whereas smaller units usually take 18 to 30 months. However, Activated Carbon Injection (ACI) installations have been known to typically last only about a year from start to finish, since only mercury is targeted.
Rob Nebergall, global business manager for emissions control technologies at Norit, said that while activity was not particularly busy during 2011, activity is now "growing vastly based on MATS."
In order to consistently furnish the power industry with the mercury products it will need over the next few years, Nebergall said air quality control product manufacturers should establish greater supply chain assurance. Coal suppliers for the power industry have long established records of supply chain assurance, and Air Quality Control equipment manufacturers should follow suit, he said.
"We consider supply chain assurance to be key. We've invested a lot of capital resources into assuring that as demand rises, we have the optimal supply chain, which includes nine lines of production and strategic distribution terminals."
Methods of control
Mercury-specific control technologies include ACI, halogen addition, and various co-benefit methods of control, such as particulate matter (PM) controls, dry sorbent injection (DSI), and dry and wet scrubbers (see Fig. 1).
ACI is essentially the injection of powdered activated carbon. The injected carbon is then captured using a downstream PM capture device (an electrostatic precipitator (ESP) or a baghouse). An ACI system is usually relatively simple and cost-effective, and consists of storage equipment, a pneumatic conveying system and injection hardware.
ACI systems cost approximately $5/kW and can be installed in 12 months or less, according to NESCAUM.
"ACI has a very low capital cost of implementation. For most, it's the lowest cost technology to get the most mercury out," said Nebergall.
Nebergall also said that older plants may be more likely to install ACI than other control technologies for mercury. "ACI tends to be a much lower capital investment than other treatments, so older plants are much more likely to install ACI.
An ACI installation could run as low as $1 million, whereas other mercury control technologies could run anywhere from $50 million to $100 million, Nebergall said.
ACI is typically effective at removing mercury unless high sulfur coals are used, or SO3 is injected for flue gas conditioning for ESPs. SO3 interferes with mercury capture by ACI; however, upstream capture of SO3 by dry sorbent injection (DSI) can enable ACI to more effectively capture mercury. ACI can also be used to reduce other HAPs, such as dioxins and furans.
Two main types of activated carbon are used for mercury control – plain powdered activated carbon (PAC) and brominated PAC. The use of plain PAC for mercury control actually started in the incinerator industry, said Ron Landreth, manager customer technical service, environmental division for Albemarle. However, plain PAC did not work well in a variety of other applications, including utility boilers. Brominated PAC has been found to work well at higher temperatures and lower mercury and hydrogen chloride (HCl) levels, though, Landreth said. However, brominated PAC is typically more expensive than plain PAC.
In recent years, bromine compounds have been used to oxidize mercury in the flue gas. Previously, high levels of mercury oxidation had been achieved, but mercury still had to be captured, Landreth said. In systems with wet scrubbers, the oxidized mercury could be captured in the scrubber liquid. However, elemental mercury is not water soluble, meaning it could not be captured by a scrubber, he said. This has led to the injection of PAC (either plain or brominated) in front of the scrubber or upstream particulate control device, which results in a greater capture rate of oxidized mercury, he said.
In low chlorine coal cases, halogen addition can be used to enhance the mercury removal process. However, downsides exist to adding halogens, said Anand Mahabaleshwarkar, senior project manager for Kiewit. "Halogen addition in coal is not well-controlled; not a well-monitored process. It can increase the corrosion potential in duct work or air heaters and downstream AQC equipment."
Many technologies provide co-benefit methods of control for mercury. Baghouses (or fabric filters) typically provide a higher co-benefit mercury capture than ESPs. According to data collected by the EPA during its information gathering period for the development of MATS, bituminous coal-fired boilers with baghouses have among the highest rates of mercury capture.
"Power plants equipped with baghouses can use ACI more efficiently than those not equipped with baghouses," Nebergall said.
Wet scrubbers with SCR controls upstream have also proven to be effective at removing oxidized mercury. Since eastern bituminous coals have higher levels of chloride, a wet scrubber is preferable for removing oxidized mercury, said Brandy Johnson, manager of FGD project development at Babcock & Wilcox.
One downside to this option is that a wet scrubber will take mercury emissions out of the air, but can leave mercury emissions in water, said Carl Weilert, principal air pollution control engineer at Burns & McDonnell. The most direct way to eliminate mercury in wastewater would be to eliminate the wastewater discharge completely by choosing a dry scrubber instead.
Plants that only have an ESP may find it challenging to meet MATS compliance, Mahabaleshwarkar said, because "ESPs remove limited mercury and HCl even with carbon/sorbent injection."
A plant that has an ESP and a wet scrubber installed will be likely to meet compliance, and a plant with a dry scrubber and fabric filter will almost certainly meet compliance, he said.
"Currently, more than 50 to 60 percent of coal-fired power plants have only ESPs installed," Mahabaleshwarkar said. With this in mind, fabric filter retrofits may become higher in demand than ESPs, since they are capable of removing more emissions, such as mercury, HCl and PM.
The addition of a co-benefit method like a wet scrubber or SCR can help remove oxidized mercury in medium to high sulfur content coals with chlorine present, Mahabaleshwarkar said.
When EPA issued the MATS rule at the end of last year, engineers and technicians at Birmingham-based Southern Research, a not-for-profit 501(c)(3) scientific research organization, were already working with industry to respond to the dictates of the new rule. At Southern Research's pilot-scale testing facilities, concentrations of mercury, trace elements, hydrogen chloride and fine particles are measured to determine the level of control achieved from various emissions control technologies.
Bob Dahlin, director of the Power Systems and Environmental Research Department, said that a number of variables affect the removal of mercury – including the presence of HCl, hydrogen bromide, chlorine and SO3, as well as the temperature of the flue gas. Aside from these variables, Southern Research has also found that injecting activated carbon at different locations can prove to be effective. However, it is not always possible to inject the activated carbon at the optimum temperature at a full-scale plant. "You can't always put the injection point exactly where you want it," he said.
Southern Research's testing has proven that certain co-benefit technologies will help mercury capture more than others. If a scrubber is already installed, for example, it might make more sense to oxidize the mercury so it can be captured in the scrubber, he said. For plants already equipped with FGDs, the most effective mercury capture enhancement method that Southern Research has found is to inject bromine, which will oxidize the mercury. Once the mercury is oxidized, it can then be captured in a scrubber.
Southern Research is developing a process in which bromine is generated in situ and injected directly into the flue gas. "We think the advantage is you don't have to put it through the boiler because there is potential that putting bromine through the boiler could cause corrosion long-term. The in-situ bromine generation technology also allows you to put the bromine exactly where it is needed."
Southern Research is currently conducting a pilot demonstration for mercury and HCl removal from high sulfur coal flue gas at a full-scale power plant owned by Southern Co. Dahlin said demonstrations such as this one are conducted using a variety of mercury measurement methods, including mercury sampling by EPA's Method 30B (carbon traps) and Method 30A (CEMS) using thermo systems that provide a continuous measure of mercury concentration. "We always like to make mercury measurements by two different techniques, because we've been fooled if we only use one type of measurement."
Due to state and local mercury requirements, air quality control systems to limit mercury emissions have been installed in small doses at generators over the last couple decades. However, mercury controls are becoming increasingly popular due to the requirements of the Utility MACT rule. The following are a few of the many solutions on the market for controlling mercury emissions.
Nalco's MerControl 7895 technology functions by increasing the oxidized mercury fraction in the flue gas, which facilitates its capture. The oxidized form of mercury is then more readily collected in conventional devices such as ESPs and fabric filters. Also, for utilities trying to minimize activated carbon injection rates to maintain fly ash quality for concrete manufacture, the use of MerControl 7895 can reduce the carbon injection rates to a level resulting in negligible impact to fly ash quality. Barring the presence of mercury re-emission, for units equipped with a wet FGD, increased mercury oxidation rates from the application of MerControl 7895 should result in equivalent increase in mercury removal, said John Meier, product line manager for mercury control solutions at Nalco.
Application of MerControl 7895 can potentially eliminate the need for ACI, Meier said, depending on the mercury emission reduction required. Although the use of fuel additives have been thought to typically benefit western fuels with low chlorine, Nalco has successfully demonstrated benefits of MerControl 7895 application fuels with as high as 1,400 ppmw chlorine in the fuel, or bituminous coals, Meier said. If the oxidized mercury is being reduced across the wet FGD and limiting mercury capture rates, a phenomenon known as mercury re-emission, Nalco's MerControl 8034 can be applied with or without the application of MerControl 7895 to eliminate re-emission and decrease stack emissions.
In December 2010, Nalco conducted a demonstration of its mercury control method at a 580 MWg boiler burning subbituminous Powder River Basin (PRB) coal (See Fig. 1). Prior to Nalco's participation, mercury emissions were controlled to a target of less than 1.0 lb/TBtu by the injection of halogenated powdered activated carbon (HPAC) alone. By injecting a small amount of MerControl 7895, the utility was able to reduce its activated carbon consumption rates while maintaining the target emission rate of 1 lb/TBtu. The end result of the MerControl 7895 installation was a reduction of annual mercury compliance by over $1.1 million per year compared to the previous control strategy of halogenated activated carbon alone.
|The Mt. Tom Power Plant near Holyoke, Mass. is equipped with the Turbosorp CDS from Babcock Power, which limits multipollutants including mercury. Photo courtesy Babcock Power.|
Albemarle is a manufacturer of bromine and bromine chemicals, which are used in the capture of mercury oxidation. The company holds the patent on gas-phase bromination and also provides several gas-phase brominated PACs, said Will Pickrell, global business director, environmental division. These products include B-PAC for applications in which the primary operating temperature is below 550°F, H-PAC for temperatures up to 800°F and C-PAC, the concrete-friendly sorbent, in which both mercury control and preservation of fly ash or cement kiln dust sales are required.
Norit's ACI technology, the Darco Hg line, has proven 80 to 95 percent removal of mercury. "One of the more recent installations we've been involved with reached 95 plus percent removal rates at far below historical rates of dollars per pound of mercury removed," said Nebergall.
Recent trials have demonstrated that the newest product, Darco Hg-LH Extra, is able to reduce activated carbon usage by 20 to 50 percent over standard halogenated carbons in challenging environments. Darco Hg-LH Extra has also proven an improved tolerance for the presence of SO3 in flue gas, removing up to 90 percent mercury from the flue gas in the presence of 6.5 ppm SO3 at an injection rate of 5 lb/MMacf.
Norit has recently been a part of field trials conducted at two coal-fired power plants in Illinois. For confidentiality, the identity of the plants will be referred to as Plant A and Plant B. Plant A is a 300 to 500 MW plant burning Powder River Basin (PRB) coal with an ESP. Darco Hg-LH Extra and Darco Hg-LH (the test standard) were injected into the flue gas stream downstream of the air preheater for eight to 10 days each while varying injection rates. These results revealed that Plant A could potentially reduce carbon usage by as much as 20 percent using Darco Hg-LH Extra when the mercury removal target is 90 percent (see Figure 2).
Plant B is a multi-unit, 1,000 MW plant burning PRB coal with ESPs installed on two test units. ACI testing was conducted on both units during a 10-week period. At 5 and 8 ppm SO3, Darco Hg-LH Extra exhibited 3.5 and 5 percentage point increases in mercury removal efficiency. At 5 ppm SO3, this product achieved 95 percent mercury removal. At 8 ppm SO3, Darco Hg-LH Extra achieved approximately 86.5 percent mercury removal, whereas the test standard achieved 81.5 percent mercury removal (see Figure 3).
Aside from traditional mercury solutions, a number of co-benefit methods for mercury control exist, including dry sorbent injection (DSI), dry and wet scrubbers and multi-pollutant control systems.
Babcock Power manufactures a circulating dry scrubber (CDS) for the purpose of multipollutant control, which includes increasing mercury capture. The product, Turbosorp CDS, has been tested for mercury control on bituminous coals, said Tony Licata, vice president. "Based on the individual coal, we're seeing that without carbon injection, we've ranged from 80 to 99 percent removal." When carbon injection is added, however, removal rates are at 98 to 99 percent.
Figure 4 displays the results of a Turbosorp CDS installation at four power stations – three of which were measured for mercury removal after an installation of TurboSorp CDS. Power stations 1 and 3 tested below the Utility MACT required limits for existing units, demonstrating 95 percent mercury removal. No activated carbon was injected at these units to gain these results. The mercury emissions at power station 4 without carbon injection, however, were slightly above the limit allowed by Utility MATS but within current permit limits. Babcock Power is continuing to study mercury removal at this station and is confident that with carbon addition they can meet the MATS limits. Mercury testing at Plant 2 was not part of the contract, so no testing was done.
The technology produced by Eco Power Solutions, Comply 2000, is a multi-pollutant removal system that reduces SO2 emissions through injecting a fogging spray mixed with a hydrogen peroxide solution that is condensed concurrently with other emissions over coils to remove all combustion emissions from the exhaust gas stream. This process converts NOX and SO2 to nitric and sulfuric acid in the wastewater stream, resulting in removal of SO2, mercury, halogens including fluoride, chlorine and bromide, heavy metals include arsenic and cadmium, 2.5 and 10-micron PM, as well as 20 percent removal of CO2.
Crapsey of Eco Power Solutions said mercury removal rates are above 95 percent on Eastern bituminous coals.
Comply 2000 also achieves 98 to 99 percent SOX and NOX removal, 95 percent acid gas removal and 60 percent CO2 removal.
While a multi-pollutant control solution is more expensive than a single emission removal technology, Crapsey said it is able to control emissions at the required rate for all of the regulations currently proposed or finalized, and it also addresses potential future requirements for carbon capture.
"If the U.S. government or anybody else imposes any more carbon regulations, we've got a product that answers that question too," said Crapsey.
While a number of technologies for mercury control exist, it will be up to each power plant to decide how retrofits should be handled.
Even though federal mercury regulations have been postponed time and time again over the last three decades, utilities should not expect that the current mercury regulations will face any challenges in court.
Since most plants face a MATS compliance deadline in less than three years, decisions should be made sooner rather than later.
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