The emission of acid gases from power plant and boiler combustion is a major threat to human, animal and plant life, and the environment. Acid gases such as sulfur dioxide (SO2) or hydrogen sulfide may effect ecosystems through acid rain or dry deposition. “Some acidic lakes have no fish,” states the EPA. “Even if a species of fish or animal can tolerate moderately acidic water, the animals or plants it eats might not.” Areas effected by acid rain may be visually identifiable by the presence of dead or dying trees. Acid rain leaches aluminum from the soil, which may be harmful to plants and animals. Acid rain also removes minerals and nutrients from the soil that trees need to grow, according to EPA. “At high elevations, acidic fog and clouds might strip nutrients from trees’ foliage, leaving them with brown or dead leaves and needles,” the agency states. “The trees are then less able to absorb sunlight, which makes them weak and less able to withstand freezing temperatures.” Mitch Lund, a technical services engineer at Nol-Tec Systems, a process engineering company with a focus on bulk material handling and acid gas control, says the term “acid gas” is a generic chemical description for any gaseous mixture containing acid-based compounds. “If present in high enough concentrations and inhaled, acid gases can be harmful to life—specifically by breaking down respiratory and skin cells,” Lund says. “Additionally, when acid gas is released into the atmosphere, it combines with moisture to form acid rain.”  This is a problem for biomass, Lund says, because burning fuel for power or steam generation creates acid gases in the combustion process. “Fuel has sulfur- and nitrogen-based compounds that, when burned, form gaseous SOx and NOx compounds that are the basis for acid gases,” he says. SOx and NOx are sulfur and nitrogen oxides, respectively. “Plants absorb minerals from the earth in which they grow, and some plants—citrus trees in particular—absorb more chlorine than others,” says Link Landers, an engineer with PPC Industries, a company focusing on pollution control that, in 1988, developed an acid control system using dry sorbent injection (DSI). “And some plants absorb more sulfur than others.”  Because acid gases are hazardous to human health and the environment, they are regulated by local, state and federal agencies. “Recently, acid gas regulation has been driven at the federal level, while working closely with states to enact implementation plans designed to control local economic impact,” Lund says. “The roots of these federal regulations are based in the Clean Air Act of 1973 that gave the EPA power to control air pollution at a national level. Amendments to this ruling in the past 30 years have enforced the control of acid gases.” Landers notes that the National Ambient Air Quality Standards established six criteria pollutants. “In this, hazardous air pollutants (HAP) were established, and included in these are acid gases,” Landers says. “Specifically, the heart of the current regulations states that there cannot be more than 10 tons per year of any single HAP and no more than 25 tons per year of all HAPs combined.” Lund further explains that “recent acid gas rulings like the Mercury and Air Toxic Standards and the Industrial Boiler Maximum Achievable Control Technology set limits on how large boilers have to be in order to be deemed necessary to regulate,” he says. “Any coal- or oil-fired unit that sells electricity to the grid and is greater than 25 megawatts (MW) must comply with MATS. The IB MACT applies to any process boiler that has the potential to emit 10 tons per year of a regulated pollutant or 25 tons per year of any combination of pollutants. These federal rulings require each boiler to be evaluated on a case-by-case basis. Some companies are regulated on an overall facility fleet basis, but these are the exceptions, not the rule.” States are required to develop State Implementation Plans to carry out federal laws set forth by EPA. “The SIPs can be more restrictive than the federal law, but not more lax,” Landers says. Here is how one would calculate whether a power plant or a boiler for plant use—since the regulations do not differentiate between the two—would be subject to the IB MACT rule for one regulated pollutant: chlorine. “If we assume a 150 MMBtu-per-hour power plant utilizes a fuel that has 7,500 Btu per pound, and contains 0.01 percent of chlorine on a wet basis, then that is 20,000 pounds per hour of fuel and 2 pounds an hour of chlorine, which, if the plant operated 8,760 hours per year would yield 17,520 pounds, or 8.76 tons, per year,” Landers says. “This is below the annual limit. But, increasing the plant size to 200 MMBtu per hour would yield 11.7 tons per year of chlorine, thus requiring some type of control.” He says the big fear is that EPA may lower the HAPs limits from 10/25 to, for instance, 8/20. “The general trends in the industry show that as years pass, newer compounds are added to regulation laws and existing compounds come under tighter regulations,” Lund says. “In general, as technology and environmental awareness evolve, pollution control does, too.”  Options For SO2, sulfur trioxide (SO3) and hydrochloric acid (HCl) control, the most common solutions, according to Lund, are wet scrubbers and DSI systems. Landers says both types come in a variety of methodologies and configurations. Nol-Tec Systems has more than 70 permanent acid gas removal systems in place today, Lund says. “We have also placed more than 70 testing or leasing temporary systems over the past 10 years,” he says. “We have three systems that use biomass as their main fuel source, but we also have numerous sites that utilize some smaller percentage of biomass as a fuel. Our DSI systems are flexible to work with either biomass of any type, or more traditional fuel sources, such as coal.” Nol-Tec has provided DSI systems for acid gas control and activated carbon injection (ACI) systems for mercury control since the early 2000s. “We got into the industry based upon our experience pneumatically conveying dry powders,” Lund says, adding that Nol-Tec also provides wet scrubbers through its Lodge Cottrell division. Wet scrubbers work by passing the dirty gas through a liquid compound that is designed to react with the targeted acid gas for removal from the dirty stream. “On the wet side, there are packed tower scrubbers, venturi scrubbers, bubbling tray scrubbers, virtual tray scrubbers, also called spray scrubbers, which utilize cross flow, cocurrent and countercurrent flow methodologies,” Landers says. “These scrubbers can use a variety of bases to accomplish the acid-base reaction required to neutralize the acids.” Caustic seems to be the reagent of choice for smaller systems, says Ray Willingham, an engineer at PPC Industries. “Larger utility-scale systems commonly use limestone,” he says.  DSI systems inject a dry chemical sorbent, or powder, into the flue gas for the same targeted removal as wet scrubbers, Lund says, and both solutions—wet scrubbers and DSI systems—form byproducts that are separated from the process and must be properly disposed of. Landers says this powder can be milled, unmilled or evaporative.  “Trona or sodium bicarbonate are typically used in these systems,” Willingham says. “Milled and unmilled injection is accomplished by blowing the base into a reaction chamber or duct where random probability takes over,” Landers says. “An acid molecule must come in contact with the base molecule.” Willingham notes that two factors come into play here—particle numbers and surface area.  “The greater number of base molecules compared to acid molecules, the more likely the reaction will occur and the higher the removal,” Landers explains. “The smaller the particle size, the longer it will stay airborne,” Willingham says, adding that this leads to better mixing in the gas and thus a greater probability of the base particle coming in contact with the acid molecules. “Additionally,” he says, “the smaller the particle, the greater the surface area to volume ratio of the particles, and since the reaction requires contact between the base particle and the acid molecule, the combination of an increase in the particle numbers and the available surface area provides an improvement in the performance and removal efficiency of these systems.” Landers says this provides the basis of the argument for milled vs. unmilled injection. “Milled injection typically requires less raw material overall, thereby lowering the operating costs,” he says. For acid gas removal, PPC Industries, which has been at its current location in Longview, Texas, since 1967, offers milled DSI systems. “We were a precipitator-only company until 1988 when we developed acid control system using dry sorbent injection,” Landers says. “In 1995, we started producing biofilters for control of volatile organic compounds, and wet electrostatic precipitators. In 2007, we developed selective catalytic reduction units for NOx control and nonselective catalytic reduction units for carbon monoxide control.” PPC Industries has installed DSI systems at 16 locations with nine of them being biomass boilers. Those that are not biomass are glass production plants and incinerators.  Landers says evaporative systems utilize a combination of wet and dry scrubbers. “A slurry mixture is injected into a reaction chamber where the water portion flashes off leaving a fine powder—smaller than milled dry sorbent—that reacts with the acid gases,” he says.  These systems, according to Willingham, typically operate using limestone or slaked lime. Lund says a popular form of NOx removal is selective catalytic reduction, which involves injecting an ammonia-based material into a reactor that reacts with the NOx in flue gases to form the nontoxic compounds nitrogen and water. Acid gas clean-up in natural gas facilities vs. coal or biomass plants, for instance, focuses on NOx-based removal. “Combustion-based technologies like low NOx burners, flue gas recirculation, and selective noncatalytic reduction systems are commonly used to combat NOx emissions in natural gas facilities,” Lund says. “Biomass, however, has a very broad fuel base, so the options for acid gas control are wide-ranging. The fuel will determine the emissions, which determines control requirements and strategies.” Wet or Dry? The big difference between the two technologies—wet scrubbers and DSI systems—comes down to operating vs. capital costs, says Lund. “Wet scrubbers are very efficient technologies that have low operating costs,” he says, “but they require capital investments in the hundreds of millions of dollars. DSI systems are the exact opposite. They have low capital costs—typically $1 to $2 million per system—but they have relatively inefficient use of sorbent, causing high operating costs.” While Lund admits that Nol-Tec Systems’ expertise with wet scrubbers in the biomass industry is limited, he says if a utility plant were used as a case study, wet scrubbers are anywhere from 50 to 100 times the capital cost of a DSI system, but the operating costs of a DSI system are usually 5 to 10 times that of a wet scrubber. Willingham says dry systems tend to require less exotic metallurgy, a main reason for the lower capital costs. Lund says small units, or larger units with a short expected lifespan, are good candidates for DSI technology. “Biomass plants are usually small enough to always be good candidates for DSI,” he says. “Cost effectiveness is related to unit size and operating life.” He says the general cut off for these parameters is 10 years of operating life and 250 MW of capacity. “Anything lower than these, DSI becomes an attractive option,” Lund says. “Anything higher is generally leaning towards a wet scrubber. Exceptions exist on both sides so it is important for an end-user to consider the pros and cons in both technologies when making compliance strategy decisions. The end user needs to work with an experienced provider to ensure they are getting the system that best suits their particular needs.” Dry sorbent injection systems will have lower removal efficiencies than wet systems, according to Landers, but dry sorbent systems are easier to operate and maintain. “Wet systems also have the ability to create secondary pollutants,” he adds. “Specifically, a gas stream that contains SO3 will produce submicron sulfuric acid mist (H2SO4) at the point the gases enter the main scrubber area. This is due to the water molecules combining with the SO3 molecules. These submicron particles will then travel through the scrubber, since scrubbers cannot remove these submicron particles, and out through the stack. In this situation, a wet electrostatic precipitator must be placed after the precipitator to capture the sulfuric acid mist.” Landers also notes that dry sorbent and evaporative systems must also be followed by a particulate removal device such as a dry electrostatic precipitator or baghouse to remove the reacted sorbent. Landers says dry systems are easier and more economical for SO2 removal less than 80 percent and HCl removal less than 95 percent down to about 5 parts per million. “Wet systems have to deal with leaks, corrosion and salts,” he says. “Corrosion can be dealt with if the proper stainless steel is used. Common 304 and 316 varieties are not suited for long-term exposure to some acid gases. Salts are reduced by blowing down water to the wastewater treatment plant.” For dry systems, those that utilize milling have increased maintenance over those that do not mill, he says. And evaporative systems, due to their complexity, would have the most maintenance of all. “Having been in the air pollution control industry for more than 20 years manufacturing both wet and dry systems, I can say with all confidence that anytime a pollutant can be treated with a dry system, there is less maintenance required and the longer the equipment lasts,” Landers tells Biomass Magazine. “And in a world of ever-decreasing maintenance and capital budgets, these are extremely important considerations.” Lund says with recent regulations that drove DSI sales coming and going, Nol-Tec Systems recognized that first-generation DSI systems were ultimately not what end-users wanted. “We remained committed to continuous innovation and improvement,” he says. “That has allowed us to work with customers to come up with truly unique features in our systems, such as silo discharging, enhanced sorbent mixing, and improved sorbent dispersion.”  Pollution control is a necessary evil, Lund says. “It leads to a lot of tough decisions that no one enjoys making. Our No. 1 recommendation is to use vendors as resources. We are specialized experts that can reduce the overwhelming task of digging through all the necessary information and evaluation that comes with choosing the best compliance strategy.” Author: Ron Kotrba Senior Editor, Biomass Magazine 218-745-8347 [email protected]