Looking for a Good Scrubbing: Today’s FGD Technology

Issue 9 and Volume 109.

Today’s FGD provides better performance and broader flexibility than ever before – and delivers it in a smaller, more dependable package.

By: Steve Blankinship, Associate Editor

It’s a good time to be in the flue gas desulfurization (FGD) business. Two-thirds of the existing U.S. coal fleet is not equipped with FGD (scrubbers). New emission standards for the control of sulfur and nitrous oxides, particulate matter and mercury – many of which do not stem directly from the Clear Air Interstate Rule (CAIR) or Clean Air Mercury Rule (CAMR) – mean most of the unscrubbed portion of the coal fleet will be adding scrubbers.

Several factors are driving the rush to scrub. They include a higher-priced SO2 allowance market (allowances have now reached $700/ton) and a desire to extend the life of old coal plants because of rising natural gas prices. Plant owners also with to acquire the ability to use alternate fuels with higher sulfur content.

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FGD vendors across the board report that local emission regulations often trump limits set by CAIR and CAMR in driving the booming scrubber market.

“If you look at North Carolina and Massachusetts with their stringent emission regulations, you see the drivers for upgrading or enhancing their air pollution control equipment, whether it’s scrubbers, fabric filters, or precipitators,” says Mike Sandell, vice president of technology for Wheelabrator Air Pollution Control (WAPC). “The Massachusetts mercury regulation is fairly aggressive, and goes beyond what can be achieved with just wet scrubbing without some form of mechanical or chemical enhancement.” What’s important to note, he says, is that wet scrubbers allow utilities more flexibility in fuel selection. “Many of the requests for proposals we are seeing are for coals with sulfur content that are fairly wide ranging, with some including a percentage of pet coke,” says Sandell.

They Don’t Make ‘Em Like They Used To

FGD systems have evolved dramatically since the late 1970s. Early systems were so prone to operational problems that power plant output often had to be curtailed to stay in compliance with emission limits. That’s no longer true. Today’s FGD systems possess the flexibility and design redundancies to cope and comply – and do so within a far smaller footprint than achievable decades ago when the first FGD system were deployed.

Reliability is so high that redundant towers are no longer needed. Today, vendors are able to supply absorber towers that stay online all the time. The redundancy is in the mechanical equipment and support systems outside the tower, all of which is easily accessible and can be maintained while the absorber stays online.

One of the more complex elements of compliance is the array of measurement standards demanded by federal and state permits. “We design our FGD systems with redundancy to meet annual average SO2 measured in tons per year, or to allow compliance if a plant has to report on a 24-hour rolling average or on a 3-hour average,” says Tony Licata, director of customer relations for Babcock Power Environmental (BPE). “Differing requirements like that require a totally different approach to redundancy. FGD systems must be flexible. There’s a big difference on how you design the system to meet a 24-hour average versus an annual average. So you oversize pumps and have extra pumps that kick in if you lose one.”

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Utility and industrial boilers near coastlines can use the alkalinity in seawater to scrub SO2 from flue gases. The volumes of seawater used accomplish scrubbing goals without reagent chemicals, and in most cases, seawater use is considered safe for return to the ocean. Hence the operating costs of seawater FGD are considerably lower than a limestone FGD. Ducon has secured contracts for seawater FGD projects for a 575 MW heavy oil unit in Jeddah, Saudi Arabia and two 250 MW coal-fired units operated by Reliance Energy in India. Both projects are under construction and are designed to achieve more than 90 percent sulfur dioxide removal efficiency without the addition of any chemicals. A precipitator removes particulates and a quench spray at the scrubber inlet cools the flue gas. Seawater is added counter current into the scrubber. When the SO2 enters the scrubbing water liquid phase, chemical mechanisms capture it. The acidic scrubber discharge water is oxidized and neutralized prior to being returned to the environment. Illustration courtesy of Ducon Technologies.

In order to meet Federal and local reporting requirements along with client requirements for high availability, Hitachi Power Systems America provides its open spray tower FGD system, developed to meet stringent Japanese regulations that require instantaneous plant shutdown the moment an emission excursion is detected. The company reports that availabilities of greater than 99 percent are common with Hitachi systems. Redundancy is applied primarily to driven equipment, consistent with U.S. utility standards.

More Features in a Smaller Package

Whether designed for new coal plants or retrofitting existing units, modern FGD units provide increased redundancy, reliability and versatility in much smaller packages than earlier generations. Today, single absorber modules can support units of 1,000 MW or even larger. Spare absorber recycle pumps and spray levels – if applicable – are standard. For support system equipment such as limestone grinding mills and dewatering vacuum filters, a standby spare unit is generally included in the design.

“Years ago an 800 MW unit would have three towers,” says Licata. “Today we build one tower for a unit like that.” We can build single towers to handle up to about 1,000 MW and we have a design for an 1,100 MW single tower. The advantage is a smaller footprint, lower capital cost, lower maintenance cost.” Hitachi has provided systems in which one absorber tower serves up to five boiler units.

Two of the more common absorber configurations that have evolved from the early designs are the open spray chamber absorber and the dual flow tray absorber. The open spray tower contains a series of spray levels inside the open spray tower. The flue gas enters the absorber, turns 90 degrees and passes through an absorption zone where thousands of gallons per minute of slurry are sprayed to saturate the flue gas and remove the SO2. A dual flow tray absorber is designed to allow the flue gas to flow through perforations of the trays. The flue gas flow through the perforations restricts the flow of slurry, causing a froth to collect on the trays. The flue gas intimately contacts with the slurry as it bubbles through the tray, efficiently removing the SO2.

Wheelabrator’s Dual Flow Tray wet FGD installation on Tampa Electric’s Big Bend Units 1 and 2 represents the largest operating generating capacity served by a single absorber tower in the United States. The high velocity dual flow tray absorber uses a limestone forced oxidation system equipped with dibasic acid (DBA) to remove SO2 for the combined flue gas from the two 445 MW units. “The chemistry of today’s wet FGD systems is well enough understood that the scale and wall buildups of the first generation wet FGD systems no longer occur,” says Sandell. “The addition of forced oxidation – often retrofitted on early scrubber systems to allow scrubbers to provide wallboard-grade gypsum – has now become almost standard. Forced oxidation helps reduce scaling potential and other operational chemistry problems as well.”

Carl Weilert, principal air pollution control consultant for Burns & McDonnell, says single absorbers can be especially beneficial for units subject only to annual tonnage emission requirements such as the acid rain cap and trade program, even when the single absorber serves two units. He notes that Tampa Electric’s Big Bend Units 1 and 2 and Springfield Illinois’ CWLP Dallman Units 31 and 32 are examples of successful wet FGD retrofit projects in the United States utilizing such a configuration. Provisions for bypassing the FGD system during maintenance and scheduling of short joint outages of all units served by the common absorber are important to the success of this strategy.

Wet Vs. Dry

In choosing a wet or dry FGD system, Licata says the decision is ultimately driven by customer preference. Semi-dry is the more common term for dry scrubbers since all FGD systems require water. Dry systems require somewhat less water to operate, but still consume 60 to 70 percent of what a wet system does. In terms of capital expenditure, a semi-dry system might cost about 60 percent of what a wet system costs, but it may represent four times the operating cost of a wet system. That’s because of the cost of the sorbents needed to operate the systems. Lime, used in semi-dry systems, sells for $80/ton, while limestone sells for $15/ton.

A wet system has greater power requirements and more motors than a semi-dry system. While today’s wet systems can serve units up to 1,000 MW using a single absorber tower, a semi-dry system will require multiple towers for the same size unit. The maximum that can be served by a semi-dry tower is 250 to 350 MW. Additionally, most semi-dry systems are limited to 94 to 95 percent SO2 removal whereas wet systems can achieve up to 99 percent removal. Semi-dry FGD, therefore, might be less desirable if lots of high sulfur coal is used.

Weilert points out that a semi-dry FGD system is more limited due to the inherent size limitation of the absorber tower. “Semi-dry requires multiple absorber modules for unit sizes larger than around 350 MW,” he says. “Some technology suppliers offer arrangements featuring multiple rotary atomizers per spray dryer absorber. When this configuration is used, it is possible to design the system to maintain performance at full load with one atomizer out of service.”

Babcock Power Environmental’s wet flue gas desulfurization installation at Vectren’s F.B. Cully plant was the first instance where a plant was configured with the flue gas from two boilers entering a single absorber. Reagent preparation, absorption and gypsum dewatering are integrated into a single 3-story building on a 1-acre site. The WFGD has not caused a boiler shutdown since it went into operation in 1994. Photo courtesy of Babcock Power Environmental.
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He notes, however, that this configuration has not been commonly applied, since emission limitations for new units are most often expressed as 30-day rolling averages. “This allows the operator to compensate for the temporary reduction in performance during periodic atomizer change-out. As with wet FGD systems, reagent preparation equipment for semi-dry FGD is typically designed with a standby spare unit.”

However, says Weilert, even semi-dry FGD processes can be configured for a single absorber to handle the gas flow from multiple units. Such a system is under construction now at Tri-Gen Syracuse Energy Corporation in Syracuse, NY. But if this configuration is used, the total capacity of all units served by the absorber would need to be less than 350 MW, he says.

“Conventional wisdom is that semi-dry scrubbing, with its lower capital costs and higher operating costs, is favored for lower sulfur fuels because it can only remove SO2 in the 90 to 95 percent range, and for smaller units with shorter remaining life expectancies,” says Phil Rader, business applications manager for ALSTOM Power. “Conversely, wet scrubbing is more preferred at high sulfur, big units that will be around for a long time and can remove SO2 at the 97 to 98 percent range.”

Sean Black, marketing manager of North America environmental control systems for ALSTOM Power, estimates that the market is currently running about 60-40 in favor of wet. “In terms of dollars/kW or dollars/ton of SO2 removed, you get your biggest bang for the buck on large, high sulfur units. The big fleets like Southern and AEP are looking at credits and long term emissions. They are focusing on the big units and the high sulfur units,” says Black. “That tends to play to the strength of the wet scrubbers.”

After all the big, high sulfur units get scrubbers, however, there could be a flurry of orders for smaller units – perhaps in the 120 MW range – that have lower capacity factors and shorter life expectancies. “Those could be perfect applications for alternate technologies like our SDA flash dry absorber,” he says.

Mercury Removal

While most wet FGD systems have demonstrated the ability to remove oxidized forms of mercury at 80 to 90 percent efficiency, none can remove an appreciable amount of elemental mercury. “This causes the overall mercury removal achievable in the FGD system to be reduced as a function of the fraction of the total mercury that exists in the elemental form,” says Weilert. “Therefore, the focus has been on methods to enhance the degree of oxidation of mercury that takes place upstream of the FGD system.”

One aspect of mercury capture that has received attention with regard to FGD system design, he says, is the extent to which captured oxidized mercury is reduced back to elemental mercury and re-emitted from the FGD process. “In some cases, chemical additives may be able to reduce this re-emission phenomenon. Some FGD systems will likely include equipment to allow injection of these chemical additives.”

Particulates and SO3

A retrofit wet FGD system will likely result in some particulate removal, says Weilert. “The extent of removal that occurs will be a function of the particulate loading at the inlet to the FGD, the particle size distribution, and the type of absorber used. The potential for particulate removal from FGD is estimated at 50 percent to 80 percent.” He cautions, however, that many vendors may not provide guarantees for this level of particulate removal.

Licata says that particulate removal by a wet scrubber can sometimes help avoid the cost of upgrading an existing ESP. “For example, if you decide to produce wallboard grade gypsum, you have to add cleaning equipment to prevent contamination of the gypsum. So this creates the potential for enhanced particulate removal by the scrubber. This involves the design and placement of nozzles and wall baffles.” He says BPE has done so on a number of retrofit projects.

The Hitachi FGD system’s absorber tower at the Tachibanawan Power Station in Japan serves 1,050 MW and has been in operation since 2000. The company has a plan for a tower than can handle up to 1,300 MW. Photo courtesy of Hitachi Power Systems America.
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FGD suppliers also note an up-tick in interest for controlling SO3 emissions. “We are seeing more requirements for emission limits for SO3/sulfuric acid,” says Sandell. He explains that the increased use of selective catalytic reduction (SCR) systems increase the oxidation of SO2 to form sulfuric acid. “Increasing SO3 in stack emissions may present a visibility problem at the exit of the stack,” he says. “In some locations where there are issues with visibility and haze, we are being asked if our systems can remove it. We are receiving requests for incorporating a wet electrostatic precipitator downstream of the scrubber. Wet ESPs collect sulfuric acid mist very well.”

While SO3 may be a gas at flue gas temperatures, once the flue gas cools in either a wet or dry scrubber, it condenses as very fine sub-micron droplets. The droplets are so small that they may not be effectively collected by conventional wet scrubbers for regulatory purposes. The droplets refract light in the visible range and resemble a bluish haze. Wet scrubbers equipped with wet ESPs can mitigate the problem. For a dry scrubbing system, the residual lime captured in the baghouses can remove a major portion of the SO3.

Impact on CUBs

Each year, the U.S. power industry produces more than 120 million tons of coal utilization byproducts (CUBs), which consists of fly ash, boiler ash and the sludge produced by FGD systems. Today, about 30 percent of the CUBs produced by U.S. coal plants are used in commercial applications, reducing the need for burial in landfills, and the Department of Energy wants the percentage to grow to 50 percent by 2010. It is hoped that increased mercury capture by FGD systems will not jeopardize markets for scrubber-produced gypsum.

Plant operators generally decide whether or not to produce wallboard-grade gypsum based on the plant’s proximity to a market for wallboard. In some cases, systems are designed to produce lesser quality gypsum, which is still suitable for use by the cement industry, or for other uses, including landfill stabilization. All systems use forced oxidation that adds oxygen to the SO2 to make SO3. “If you produce cement industry grade gypsum, it goes directly to the cement plant and is a little easier to produce than wallboard,” says Licata. To get the whiteness and purity required for wallboard grade requires some purification along with washing and separation. “If you don’t currently have a market for wallboard gypsum, we leave the space so if a wallboard market evolves in the future that extra equipment can be added.”

So far as concerns about the mercury uptake into commercial byproduct applications, Licata notes that between 1984 and 1990, every coal-fired power plant in Germany was retrofitted with scrubbers. “Every power plant in Germany makes wallboard grade quality gypsum, and every pound of gypsum produced is sold because it’s the law. Landfilling of byproducts is not allowed. So they have 15 or 20 years of experience. The systems used there capture as much mercury as the units here do. And they sell all the byproducts.”

Hitachi’s experience is similar since Japan also forbids placing coal plant byproducts in landfills. Every system Hitachi makes produces wallboard grade gypsum. The company notes that although it is common practice in the United States to use both primary and secondary dewatering when producing wallboard grade gypsum, Hitachi eliminates its primary dewatering because its FGD absorber operates at more than 20 percent solids as compared to typical FGD systems that operate between 10 and 15 percent solids.