Coal

Columbia Energy Center: An Evolving Coal-Fired Plant Keeps Pace with the Times

Issue 1 and Volume 120.

By Tim Miser, Associate Editor

Straddling five decades, the Columbia Energy Center (CEC) coal-fired power plant in Pardeeville, Wisconsin has weathered a few storms. The plant has evolved from its beginnings as one of the first plants in the country to burn low-BTU coal, through a seemingly endless string of environmental regulations, into an age of higher-efficiency generation. Thanks to multiple infrastructure installations and upgrades, the modern plant is stronger than ever and ready to provide power in an increasingly emissions-constrained world.

The Air Quality Control System Retrofit Project at the Columbia Energy Center is helping Alliant Energy and co-owners meet emissions standards today and decades into the future.

As one of the largest power plants in Wisconsin, the facility is jointly owned by Madison Gas and Electric, Wisconsin Public Service Corporation, and Wisconsin Power and Light Co., a subsidiary of Alliant Energy. Unit 1 of the plant was commissioned in 1975 with a capacity of 512 MW, at a cost of $150 million. Unit 2 followed in 1978 with a capacity of 511 MW and a price tag of $160 million.

PRB Coal

The CEC was one of the first coal-fired plants designed to burn low-BTU coal from the Powder River Basin (PRB). PRB coal is attractive because it is very inexpensive compared to coal mined farther east. Sourced from Wyoming and Montana, PRB coal has only 25 to 30 feet of overburden and can be strip-mined. Add to this the 150 feet of easily-accessible deposits waiting below, and it’s easy to see why PRB coal provides a competitive advantage over other coal deposits, which must be accessed via underground mines that might extend deeper than a mile, and which reward a mining operation with only three to six feet of deposits.

PRB coal does have a downside. It’s a low-BTU coal with relatively low energy density. This means more coal must be burned to realize a given return. Bob Newell, senior manager of strategic projects at Alliant Energy, has worked with the CEC since it was first commissioned. “Since PRB coal produces less BTUs when burned,” he explains, “the plant has to burn more of it.” Because of this, much of the material-handling equipment at the CEC had to be designed for this specific type of coal. This meant the coal-handling system at CEC had to be upsized. The reclaiming system, conveyors, and boilers also had to be larger, which in turn necessitated the use of more structural steel. Additionally, the electrostatic precipitators (ESP) at the plant had to be larger to handle the additional fly ash generated in the combustion process. “There were a number of balance-of-plant considerations to be made,” Newell says.

Little was known about the ash mineral analysis of PRB coal when the CEC began operation. “We’ve since learned that PRB coal contains a lot more lime in the unburnable ash than other coals do,” says Newell. “This is both good news and bad news. You can actually sell the fly ash as a replacement for Portland cement, so this provides another revenue stream. But the lime also causes slagging and fouling issues in the boiler, which we experienced in spades when both boilers were brand new.” Even though the boiler was upsized, Newell explains, it still wasn’t large enough. Because of its higher lime content, PRB coal is sticky at high temperatures. If the ash doesn’t have a chance to cool, it will accumulate on furnace walls in a process call slagging. These deposits can then fall off and damage equipment.

To combat this, the plant had to monitor its operations very closely and reduce load at night in order to cool the ash and shed the slagging. On some occasions, outages were required, during which time high-pressure water and explosives were used to clear the slagging. “Though there were incremental improvements over time,” Newell continues, “the plant essentially was forced to live with the slagging problem.”

The plant was originally built with hot-side precipitators, used to collect the fly ash generated in the combustion process. At the time, the industry felt this process, which places the ESP before the air heater, was the best way to handle this type of coal. “When we began to fall short of performance metrics,” Newell says, “we quickly involved the original equipment manufacturer to help us meet benchmarks. We injected a sodium solution that bound up the fly ash. The very low resistivity of sodium improved the resistivity of the fly ash, which could then be charged more easily and attracted to collection plates.” In time this became very expensive and in the early 1980s the plant began to look for alternatives. Ultimately, the CEC was able to achieve similar results using a much cheaper ammonia-based product. “This also eliminated certain operating issues experienced at the plant,” says Newell.

In time, it was better understood that western coals like PRB do not perform well with hot-side precipitators. Around 1987, the plant switched to cold-side precipitators in Unit 2, at a project cost of about $35 million. Instead of operating at a temperature of 700 degrees, the system now operates at around 300 degrees. “About this time,” Newell says, “we also decided to add an SO3 injection system. This sulfur trioxide lowers resistivity just as sodium does, and does not exit the stack as an emission because the high calcium content of the fly ash absorbs it like a sponge.”

In about 2005, the slagging problem improved tremendously when the plant installed an over-fire air system for NOx control. Newell explains: “The main combustion zone in an over-fire air system is operated sub-stoichiometrically, meaning there is a less than one-to-one air-fuel ratio.” This reduces combustion temperatures, and the ash remains cooler. As a result, it doesn’t stick to the walls of the boiler as readily. “This was initially a NOx control measure,” Newell continues, “but it had the happy side-effect of essentially eliminating slagging.”

AQCS Retrofit Project

More recently, the CEC has worked steadily but surely toward addressing emissions issues, and it’s making progress. “We finished our air quality control system (AQCS) retrofit project-a baghouse and scrubber-about a year ago,” says Newell, “and we have had 100 percent operability since that time.”

Completed in mid-2014, the $589 million project reduced sulfur dioxide by 94 percent, and mercury by greater than 90 percent. “We began injecting finely-ground activated carbon and liquid calcium bromide to control mercury emissions in around 2007,” said Newell. “The calcium bromide is placed on the coal prior to combustion. There it oxidizes the mercury in the coal. After combustion, carbon is injected into the process which absorbs this oxidized mercury. The mercury can then be collected with the fly ash.” Without mercury controls, the CEC was emitting about 300 pounds of mercury a year per unit. That’s about a cubic foot of mercury. Now, with the calcium bromide and carbon injections, the plant emits only about 16 pounds of mercury, roughly the size of a baseball.

Black & Veatch supported the AQCS retrofit at the CEC as the EPC contractor on the project. It was their largest EPC contract to date. The company provided conceptual design, permitting support, procurement, construction, and management for the retrofit. The new AQCS facilities were constructed behind existing chimneys at the plant. Flue gas is now routed through the AQCS system via additional ductwork, then returned to the existing chimney to exit the stack as before.

Jeff Kurtz is vice president at Black & Veatch, and the project manager for the AQCS retrofit project at the CEC. “We’re very proud of our safety record in executing the project,” he says. “We had over 1.8 million man-hours and no lost-time incidents. We exceeded all performance emissions requirements and expectations and finished the project well ahead of schedule. The outage duration was less than what was planned for, and the project came in at $31 million below budget.”

Black & Veatch is now providing further engineering support at the plant. “They call it the Comprehensive Acid Management Program, or CAMP,” Kurtz continues. “We’re upgrading the turbines, installing new coal pulverizers, and upgrading the condensate polishing systems.” The plant is investing significant amounts of money toward a long-term coal-fired facility that meets current standards and operates at higher efficiencies. “As you can imagine,” Kurtz says, “there’s a lot of work to be done when tackling engineering logistics of this kind.”

The plant is also ramping up a $140 million project to remove between 50 and 75 percent of the remaining NOx in the flue gas. “We currently have a consent decree that goes into effect in early 2019,” says Newell. “This requires us to achieve .07 pounds-per-million BTU on a 12-month rolling average. To do this, we’ll depend on a standard selective catalytic reduction system.”

Efficiency Projects to be Complete by 2018

In addition to all the air quality measures being made at the CEC, the plant is also embarking on a half dozen major projects that will improve efficiency, in the process lowering carbon emissions for the plant.

One such project is a turbine upgrade. The plant currently utilizes turbines that were designed in the late 1960s. Since that time, tremendous improvements have been made in the aerodynamics of turbine blades and resulting efficiencies. Turbines now utilize new materials that experience less corrosion. These new designs eliminate much of the wear and tear on the turbine.

The Air Quality Control System Retrofit Project at the Columbia Energy Center significantly reduces emissions of mercury, sulfur dioxide, and particulate.

“Our existing turbines have begun to experience stress corrosion cracking on the L-1 and L-2 blades,” says Newell. “It’s an industry-wide issue. If a crack propagates all the way through the material, and that material detaches from the blade while the turbine is spinning at 3600 rpm, imbalances occur that result in catastrophic failure, and the unit is down for more than a year while the turbine is replaced.” To combat this problem, the plant has monitored the condition of the blades over the last 15 years. “We have discovered small cracks beginning to propagate,” said Newell. “This means we will need to replace the low-pressure turbine blades. Our first turbine upgrade to Unit 2 will take place this spring; Unit 1 will be upgraded the following spring, in 2017.”

To benefit from improvements in efficiency, the plant is reworking the entire steam path. Both stationary and rotating blades and shafts are being replaced throughout the entire machine. “This will improve the performance of the turbines by over 5 percent,” explains Newell, “which will in turn lower the carbon emission rate and increase the output of the plant without burning any more coal.”

The CEC has also replaced its cooling tower with a larger one that improves heat rejection and efficiency in the summer time. It is also upgrading its water treatment facilities, adding a condensate polisher, and improving air heater seals. Newell says altogether, the plant expects to see a nearly 10 percent reduction in heat rate.

The combined effect of multiple air quality and efficiency projects at the CEC have placed the plant in a strong position to continue operation well into the future. Overseen by plant manager Jerry Lokenvitz, the Columbia Energy Center coal-fired plant is positioned to provide power to its customers for many years to come.