Kentucky Power to scrub one Big Sandy coal unit, shut the other

Saying it is already behind schedule to meet new air mandates like the Cross-State Air Pollution Rule, the Kentucky Power unit of American Electric Power (NYSE:AEP) is seeking Kentucky Public Service Commission approval to install a dry SO2 scrubber system on Unit 2 of its Big Sandy power plant.

Besides current and pending U.S. Environmental Protection Agency air rules, Kentucky Power told the commission in a Dec. 5 application that under a consent decree it worked out with EPA in 2007 covering coal plants in five eastern states, it agreed to install flue gas desulfurization equipment on Big Sandy Unit 2 by the end of 2015. Kentucky Power is seeking a certificate of public convenience and necessity for the Big Sandy Unit 2 scrubber along with related projects, like a scrubber waste landfill.

Big Sandy Unit 1 is a 278-MW coal-fired unit completed in 1963. Big Sandy Unit 2 is an 800-MW coal facility completed in 1969. Kentucky Power said in the Dec. 5 filing that it currently anticipates retiring Big Sandy Unit 1 by Jan. 1, 2015, and will make all needed filings related to this retirement by separate application. A big negative for Unit 1 is that it lacks both selective catalytic reduction for NOx control and an FGD system and would need both for future air compliance. Unit 2 already has an SCR. Unit 1 is also a subcritical pulverized coal facility, while Unit 2 is a more efficient supercritical unit.

The Unit 2 scrubber project is currently in Phase 1, with initial planning and conceptual engineering completed. Kentucky Power proposes to commence site construction activities at Big Sandy on or about July 1, 2013. Kentucky Power requested that the commission issue its Certificate of Public Convenience and Necessity by June 5, 2012.

Kentucky Power said that CSAPR, which has a first phase that takes effect in January 2012 and a second phase that starts January 2014, sets aggressive compliance timelines and restrictive emissions caps that will be difficult to comply with. The 800-MW Unit 2 needs to be severely curtailed, retired or retrofitted to achieve massive SO2 reductions. CSAPR also provides the company with the option to acquire SO2 or NOx allowances to offset Phase 1 and Phase 2 emission levels that exceed annual EPA-budgeted allowance allocations. The extraordinarily brief compliance window will require Kentucky Power to operate Big Sandy Unit 2 in an uncontrolled fashion, but under a potentially constrained dispatch, said the company. This is due to the fact that the timeframe to permit and install the DFGD system is beyond the CSAPR compliance deadlines.

“In essence, the timing contained in the rule already puts us behind schedule,” said John McManus, Vice President-Environmental Services at American Electric Power Service Corp., also a subsidiary of AEP, about CSAPR compliance. Another factor in compliance planning is EPA’s proposed Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule.

Company witness Robert Walton described the difference between the commonly-used wet FGD process and the dry FGD system planned for Big Sandy Unit 2. Walton is Managing Director of Projects and Controls at AEP Service.

“In a WFGD system, alkaline reagent slurry (usually lime or limestone) is injected into a vessel, where it reacts with the flue gas to collect the SO2,” said Walton. “A WFGD absorber utilizes a high volume of liquid slurry continuously circulating in the absorber vessel and collecting in the absorber reaction tank where the scrubbing reaction occurs. A DFGD is comprised of the absorber vessel or duct integrated with a pulse jet fabric filter (PJFF), often referred to as a baghouse. The DFGD does not utilize a liquid filled reaction tank, but instead relies on the scrubbing reactions to take place as the flue gas intermingles with the lime inside the vessel or ductwork and also in the highly reactive dust cake on the surface of the downstream fabric filter media.”

The preferred NID DFGD system was compared to a Spray Dryer Absorber (SDA) technology, Circulating Dry Fluidized Bed Scrubber (CDS) technology and the Limestone Forced Oxidized (LSFO) Spray Tower WFGD technology. Considering equivalent SO2 removal efficiencies among those options, the proprietary NID DFGD system is the favored technology, said Walton. Reasons for that include: lowest total evaluated cost on a 30-year cumulative present worth basis (capital and O&M); lowest water consumption; lowest auxiliary power usage; lowest reagent usage; and smallest equipment footprint.

The NID installation at Big Sandy Unit 2 will be designed to reduce SO2 emissions by 98%. The cost estimate for the DFGD installation, excluding Allowance For Funds Used During Construction, is currently $839m, which also covers ancillary costs like the scrubber waste landfill.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.