The Tennessee Valley Authority, which is shutting a number of coal units due to clean air needs, is looking at installing new flue gas desulfurization (FGD), selective catalytic reduction (SCR) and activated carbon injection (ACI) systems at the Gallatin coal plant in Sumner County, Tenn.
TVA is taking comment until Nov. 16 on a draft environmental assessment (EA) covering these projects. These projects are needed in order to meet the new Mercury and Air Toxics Standards (MATS) and to comply with the April 2011 Federal Facilities Compliance Agreement (FFCA) between the U. S. Environmental Protection Agency and TVA.
Gallatin, known as GAF in the draft EA, would get a dry FGD system to control SO2, SCR for NOX emissions and ACI integrated with the dry FGD to reduce mercury emissions. It would also get a pulse jet fabric filter (baghouses or PJFF) to control particulate matter (PM) emissions.
Additional facilities required to support TVA’s proposed action include a new on-site dry coal combustion product (CCP) landfill; electrical transmission lines, transformer yard, and switchyard upgrades; and ancillary facilities such as on-site haul roads. TVA’s plans for closure of surface impoundments to support wet-to-dry conversion plans specific to GAF are not included in the scope of the draft EA. TVA has been forced to phase out wet coal ash storage after the notorious failure in December 2008 of a dam at a wet storage facility at its coal-fired Kingston power plant in Tennesee.
GAF has four coal-fired units and combusts an average of 12,350 tons of coal per day. Units 1 and 2 each have nameplate ratings of 300 MW, and Units 3 and 4 each have nameplate ratings of 327.6 MW. In a typical year, GAF generates about seven billion kilowatt-hours (kWh) of electricity. Four fuel-oil combustion-turbine (CT) units were added to GAF in the early 1970s, and another four in 2000. The CT units support GAF’s peak energy demand.
TVA has installed electrostatic precipitators (ESPs) at GAF to reduce PM emissions and low-NOX burners to reduce NOX. TVA also burns a low-sulfur blend coal, primarily from the Powder River Basin (PRB), to reduce SO2.
Currently, about 185,000 dry tons of fly ash and about 45,000 dry tons of bottom ash are wet-sluiced to GAF’s surface impoundments each year. TVA has proposed dry CCP operations for the fly ash and dry FGD byproduct as part of the proposed action; activities to support bottom ash wet-to-dry conversion are not included in the scope of this EA.
TVA picks the NID dry scrubber system for this project
The following dry FGD systems were evaluated by TVA during the technology selection process:
- Spray drying absorber (SDA);
- Circulating dry scrubber (CDS); and
- Novel integrated desulfurization (NID) system of flash dryer absorber (FDA).
TVA said it selected the NID dry scrubber technology, because, compared with the other types of scrubbers, the NID scrubber has low capital and maintenance costs, as well as low operating energy requirements. The main components of the NID system include a fabric filter (FF) that separates the gas from the solid material; a reactor, where calcium hydroxide (Ca(OH)2) is used; a mixer, where byproduct, water, and lime are mixed; and hopper/trough where dust is stored before being recirculated to the mixer.
Units 1-4 would be retrofitted with an SCR system to reduce NOX emissions by approximately 90%, given an inlet NOX of 0.4 lb per MMBtu. The new SCRs would be placed where the ESPs are currently located. When the dry FGD system is built, a new duct system would be added to direct the flue gas directly from the SCR reactors across the discharge channel and into the dry FGD system.
TVA would construct and operate an ACI system for each dry FGD to reduce mercury emissions from GAF Units 1-4. The ACI injection point is anticipated to be after the dry FGD and before the PJFF.
TVA would construct a dry CCP facility to store the waste from GAF’s new clean air equipment. GAF’s four coal units currently produce about 185,000 dry tons of fly ash, which are wet-sluiced to on-site fly ash and bottom ash ponds. TVA estimates that CCP production from new equipment proposed could range from 430,000 to 835,000 dry tons per year (TPY). This range is conservatively based on the proposed blend of 50% Illinois Basin and 50% Powder River Basin coal and resulting variation of annual CCP production.
Two separate landfills, the NRL and SRL, would be constructed. Initially, the NRL landfill would be constructed to support GAF’s operations. TVA anticipates that the NRL landfill could occupy about 94 acres of land, of which 50 acres would be developed per Subtitle D for CCP disposal. Although the NRL will be permitted to accept all dry CCP, dewatering of the bottom ash is not included in this scope. Active areas within the landfill footprint, also referred to as ‘cells,’ would be operated to about 6 million cubic yards of disposal capacity. The maximum height of the CCP facility would be about 150 feet, which results in an active stack elevation of 650 feet above mean sea level. In the event NRL reaches full capacity, TVA would implement plans to design and construct the SRL landfill.
Biomass, more reliance on natural gas rejected as options
TVA considered and rejected options like converting Gallatin to biomass. It also considered operating Units 1-4 “as-is” until ceasing operations in April 2015 under the Utility MATS or on Dec. 31, 2017, under the FFCA, if MATS requirements were delayed or vacated in the meantime. This alternative would not result in the installation of the new emissions controls.
“Although this alternative would comply with the FFCA and applicable regulations and would reduce local and regional emissions, retiring GAF coal-fired boilers would not maintain an existing energy asset available to generate reliable and cost-effective energy for the region,” the draft EA noted. “Nor would it help meet TVA’s plans and identified need for a more balanced energy resource portfolio. TVA would have to rely more on natural gas and/or nuclear resources to replace the generation from GAF’s coal units. Solar or wind energy resources are intermittent and are not energy resources that are equivalent to coal-fired generation.”
TVA’s 2011 integrated resource plan (IRP) contemplates using all of these resource options as well as the continued operation of many of TVA’s existing coal units. In addition to completing Unit 2 at TVA’s Watts Bar Nuclear Plant and the addition of the gas-fired John Sevier Combined Cycle plant to the TVA system, TVA is adding considerable demand side resources to its portfolio and will scale up its most successful programs to increase the contribution of energy efficiency.
“As part of the analysis carried out in the IRP, TVA determined that over-reliance on any specific type of energy resource was not optimal either from a cost or risk perspective,” the draft EA added. “It found that portfolios that relied more heavily on specific kinds of energy resources performed more poorly in most scenario analyses than more diversified portfolios.”
Replacing the GAF coal units with more natural gas combined-cycle units would provide TVA generation that is more equivalent in performance to coal-fired generation than currently available renewables, TVA added. “Until very recently, however, natural gas has been subject to wide price swings and supply shocks (i.e., weather events like hurricanes or severe cold snaps often drove prices three to five times higher than normal) that have resulted in greater volatility in the costs of energy generated using natural gas. As the market for gas continues to internationalize, and LNG export capabilities expand, the current dampening effect shale gas supplies have had upon gas prices could disappear or weaken, resulting in return to volatility in the future. Coal, which is purchased on much more local, domestic markets, has been more insulated from global demand.”
50-50 blend of Illinois Basin and PRB coal is the base fuel option
An appendix to the draft EA shows assumed coal specs after the emissions controls are in. That involves a 50-50 blend of Illinois Basin (5 lbs of SO2/mmBtu and 11,500 Btu/lb) and Powder River Basin (0.6 lbs/mmBtu of SO2 and 8,720 Btu/lb) coal.
The scrubber design coal is not limited to only PRB and ILB coals, the draft EA pointed out. Any other available coal combination is acceptable provided the individual fuel constituents are met.
Although the draft EA’s basic specs show that the final blend moisture is 18.7%, the scrubber is to be designed for a maximum of 30% coal moisture. The 30% moisture is recommended due to previous problems at GAF. Although the basic specs for the final blend ash is 6.9%, the scrubber will be designed for a maximum of 15% coal ash (% dry basis). The 15% ash level is recommended to provide necessary flexibility and baghouse sizing.
Although the basic blend specs are that the final blend chlorine is 0.066% (dry), the scrubber will be designed for a maximum of 0.25% chlorine. The 0.25% chlorine is recommended to provide necessary flexibility for fuel changes. No one coal type is to exceed 0.25% on chlorine. Chlorine can be a particular issue for some Illinois Basin coal, particularly some of the Illinois coals.
TVA retiring, idling coal units due to 2011 agreements
Said TVA’s Aug. 3 Form 10-Q filing about the reasons underlying the Gallatin project: “In April 2011, TVA entered into two substantively similar agreements, one with the EPA and the other with Alabama, Kentucky, North Carolina, Tennessee, and three environmental advocacy groups: the Sierra Club, National Parks Conservation Association, and Our Children’s Earth Foundation (collectively, the ‘Environmental Agreements’). They became effective in June 2011. Under the Environmental Agreements, TVA committed to (1) retire on a phased schedule 18 coal-fired units with a combined summer net dependable capability of 2,200 MW, (2) control, convert, or retire additional coal-fired units with a combined summer net dependable capability of 3,500 MW, (3) comply with annual, declining emission caps for SO2 and NOx, (4) invest $290 million in certain TVA environmental projects, (5) provide $60 million to Alabama, Kentucky, North Carolina, and Tennessee to fund environmental projects, and (6) pay civil penalties of $10 million.”
In an effort to address operational challenges and reduce costs, TVA announced the idling of several coal-fired units. TVA idled Johnsonville Units 7-10 on March 1, 2012 (564 MW of summer net capability) and announced plans to idle Johnsonville Units 5-6 and Colbert Unit 5 by Oct. 1, 2012 (686 MW of summer net capability), the Form 10-Q said. The idling of the Johnsonville units was earlier than required in the 2011 Environmental Agreements.
Due to unanticipated operating challenges of certain generating units, TVA said in the Form 10-Q that it was is in the process of re-evaluating the previously announced idling dates of these units. Johnsonville Unit 9 (141 MW of summer net capability) was brought back into service during June 2012. Johnsonville Unit 10 (141 MW of summer net capability) was brought back into service in July 2012.
Consistent with the Environmental Agreements, Units 1-2 at John Sevier will be retired by Dec. 31, 2012, the Form 10-Q said. The remaining two units at John Sevier will be idled by Dec. 31, 2012. The four John Sevier units have a summer net capability of 704 MW. Johnsonville Units 1-4 will be retired by Dec. 31, 2017. These four units have a summer net capability of 428 MW.