The Indiana Office of Air Quality (OAQ) has approved an air permit change that would allow Duke Energy Indiana to install new selective catalytic reduction (SCR) and other air emissions controls on the coal-fired Units 1-2 at the Cayuga power plant.
The OAQ, part of the Indiana Department of Environmental Management, granted the approval on Sept. 5. Duke Energy Indiana on June 26 had requested the permit modification, relating to the installation of SCR on each unit to control emissions of NOx and to convert mercury (Hg) into a form which can be more easily captured with the existing controls. The proposed SCR system will include an arsenic mitigation system, sulfur trioxide (SO3) mitigation system, and ammonia storage facility. The arsenic mitigation system is needed to reduce degradation of the catalyst material from trace quantities of arsenic in the coal.
Duke Energy Indiana, a unit of Duke Energy (NYSE: DUK), is also proposing to install an activated carbon injection system on each unit to achieve additional Hg control. In addition, Duke Energy is plans to install a dry fly ash handling and ash fixation system. Currently the fly ash collected in the electrostatic precipitator (ESP) is sluiced to ash ponds.
The new emissions controls are planned for operation by 2015. The affected units at Cayuga are:
- One dry bottom, pulverized coal-fired boiler, identified as Boiler No. 1, installed in 1967, with a nominal heat input capacity of 4,802 MMBtu/hr, with an ESP for control of particulate matter, a flue gas desulfurization (FGD) system for control of SO2, and exhausting to stack 1. Stack 1 has continuous emissions monitors (CEMs) for NOx and SO2 and a continuous opacity monitor (COM). Boiler No. 1 was configured with a low NOx burner system in 1993.
- One dry bottom, pulverized coal-fired boiler, identified as Boiler No. 2, installed in 1968, with a nominal heat input capacity of 4,802 MMBtu/hr, with an ESP and FGD, exhausting to stack 2. Stack 2 has CEMs for NOx and SO2 and a COM. Boiler No. 2 was configured with a low NOx burner system in 1993.
New Cayuga controls part of Duke’s ‘critical path’ planning
The primary features of Duke Energy Indiana’s Phase 2 compliance plan for the 2014-2015 period include new “critical path” SCRs on Cayuga Units 1-2. The utility described its plans in recent filings with the Indiana Utility Regulatory Commission. Other Phase 2 projects include:
- dry sorbent injection (DSI) systems on Cayuga Units 1-2 for SO3 mitigation;
- activated carbon injection (ACI) systems on Cayuga Units 1-2, all five Gibson units and Gallagher Units 2 and 4; and
- mercury re-emission chemical injection systems on Cayuga Units 1-2 and Gibson Units 1, 2, 3 and 5.
These Phase 2 projects were designed primarily to meet the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and are targeted towards mercury reductions at these units (with the exception of the DSI systems at Cayuga, which are proposed for SO3 mitigation). The company tentatively plans to file its Phase 3 compliance plan with the commission by the spring of 2013, said Douglas Esamann, President of Duke Energy Indiana.
Esamann was one of several Duke officials that supplied June 28 testimony to the commission in an environmental cost review case. He noted that EPA programs like MATS and the Cross-State Air Pollution Rule (CSAPR) put a heavy burden on the company’s coal units. “Duke Energy Indiana’s only options for each unit are clear – lower emissions or shut it down,” he added. “While our compliance options under the MATS rule are severely limited, long-term environmental compliance planning and implementation remains extremely complex for electricity generators.”
The implementation of the prior, Phase 1 plan was substantially complete by the fall of 2008, when the second of the new scrubbers at the Cayuga plant was placed into service.
More emissions controls eyed for Phase 3
The company’s tentative Phase 3 projects, to be executed in the 2014-2020 period, include:
- Gibson Units 1-3 precipitator enhancements;
- Gibson Unit 5 flue gas desulfurization (FGD) replacement, since the existing FGD is a 1970s vintage technology, while the Units 1-4 FGDs are newer;
- Cayuga Units 1-2 and Gibson Units 1-4 FGD enhancements;
- Gibson Units 1-5 SCR upgrades; and
- Gallagher Units 2 and 4 selective non-catalytic reduction (SNCR) installation.
Duke Energy Indiana has 7,215 MW of generating capacity and remains heavily reliant on coal: 70% of its generating capability is coal-fired, with 26% natural gas-fired, 3% oil-fired, and less than 1% hydro-powered. About 97% of the energy generated by its units in 2011 was produced from its coal units. As a result, the company is Indiana’s largest purchaser of coal – about 12.5 million tons annually, most from Indiana mines. This portfolio will become less dependent on coal over time, with the projections for 2016 being that coal will make up only 58% of generating capability and 88% of generation.
Duke Energy Indiana’s plan includes the retirement of Wabash River Units 2-5 in April 2015, which are the oldest and smallest coal-fired units on its system, because the retrofit of these units will not be economical. The company is also assessing the long-term options for Wabash River 6 and Gibson 5, including reviewing the potential for retrofitting Wabash River Unit 6 to run on natural gas by April 2015. Gibson Unit 5 is a possible retirement option if a replacement FGD system is not found to be cost-effective.