Interstate Power works on emissions controls at Ottumwa, Lansing Unit 4

Interstate Power and Light is moving forward with new emissions control projects on coal-fired plants, including a new scrubber and baghouse installation at the Ottumwa plant in Iowa, said IPL in a July 13 filing at the Minnesota Public Utilities Commission.

The this Alliant Energy (NYSE: LNT) subsidiary filed a cover letter and a copy of a biennial Emissions Plan and Budget (EPB) April 2 at the Iowa Utilities Board (IUB). The EPB is a multi-year plan and budget for managing regulated emissions from IPL’s coal plants in Iowa. Under a March 2 Minnesota commission order, the utility filed a copy of the EPB with the commission.

“IPL acknowledges that Minnesota Statutes, section 216B.1695 establishes a procedure for a utility to request from the Commission an advanced determination of prudence (ADP) for certain projects undertaken to comply with federal or state air quality standards,” said the cover letter. “Qualifying projects must: 1) have an expected jurisdictional cost to Minnesota ratepayers of at least $10 million; and, 2) be undertaken to comply with either a state requirement issued as part of a state implementation plan, permit, or, order, or a federal requirement under section 111 or 112 of the federal Clean Air Act.”

As part of its EPB, IPL intends to install, by 2014, a scrubber and baghouse at its Ottumwa Generating Station (OGS). OGS is a single unit, coal-fired baseload plant located in Chillicothe, Iowa. The unit began operation in 1981, has a nameplate rated capacity of 726 MW and is jointly owned with MidAmerican Energy. IPL is the operator of the plant and owns roughly 387 MW of the total capacity. The OGS scrubber and baghouse project has an estimated total capital cost to IPL of $165m.

“It is IPL’s belief that the OGS scrubber and baghouse project does not meet the statutory dollar threshold under Minnesota Statutes, section 216B.1695,” the utility said. “Consequently, the OGS scrubber and baghouse project does not qualify for an ADP from the Commission. However, in the interest of full disclosure, IPL believes that it should advise the Commission and the other parties in Docket No. E001/RP-08-673, through this submission, of this important environmental project.”

IPL said it has not made any official changes to its Integrated Resource Plan (IRP) on-file at the Minnesota commission. However, IPL’s April 2 EPB filing in Iowa, as corrected by April 4 and July 2 errata filings, is being provided to the parties to advise them that the outcome of the EPB filing may lead to changes to IPL’s plan. When IPL finalizes any IRP changes, it intends to make the required notice of changed circumstances filings with the commission. IPL is not seeking any action by the commission on the emissions plan and budget at this time.

Scrubber also in the works for Lansing Unit 4

The EPB outlines the status of various emissions projects at IPL plants. For example, at Lansing Unit 4, low NOx burners (LNB) and selective catalytic reduction (SCR) projects went into service in July 2010. The activated carbon injection (ACI) and baghouse system at Lansing 4 went into service in July 2010. Planning is currently underway for a circulating fluidized-bed (CFB) dry scrubber for this unit. Construction activities would begin in 2013. The scrubber project is currently expected to go into service in 2015.

For Ottumwa Unit 1, IPL has gotten Iowa permit approval for construction of a new air quality control system (AQCS) that includes an ACI system and pulse jet fabric filter (PJFF) baghouse that will reduce mercury emissions. IPL has selected Burns & McDonnell and Babcock & Wilcox to complete detailed engineering and begin fabrication and construction of the ACI system and baghouse in 2012. Commissioning is scheduled for 2014. It also plans a Spray Dryer Absorber (SDA) flue gas desulfurization technology. IPL has selected Burns & McDonnell and Babcock & Wilcox to complete detailed engineering, and begin fabrication and construction of the spray dryer absorber in 2012. Commissioning is scheduled for 2014.

CFB scrubber technology is newer than the SDA technology; however, CFB scrubbers have been used on coal boilers in Europe and Asia since the early 1990s, the EPB pointed out. CFB scrubbers are becoming a more common SO2 control technology in North America. The leading supplier of CFB scrubbers has installed at least 12 units in the U.S. At least two other U.S. companies have also licensed or developed the technology and have installed additional units. More unit installations are under contract.

Testing shows biomass co-firing not a viable option

The EPB noted that IPL did not conduct any biomass testing in 2011. “Based upon an evaluation of the logistical and economic challenges associated with operating a coal-fired generation unit with biomass co-firing, IPL decided to postpone plans for biomass testing and instead look to benefit from biomass testing that was conducted at the Wisconsin Power and Light Company (WPL) Nelson Dewey generating station. The biomass testing was conducted at Nelson Dewey in the fall of 2011. Although technically feasible to co-fire biomass at this coal-fired generation unit, the high cost of the biomass fuel makes the process prohibitive. IPL does not have any biomass testing planned currently.” WPL is another Alliant subsidiary.

The EPB also discussed the use of dry sorbent injection (DSI) systems for SO2 control. That is a technology that power generators nationwide are increasingly looking at for installation on coal units that are too old for expensive conventional SO2 scrubbers. But the DSI can give those power companies a few more years of useful life before retiring those units.

“DSI systems can achieve 30%-90% SO2 removal rates on a consistent basis, depending on the type and quantity of sorbent used,” said the EPB. “Actual removal rates will depend on site specific design characteristics. Depending on the type of sorbent, DSI may also capture HCl, other acid gases and Hg. Precipitator performance may limit the amount of sorbent that can be injected without impacting particulate emissions. The capital cost for DSI is significantly lower than wet or dry scrubbers, providing existing precipitator performance is adequate. The volume of sorbent required causes significant operations and maintenance (O&M) expenditures and may render ash unsuitable for sale.”

DSI has been demonstrated at WPL’s Edgewater Unit 4 in Sheboygan, Wisc., the company noted. The short duration tests at full load and stable SO2 emissions produced the following results: with Trona, the maximum SO2 removal was about 67%; and the use of sodium bicarbonate resulted in around 78% removal. In both tests the sorbent injection rate was based on the vendor’s estimates for 70%-90% removal.

For smaller, intermediate-load, coal units, IPL continues to consider conversion to alternative fuels, such as natural gas, instead of installing emission controls. In 2011, IPL switched the Dubuque plant to a natural gas-fired facility and no longer operates the site as a coal-fired facility. IPL also is switching this year its Sutherland plant (Units 1 and 3) from coal to natural gas. Co-firing of natural gas with coal may also provide an economic alternative, the EPB noted.

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.