Gulf Power permits new emissions controls for Lansing Smith coal units

Gulf Power, a unit of Southern Co. (NYSE: SO), is working on permitting needed to extended the lives of the coal-fired Units 1 and 2 at the Lansing Smith power plant.

The Florida Department of Environmental Protection on July 30 went out for public comment on draft air permitting for this project. Unit 1 and 2 are tangentially-fired, dry-bottom coal boilers that began commercial operation in 1965 and 1967, respectively. Boilers 1 and 2 have a common 199-foot stack and are equipped with this air pollution control equipment:

  • hot and cold side electrostatic precipitators (ESPs) to control particulate matter (PM);
  • low NOX burners and non-selective catalytic reduction (SNCR) systems to control NOX; and
  • continuous emissions monitoring systems to measure and record NOX and SO2 emissions and a continuous opacity monitoring system to measure and record the opacity of the exhaust gas.

The project being permitted establishes an SO2 emission standard of 0.74 lb/MMBtu of heat input on a 30-day rolling average basis for Boilers 1 and 2. The limit will be met by a combination of dry sorbent injection (DSI) upstream of one or both ESPs on each unit, upgrades to the ESPs to capture the reacted sorbent, and coal sourcing consistent with the DSI system capabilities and the SO2 standard.

DSI systems remove SO2 and other acid gases through two basic steps. A powdered sorbent is injected into the boiler furnace exhaust gas with the SO2. The sorbents most commonly associated with DSI are sodium sesquicarbonate (trona), sodium bicarbonate and hydrated lime. The resulting reaction products and excess unreacted sorbent are removed by a downstream PM control device such as an ESP or a fabric filter (baghouse).

The GenerationHub database gives the Unit 1 capacity as 162 MW in the summer, with Unit 2 at 195 MW.

Gulf identifies Colombian coal as the plant’s main future fuel

During recent years, annual emission factors from Boilers 1 and 2 combined have ranged from 0.93 and 1.48 lb/MMBtu. “Given that the future coal sulfur range will be similar to the range in coal used over the past few years, then the SO2 removal objective for the DSI systems is approximately 20 to 50 percent (%),” the DEP noted. “Per the applicant, future coal sourcing is primarily Colombian coal.”

Boilers 1 and 2 are equipped with hot and cold side ESPs. Therefore the air preheater in each unit is located between the two ESPs. Depending upon the reagent loading required to reduce SO2 to target levels, it may be necessary to remove greater mass than just the fly ash emitted from the furnaces. The additional mass removal may require operational changes but could also be accomplished by physical changes, DEP said.

Among the possible changes envisioned is conversion of hot-side ESPs to cold-side ESPs by moving the preheaters from the present locations between the ESPs to immediately after the economizers. Such changes reduce the actual volumetric flow rates treated by the first ESPs and increase the residence time of exhaust gases within the control equipment. Reagent can be injected before or after the air preheaters and before or between the ESPs. High temperature injection can promote a “popcorn effect,” which increases the reagent surface to volume ratio, the DEP said. The additional mass loading increases the volume of ash to be handled. There is at least the possibility of some minor changes in the coal and ash handling systems to facilitate the overall SO2 reduction objective.

Gulf Power said in an Aug. 1 fuel filing at the Florida Public Service Commission that Lansing Smith is forecasted to burn between 481,000 and 512,000 tons of coal a year and must comply with a state SO2 emission limit of 2.1 lbs SO2/MMBtu. Smith can burn a variety of coals, including Illinois Basin and imported coals such as Colombian, Australian and Venezuelan. Domestic sources such as Colorado, Utah and Central Appalachia coals also have been burned in the past.

DSI plus Colombian coal the leading option in BART analysis

Various technologies, including DSI, plus the use of low-sulfur Colombian coal, are being looked at for compliance with regional haze rules at Lansing Smith. Gulf Power on July 16 filed with the DEP a five-factor analysis of Best Available Retrofit Technology (BART) options for the plant. Units 1 and 2 are BART-eligible.

With respect to the Regional Haze Rule (RHR) BART requirements, the U.S. Environmental Protection Agency previously determined that emissions sources subject to the Clean Air Interstate Rule’s (CAIR) SO2 and NOx trading programs would achieve SO2 and NOx emissions reductions that would result in visibility improvement that is better than BART; therefore, these two pollutants would not need to be addressed in BART determinations. Due to legal challenges to CAIR, EPA issued a final rule in July 2011, called the Cross-State Air Pollution Rule (CSAPR).

For Florida electrical generating units (EGUs), CSAPR only addresses ozone season NOx emissions. However, in December 2011, a federal appeals court stayed CSAPR and left CAIR in effect pending judicial review. So, Units 1 and 2 remain subject to CAIR, which, for Florida EGUs, addresses SO2 and NOx (both annual and ozone season), the analysis said.

Although Smith Units 1 and 2 remain subject to CAIR and EPA has determined that both CAIR and CSAPR will result in visibility improvement that is better than BART, due to the regulatory uncertainty with CAIR and CSAPR, the Florida DEP requested the submittal of a five-factor BART analysis for Smith Units 1 and 2 for SO2, NOx, and particulate matter (PM). Gulf Power prepared the BART analysis filed July 16 in response to the FDEP’s request.

SO2 retrofit control technologies evaluated include: switch to lower sulfur Colombian coal; DSI with use of lower sulfur Colombian coal; dry flue gas desulfurization (DFGD) lime spray dryer absorber (SDA); and wet flue gas desulfurization (WFGD). The proposed SO2 BART determination for Smith Units 1 and 2 is an SO2 emissions rate of 0.74 lb/MMBtu on a 30-day rolling average basis, which can be achieved with the use of DSI with trona as the alkaline reagent. The proposed BART SO2 control technology will be installed and in operation no later than the Mercury and Air Toxics Standard (MATS) compliance deadline prior to the end of the first 10-year RHR planning period in 2018.

The DSI (trona) plus Colombian coal option represents the best level of control based on consideration of the statutory factors required by Section 169A(g)(7) of the Clean Air Act.

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.