Orlando nears permit for coal unit emissions projects

The Orlando Utilities Commission, which applied in June with the Florida Department of Environmental Protection for an air permit for new emissions controls on two coal-fired units at the Stanton Energy Center, is close to getting that permit.

The DEP on Aug. 2 issued a notice of intent to approve the permit, with that notice now going through a public comment process.

Stanton presently consists of two coal units and two combined-cycle units. Units 1 and 2 (468 MW each) began operation in 1987 and 1996, while combined-cycle Unit A (640 MW) began operation in 2003 and combined-cycle Unit B (300 MW) began operation in 2009.

The proposed project consists of:

  • installation of a selective catalytic reduction (SCR) system on Unit 1;
  • installation of dry sorbent injection (DSI) systems on Units 1 and 2; and
  • upgrades to the flue gas desulfurization system (FGD) system on Unit 1.

This equipment is aimed at reducing emissions of key criteria pollutants in preparation for upcoming regulatory programs such as the Cross-State Air Pollution Rule (CSAPR) and the Mercury and Air Toxics Standards (MATS).

Unit 1 consists of a coal-fueled Babcock & Wilcox water-tube wall-fired boiler/steam generator and steam turbine, which drives a generator with a nameplate rating of 468 MW. No. 6 fuel oil is used for startup and flame stabilization. Biogas from a nearby landfill is also combusted. Air control equipment consists: of an electrostatic precipitator (ESP); low-NOx burners (LNB) and overfire air (OFA) for NOx control; and a wet FGD for SO2 control.

“The Department recognizes that a further reduction below the 0.28 lb NOX/MMBtu vendor guarantee for the LNB/OFA can be achieved by the installation of an SCR system,” the DEP noted. “In recent years, as reported in the application, the average NOX emissions rate from Unit 1 has been 0.2613 lb/MMBtu (baseline period). OUC expects that the SCR project will substantially decrease NOX emissions from its baseline to a value of approximately 0.04 lb/MMBtu. OUC states that it will operate the system to a level necessary to comply with the CSAPR. The current permit limits are 0.6 lb/MMBtu (30-days rolling average) and 0.46 lb/MMBtu (annual average).”

OUC proposes to duplicate the existing Unit 2 SCR system for Unit 1, incorporating improvements in SCR technology over the years. The proposed SCR system will include a single reactor.

OUC proposes a DSI system to inject hydrated lime into the exhaust gas ductwork upstream of the ESPs to minimize SO3 formation and ultimately to control H2SO4 emissions from the stacks to a concentration of approximately 3 ppm in both units. The DSI system will also mitigate potential “blue-plume” episodes by controlling H2SO4 that could occur as a result of oxidation of SO2 by the SCRs and will allow both units to maintain H2SO4 emissions at current levels.

Stanton Unit 1 (as well as Unit 2) utilizes WFGD limestone-based scrubbers to control SO2 emissions. Each unit’s scrubber system includes three 50% capacity absorber modules, with two normally in operation and the other designated as a spare.

To further increase reliability and flexibility of the Unit 1 WFGD system, OUC commissioned a study to evaluate improvements in SO2 removal capability. This study was performed by Black & Veatch with assistance from Wheelabrator Air Pollution Control Co.

OUC is in the bidding process for determining which FGD vendor can provide the most cost-effective upgrades for meeting the new SO2 emission target and the exact nature of the needed FGD improvements, the DEP noted. The final upgrades will work in conjunction with previous upgrades to reduce SO2 emissions for up to the maximum design coal sulfur content of 3.5%, by weight, that OUC sees in its fuel deliveries.

Based on the study conducted, OUC plans the following possible modifications, although the final selection of the FGD upgrades is still underway.

  • Based on the existing absorber modules, the study indicated that the Unit 1 WFGD system performance can be significantly improved with the addition of a perforated distribution tray. Distribution trays have commonly been used by the industry in the design of new scrubber systems and have been used as a retrofit option to improve performance of existing FGD.
  • Like with the distribution trays, industry experience has shown FGD performance can be improved with the addition of wall rings between the spray headers. The wall rings are attached to the inner circumference of the absorber between the spray headers. The rings direct both the flue gas and the slurry away from the wall where contact between the two phases is limited towards areas where gas-liquid contact is enhanced.
  • New spray headers with a modified nozzle arrangement with more modern nozzles can be used to maximize spray coverage. Improvements in recycle spray nozzles and their arrangements provide a more uniform and denser spray coverage pattern, which provides better interaction between the spray and better gas/liquid contact.
  • ID fan modifications may be necessary to support the specific FGD improvements selected.
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.