Orlando nears permit decision on Stanton air emissions projects

The Florida Department of Environmental Protection on Jan. 15 went out for comment on a draft air permit covering new air emissions control systems for the Stanton power plant of the Orlando Utilities Commission.

On Oct. 29, 2014, Orlando Utilities Commission (OUC) submitted an application requesting authorization to install and operate several pollutant reduction systems.

  • OUC is requesting the installation of a Fuel Lean Gas Re-burn (FLGR) system on Units 1 and 2 for additional NOx reduction.
  • OUC is proposing upgrades to the wet flue gas desulfurization (FGD) scrubber system on Unit 2 to improve SO2 emissions reduction efficiency to help comply with the federal Mercury and Air Toxics Standards (MATS).
  • OUC is requesting authorization to install an activated carbon injection (ACI) system on Unit 2, similar to the temporary system previously authorized by by the DEP. This system will be used in combination with chemical spray technology to mitigate mercury emissions. The chemical spray technology is based on spray application of halogen-based additives such as calcium bromide (CaBr2) into the coal feeder and sodium hydrosulfide (NaHS) into the FGD scrubber systems.

The Stanton Energy Center is a nominal 1,876-MW facility. It consists of: two fossil fuel fired steam generating units (Units 1 and 2); and two combined cycle combustion turbine-electrical generators (Units A and B). Units 1 and 2 fire coal and No. 6 fuel oil and have a combined output of 936 MW. Unit 1 began operation in 1987 and Unit 2 began operation in 1996. Units 1 and 2 have the following pollution controls: NOX emissions are controlled by low NOX burners (LNB), over fire air (OFA) and selective catalytic reduction (SCR) systems; PM emissions are controlled by dry electrostatic precipitators (ESP); and SO2 emissions are controlled by a wet FGD scrubbers.

Re-burn system to cut NOX emissions by up to 30%

The proposed FLGR installation on Units 1 and 2 could reduce NOx by up to 30%. The proposed system would require approximately 5% to 10% firing of natural gas above the OFA zone in each of the boilers. Specifically, 10% of the total coal heat input of each unit would be replaced by natural gas above the OFA zone. The heat input to each unit is not expected to increase as a result of this project. Instead 10% of the total coal heat input to each unit would be replaced by natural gas, thereby lowering overall emissions.

A prior permit authorized an initial demonstration project covering 90 non-consecutive operational days to evaluate spray technology and activated carbon injection. The purpose of this project was to explore mercury mitigation measures by ACI testing, and CaBr2 spray application to the coal, and NaHS additive to the scrubber liquor to reduce emissions of mercury to meet the applicable MATS standards. During the demonstration, the ACI and chemical spray technology (CaBr2 and NaHS) were found to be effective in reducing emissions of Hg. No detrimental effects on precipitator performance were observed. Therefore, the department will authorize the permanent operation of a portable ACI system that can be used on either Units 1 or 2 as well as the chemical spray technology (CaBr2 and NaHS) for Units 1 and 2.

The existing wet FGD scrubber system on Unit 2 consists of three 50% capacity absorber modules, with normal operation consisting of two operating absorber modules with one module designated as a spare. The absorber chemistry is limestone based, operating in forced oxidation mode. Four recycle pumps per module are provided, with three used for normal operation and the fourth acting as an installed spare.

The scrubber upgrades on Unit 1 authorized by previous permitting actions have been completed. OUC is now requesting to carry out similar upgrades to Unit 2. OUC is currently in the evaluation process to determine which wet FGD vendor can provide the most cost-effective upgrades for Unit 2 with regard to meeting the MATS SO2 emission target of 0.2 lb/MMBtu (30-day average). All of the scrubber modifications being evaluated are essentially internal to the scrubber and may be used alone or in combination with others depending on the optimized improvement approach developed by the selected vendor. Although the final design of the FGD scrubber system upgrades for Unit 2 is still underway, the upgrades should be very similar to those conducted for Unit 1.

Here are descriptions of the possible FGD modifications being evaluated by OUC:

  • Installation of Distribution Trays: Based on the existing wet FGD modules, industry experience has shown wet FGD system performance can be significantly improved with the addition of a perforated distribution tray. Distribution trays have commonly been used in the design of new scrubber systems and have been used as a retrofit option to improve performance of existing wet FGD systems. The distribution trays provide intimate contact between the gas and liquid phases and the resulting increased mass transfer surface area improves the amount of SO2 absorbed in the scrubbers.
  • Addition of Wall Rings: Much like the distribution trays, industry experience has shown wet FGD performance can be significantly improved with the addition of wall rings between the spray headers. Wall rings have been commonly used in the design of new scrubber systems and have been used as a retrofit option to improve performance of existing wet FGD systems. 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.
  • Improved Spray Header and Nozzle Design: New spray headers with a modified nozzle arrangement with modern nozzles can be used to maximize spray coverage. Improvements in recycle spray nozzles and their arrangement provide a more uniform and denser spray coverage pattern which provides better interaction between the sprays and better gas/liquid contact. Changes in the direction of the sprays (use of both counter and co-current sprays), dual nozzles to allow the sprays to interact better, and flatter spray patterns are all options that are currently presented by the various vendors and are being evaluated. Modification of the nozzles may provide a lower pressure drop that may allow the existing pumps to produce higher flow rates, without changing the current pump operating speeds.
  • Fan Performance: Modify the induced draft fan to increase the speed to account for the additional pressure drop caused by the scrubber upgrades.

Modifications to the wet FGD system will not increase the capacity of Unit 2, the DEP 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.