Orlando Utilities Commission plans air upgrades for Stanton coal units

The Orlando Utilities Commission (OUC) is pursuing the permitting for several new air emissions controls for its partially coal-fired Stanton Energy Center.

The commission’s October application for this permitting was posted on Nov. 26 to the website of the Florida Department of Environmental Protection and is still pending. The application was written by consultant Golder Associates.

The Stanton Energy Center (SEC) is a nominal 1,876-MW facility. It consists of:

·      Two fossil fuel fired boiler electrical generating units (Units 1 and 2);

·      Two combined cycle combustion turbine-electrical generators (Units A and B);

·      Solid fuels, fly ash, limestone, gypsum, slag, bottom ash storage and handling facilities; and

·      Fuel oil storage tanks.

Units 1 and 2 fire coal and natural gas and have a combined output of 936 MW. Unit A fires natural gas and diesel fuel and has a total nominal capacity of 640 MW. Unit B fires natural gas and fuel oil and has a design capacity of 300 MW.

The two coal units are equipped with the following air emissions control equipment: dry electrostatic precipitators for control of particulate matter emissions; wet flue gas desulfurization systems for control of SO2 emissions; low NOx burners and overfire air systems for control of NOx emissions. In addition, Unit 2 has a selective catalytic reduction (SCR) system to further control NOx. Unit 1 began operation in 1987 and Unit 2 began operation in 1996.

The purpose of the pending permit application is to request authorization for the installation of several pollutant reduction systems. Specifically, Orlando is requesting the installation of a Fuel Lean Gas Reburn system on Units 1 and 2 for additional NOx reduction. This is in response to the U.S. EPA‘s requested implementation of the Cross State Air Pollution Rule by 2015. Orlando is also proposing upgrades to the wet FGD system on Unit 2. These proposed upgrades would be similar to the upgrades already completed on Unit 1.

Finally, OUC proposes to install an activated carbon injection system similar to the temporary system previously authorized by the DEP. This system will be used in combination with chemical spray technology to mitigate mercury emissions. The proposed portable ACI system may be used on either Unit 1 or Unit 2. The proposed 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 wet FGD system.

The proposed FLGR installation on Units 1 and 2 would theoretically reduce NOx on Unit 1 by 30 percent and on Unit 2 by an amount to be determined. The proposed system would require about 5 percent to 10 percent firing of natural gas above the “over-fire air” (OFA) zone in each of the boilers. Specifically, 10 percent of the total coal heat input of each unit would be replaced by natural gas above the OFA zone. The heat input to each steam unit is not expected to increase as a result of this project; rather, 10 percent of the total coal heat input of each unit would be replaced by natural gas, thereby lowering overall emissions.

In March 2014, Orlando submitted an application requesting to install and operate a calcium bromide (CaBr2) and activated carbon injection demonstration project at the Stanton Energy Center. The purpose of this project was to explore mercury mitigation measures by ACI testing and CaBr2 spray application to the coal to reduce emissions of mercury to meet the applicable Mercury and Air Toxics Standards (MATS) compliance standards. A permit was subsequently issued that authorized the test project.

The proposed demonstration project duration was authorized for 90 non-consecutive operational days. During the tests with ACI, mitigation of mercury by using the ACI system and applying CaBr2 sorbents was found to be effective. No detrimental effects on precipitator performance were observed. Therefore, this requested authorization is to allow for the permanent operation of the ACI system, as well as sorbents such as calcium bromide (CaBr2) to be applied to the coal. The ACI system will be engineered so as to be portable between Units 1 or 2, as needed.

Also, as requested in a letter to the department dated Oct. 14, OUC now proposes that the injection of halogen based additives (CaBr2) be followed by injection of sodium hydrosulfide (NaHS)—or equivalent, a sulfide-donating liquid agent, into the recirculating pumps of the wet FGD system. Halogen-based additives, which have been injected onto the coal during the current testing program, will oxidize mercury into mercury ions inside the boiler.

Since the mercury ions are soluble in water, NaHS will be injected into the WFGD, which will react with the mercury ions to create insoluble mercury sulfide (HgS) solids. The HgS may be emitted into the atmosphere along with the water droplets. However, WFGD has a mist eliminator to reduce the emission of water droplets and a conservatively low drift rate of 0.1 percent was used in estimating HgS emissions. Orlando will monitor mercury emissions during the testing period to determine the optimum feed rates of halogen-based additives and NaHS.

Based on engineering design data, OUC expects that all of these processes combined would provide adequate reduction in mercury emissions to meet the MATS standard of 1.2 lb per trillion British Thermal Units with sufficient margin. Therefore, OUC has requested authorization to conduct testing over a sufficient period of time to accumulate enough mercury data to determine what chemical feed rates are necessary to adequately reduce mercury emissions. The time remaining on the current authorization should be sufficient to accomplish the additional testing.

Phase 1 of the WFGD upgrades was previously completed and included the installation of a dibasic acid (DBA) chemical feed system and a forced oxidation system to improve scrubber performance. Installation of the DBA chemical feed system was covered under a 2007 permit, and the forced oxidation system was approved under another 2007 permit. Further scrubber upgrades were authorized to modify the spray nozzles and their arrangement and piping. Additionally, minor upgrades to the mist eliminator vanes and fixed grid wash system on the Unit 1 WFGD were authorized and installed under a 2010 permit. Another permit authorized additional upgrades (Phase 2) to the existing components of the WFGD system for Unit 1.

Phase 2 of the scrubber upgrades has been completed for Unit 1, and is now requested for Unit 2. Similar to Unit 1, this would involve installation of spray header modifications, along with possible gas/liquid contact devices such as dual flow tray and/or wall rings on the inside of the absorber to improve the contact of the slurry and the flue gas. These modifications were previously authorized for Unit 1. As was previously the case, these modifications are expected to reduce the emissions of the Unit 2 WFGD system and improve its reliability. In addition, the modifications will assist in meeting the MATS requirements.

To increase reliability of the WFGD system, Orlando had previously commissioned a study to evaluate improvements in SO2 removal capability for Unit 1. This study was performed by Black & Veatch with assistance from Wheelabrator Air Pollution Control Co. WAPC is a major supplier of WFGD systems. The study provided guidance on the most cost effective means to improve SO2 removal performance, mitigate process problems, and improve reliability.

Orlando is currently in the evaluation process to determine which WFGD vendor can provide the most cost effective upgrades for Unit 2, for meeting the new SO2 emission target of 0.2 lb/MMBtu (30-day average) and the exact nature of the FGD improvements necessary. The final upgrades will work in conjunction with the previous upgrades to reduce SO2 emissions. All of the absorber modifications being evaluated are essentially internal to the absorber and may be used alone or in combination with others depending on the optimized improvement approach developed by the selected vendor, the application noted.

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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.

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