December 20, 2007

Three experts provided the 30 utility, A/E, supplier and other webinar attendees with insights on the impact of coal selection on the emissions.

Anupam Sanyal, International Environmental & Energy Consultants, Inc., was the lead off hitter with an overview. He divided emissions into four categories and listed the coal variables which will impact them as follows:

Impact of Coal Properties and Relevant Parameters on Particulate Emission

• Sulfur
• Ash Content & Chemistry
• Flyash Resistivity for Collection by ESP
• Coal Combustion & Unburnt Carbon
• Gas Temperature & Volume
• Flyash Sizing
• Coal Rank
• Impact of Slagging & Fouling

Impact of Coal Properties and Relevant Parameters on NO_x Emission

• Nitrogen Content
• Fuel Ratio (Fixed Carbon/Volatile Matter)
• HHV
• Moisture Content
• Fuel NO_x Indicator – Function of Fuel Ratio & Nitrogen in Coal
• Coal Combustibility – Function of HHV, Fuel Ratio and Ash Content
• Char Combustion Index – Function of Fixed Carbon & Moisture Content
• Impact of Coal Properties and Relevant Parameters on Secondary DeNOx
• S, Arsenic, Ash Chemistry, SCR Catalyst Composition & Management

Impact of Coal Properties and Relevant Parameters on SO₂ & SO₃ Emission

• Sulfur
• Excess Air
• Furnace Gas Temperature
• Ash Chemistry for Sulfur Retention
• Convective Pass Material of Construction and Gas Temperature

Impact of Coal Properties and Relevant Parameters on Mercury Emission

• Coal Rank and Mode of Occurrence
• FGD
• ESP
• Baghouse
• Mercury Adsorbents
• Coal halogen Content

Murray Abbot of Fuel and Furnace displayed results of a program which predicts the corrosion rate, NO_x, and opacity based on the use of various coals and blends. In answer to a question, Murray said that chlorine content was not an important variable in corrosion but that other constituents were.

Bill Rafferty of Clyde Bergemann talked about intelligent soot blowing as a way to improve performance with a variety of coals. The SmartClean ISB System takes into account a number of parameters with the following potential improvements.

• Increase Load

·        Eliminate pluggage resulting from “under-cleaning”

·        Reduce tube leaks caused by “over-cleaning”

• Increase Boiler Efficiency

·        Intelligent heat transfer surface management

• Reduce Thermal NO_x Formation

·        Improved furnace heat transfer

• Reduce CO₂ & SO_x Emissions

·        Reduced heat rate
 

• Reduced Opacity Averages

·        Managed ash removal rates
 

• Increased Fuel Variability

·        Intelligent heat transfer surface management

Links to the above presentations will be added to the Decision Tree in the next few weeks.

Mercury CEMS are Installed at Most Plants and Performance is Being Demonstrated

The industry has come a long way in a short time to develop reliable mercury CEMS. There are still remaining issues but some 25 systems are already proving the technology.

The first speaker at the December 20 ^th Mercury Hot Topic Hour was Chuck Miller of DOE NETL. The papers presented at the DOE mercury conference last week will be posted on the NETL website in January. NETL does not have additional funding for mercury research. But with the effort to date there are a variety of technologies available. Sorbent injection could cost from $10,000 to $45,000/lb of Hg removed. A mercury catalyst can convert 70 percent of the elemental mercury to the oxidized form for a cost of $5000-$20,000 /lb of mercury removed. Mercap, as a polishing technology, can remove 35 to 45 percent of mercury across gold-coated plates. Overall coal-to-stack Hg removal on bituminous coal-fired units can range from 53-97 percent depending on the APC equipment. Removal on other coal-fired units would be less.

Scott Hedges of EPA updated us on the regulations. The Part 75 rule modification package was signed by the Administrator on December 19 and the rule will become final upon publication in the Federal Register (expected within two to three weeks). This includes

• A “re-engineered” Part 75 data collection and processing system incorporating a user-friendly XML format
• Minor technical/procedural changes to Subpart I of Part 75 (Hg Mass Emission Provisions) including adding multiple/common stack heat input procedures
• Reference Method 29 proposed as an alternative Ontario Hydro reference method.

There has been a postponement of the date when the elemental and oxidized Hg gas traceability requirements become mandatory to January 1, 2010. This does not change the requirement for installing and certifying mercury monitoring systems (including conducting the required calibration error tests, linearity checks, and system integrity checks) by January 1, 2009.

EPRI/NIST/utilities/vendors and others will participate in a field demonstration program in 2008 that will collect data needed to finalize the traceability protocols. Key elements of the demonstration program will include:

• An assessment of the field performance of elemental and oxidized Hg generators
• An evaluation of the stability of elemental Hg compressed gas cylinders

Based in part on demonstration program results, EPA expects to finalize the elemental and oxidized Hg traceability protocols by December 31, 2008.

Sharon Sjostrom of ADA-ES took time out from her Arizona vacation to report on the state of the art. She observed that upgrades to Thermo systems have significantly improved low concentration performance. The ADA-ES M30A instrumental reference method system can perform RATA testing with HgCl₂ system integrating checks and dynamic spiking. It has the ability to traverse the stack and provide real-time feedback using the ThermoFisher analyzer and calibrator. It has been a noteworthy achievement to obtain optimal performance with this portable system.

Michael Corvese of ThermoFisher advised users that prior to the traceability standard, sorbent trap testing should be used in conjunction with RATAs to verify calibrator output. ThermoFisher has now shipped over 300 mercury CEMS systems. Eighty-five systems are installed and operational. Twenty-five systems have met performance criteria. Seventy-five percent of the boiler units have ThermoFisher mercury CEMS.

Links to the above presentations will be added to the Mercury Decision Tree in the next few weeks.