Catalytic Ocidation of NO in Flue Gas for Capture in Wet Scrubbers

INTERIM FINAL TECHNICAL REPORT

November 1, 1998, through October 31, 1999

Project Title: CATALYTIC OXIDATION OF NO IN FLUE GAS FOR CAPTURE IN WET SCRUBBERS

ICCI Project Number: 98-1/1.1E-1

Principal Investigator: Gary A. Robbins, CONSOL Inc., Research & Development

Project Manager: Ronald H. Carty, ICCI

ABSTRACT

CONSOL R&D, the research arm of Consolidation Coal Company, which mines about 5 million tons of Illinois coal each year, began development of technology that is expected to result in cost-effective NOx removal by wet flue gas desulfurization (FGD) scrubbers. Wet FGD is the preferred technology for removing sulfur dioxide generated during the combustion of high- and medium-sulfur Illinois coal in the production of electric power. In this work, catalysts will be identified that oxidize NO to NO₂ for more efficient capture in wet scrubbers, and the cost of using this technology will be evaluated. It is expected that this technology will cost less than competing technologies for NOx reduction. Utilities will face increasingly stringent emission regulations for NOx by the year 2005. Successful commercial development of this technology by 2003 would help to preserve the market for medium- and high-sulfur Illinois coal. Project background and objectives are provided in the report.

Work conducted during the report period consisted of: (1) completion of the catalyst test unit construction; (2) completion and approval of operating procedures, safety review, and operator training; (3) start-up of the unit with a catalyst blank; and (4) correcting start-up difficulties.

EXECUTIVE SUMMARY

Because the current NOx control technology is costly, CONSOL R&D began laboratory development of a low-cost alternative NOx control method. This technology would be used with existing or new wet flue gas desulfurization (FGD) scrubbers. The overall project goal is to commercialize, by the year 2003, a low-cost alternative NOx control method suitable for use on coal-fired utility boilers that can achieve 65 µg/MJ (0.15 lb/MMBtu) NOx emissions. In 2004, additional NOx control is expected when the recently revised NOx SIP regulations set the framework for NOx emissions limits. The process being developed by CONSOL is based on catalytic oxidation of NO to NO₂. At typical flue gas conditions downstream of the boiler economizer, most of the NOx (>95%) is NO. The residual oxygen (3% to 6%) in the flue gas is the oxygen source. NO₂ is more soluble in aqueous solutions than NO. An existing flue gas desulfurization (FGD) wet scrubber can remove the NO₂. The catalyst can be placed upstream of the air heater section, downstream of the air heater but upstream of the particulate collector, or downstream of the particulate collector. A desirable characteristic of the catalyst is that it minimize the oxidation of SO₂ to SO₃. Based on equilibrium calculations, 60% to 95% removal of NOx is possible, but testing will be required to determine the actual NOx removal efficiency. The process can be used in combination with combustion modification to control NOx emissions (i.e., low-NOx burners). The process requires a relatively small capital investment to achieve high NOx removal.

This technology will promote the use of wet FGD scrubbers for combined NOx and SOx control. This will benefit the use of medium- to high-sulfur coals, such as those produced by the Illinois coal industry, by preserving or expanding their markets.

The planned research activities include:

Task 1 (in progress) - A catalyst screening program to identify a catalyst capable of oxidizing at least 50% of the NO to NO₂ while oxidizing less than 5% of the SO₂ to SO₃ under typical coal-fired flue gas conditions. A catalyst test unit was constructed that uses simulated flue gas. The unit was completed and started up during the report period. A major catalyst manufacturer will prepare and provide about ten candidate catalysts for evaluation in this program. Three catalysts have been provided for initial testing.

Task 2 - Extended catalyst testing to simulate boiler cycling and observe catalyst deactivation.

Task 3 - A process economic evaluation to estimate the process economics, identify significant cost areas for process improvements and cost reductions, and evaluate options for process scale-up.

The catalyst test unit is built around a tubular quartz reactor that is wrapped with heating tape and temperature controlled. The honeycomb catalyst samples to be tested will be 1 in. dia. x 4 in. long. The catalyst test unit design conditions were 300-600 F, 10,000-60,000 hr^-1 space velocity (std L/hr gas flow per L catalyst bed volume) of simulated flue gas containing 100 - 1000 ppmv NO, 1000 - 3000 ppmv SO₂, 3 - 7 vol % O₂, 10 - 14 vol % CO₂, 4 - 8 vol % H₂O, and the balance N₂. For this range of space velocity, and the catalyst bed volume chosen, the combined flow (including water vapor) of simulated flue gas will be 8.6-51.5 SLPM. Gas will be fed from the plant nitrogen supply and gas cylinders using mass flow controllers to meter the gases into the mixing and preheat zone prior to entering the catalyst reaction zone. Exit gas will be analyzed using continuous NO/NOx and SO₂ analyzers; SO₃ yield will be calculated from any change in the SO₂ concentration, and confirmed using a manual batch sampling method for SO₃. Catalyst tests will be run until steady-state conditions are achieved as indicated by gas analyzer data.

The test strategy is to screen all catalysts at one test condition, and select the best ones for more extensive testing. The conditions chosen for the screening test were 600 F, 10,000 hr^-1 space velocity, 1000 ppmv NO, 2000 ppmv SO₂, 5 vol % O₂, 12 vol % CO₂, and 6 vol % H₂O. During the extensive test program, the space velocity and temperature will be varied at several levels, two levels will be used for the SO₂ and NO concentrations, and the concentrations of H₂O, O₂ and CO₂ will be tested at only one level.

The catalyst test unit consists of five subsystems: (1) The gas supply and mixing subsystem provides inert gas (nitrogen from the plant supply) for reactor start-up and shutdown, inert gas (nitrogen from the plant supply) for the balance of the simulated flue gas, and CO₂, O₂, SO₂, and NO from cylinders to produce the simulated flue gas. Special features provide for safety of personnel and equipment. (2) The humidification/gas preheat system consists of metered water injection into the gas stream, followed by evaporation and preheating to approximately 230-260 F through a coil in an oil bath. (3) The reactor system consists of a custom tubular quartz reactor in three sections; two sections are heated and one is cooled. In the first section, the simulated flue gas is preheated to reaction temperature, 300-600 F. The second section contains the catalyst, and the third section cools the gas to about 300 F at the reactor outlet. (4) The flue gas conditioning and analysis system provides reactor effluent gas drying, pressure control, and gas analysis for NO/NOx, SO₂, CO₂, and O₂. (5) The data recording system logs data, including mass flow rates of component gases, temperatures of the reactor zones, and the concentrations measured by the gas analyzers.

Construction of the catalyst test unit was completed. The data recording system was completed for operation without computer logging. Integrated testing of the humidification, preheating, and reactor systems was conducted. Several equipment problems were identified and corrected during the integrated system start up. Failure and re-start modes of several components were evaluated as part of the safety considerations. Materials were obtained, and specific procedures were set up for area monitoring for NO and SO₂ using color indicator tubes. Three catalysts to be tested were received from the catalyst manufacturer.

The unit operating manual and safety review were approved, allowing the unit to be run with NO and SO₂ in the simulated flue gas. A catalyst blank test was delayed by equipment failures and contamination that seems to originate from the NO cylinder. We will complete catalyst blanks and begin running catalysts as soon as these problems are resolved. Because of the delay in starting up the catalyst test unit, a three-month extension of the project was obtained.