SCR succeeds at Logan Generating Plant
Given the good SCR performance at the Logan Generating Plant, designers may want to seriously consider SCR when faced with increasingly stringent emissions regulations
By Paul Wagner, P.E., and Greg Cook, U.S. Generating Co.
As environmental requirements become more and more stringent, power plant owners continue to search for technology capable of dropping emissions levels even further. U.S. Generating Co. has found success with selective catalytic reduction (SCR) at three of its existing coal-fired plants, including Logan in southern New Jersey.
The Logan Generating Co. L.P. has successfully commissioned the United States` first full-scale, plate-type catalyst SCR for a pulverized coal-fired steam generating plant. The plant holds NOx emissions to 0.17 lb/MBtu (Figure 1) while maintaining less than 5 parts per million by volume, dry (ppmvd) ammonia slip with Foster Wheeler`s boiler package. The package includes low-NOx burners, overfire air inside the boiler and SCR after the boiler. Low-NOx burners and the overfire air system could not meet New Jersey`s stringent emissions requirements without adding SCR. The SCR system provides for denitrification of the flue gas by injecting ammonia into the flue gas in the presence of a catalyst which causes chemical reactions that convert the NOx to free nitrogen and water vapor.
The Logan Generating Plant is owned by the Logan Generating Co., an affiliate of U.S. Generating Co. The plant, previously named the Keystone Energy Service Co. L.P., is a 202 MW net coal-fired cogeneration plant located in Logan Township, N.J. Logan plant, engineered, procured and constructed by Bechtel Corp., began commercial operation in September 1994, six months ahead of schedule. The plant sells 200 MW of electricity to Atlantic Electric Co. and provides up to 50,000 lbs. per hour of process steam and 2 MW of electricity to the Monsanto Delaware River Plant.
Besides being equipped with an SCR system, the pulverized coal-fired plant includes a dry SO2 scrubber using quicklime and recycled fly ash reagents, and a reverse air fabric filter baghouse for particulate control. The plant is also a zero liquid discharge facility where all process and waste waters are recycled for reuse by using lime/soda ash softener and reverse osmosis technologies. Both the boiler and SCR system were designed and supplied by Foster Wheeler Energy Corp.
The steam generator burns low sulfur (less than 1.5 percent), Eastern bituminous coal from West Virginia, with an as-fired heating value of 13,200 Btu/lb. It produces 1.58 million lbs. per hour of 2,400 psig steam. The boiler utilizes 12 low-NOx burners which are front-wall fired and coupled with a front- and rear-wall overfire air system. Two pressurized ball-and-tube-type pulverizers pulverize and dry the coal. Each pulverizer supplies coal to six burners.
The combined use of low-NOx burners, an overfire air system and an SCR system minimizes NOx emissions from the stack, making Logan one of the nation`s cleanest coal-fired plants. The design for NOx emissions is 0.10 lb/MBtu. As stipulated by the New Jersey Department of Environmental Protection air pollution control permit, the stack emission rate limit is 0.17 lbs. of NOx per MBtu or 100 ppmvd corrected to 7 percent O2 dry on a three-hour rolling average. In addition, there is a stack emission limit for ammonia slip–10 ppmvd corrected to 7 percent O2 dry on a three-hour rolling average and 5 ppmvd corrected to 7 percent O2 on a 30-day rolling average. It is anticipated that additional catalyst will be required every three years to maintain the NOx emission limit and minimize slip.
The plant is operated by 64 full-time personnel, providing operations, maintenance and engineering support. Figure 2 shows the basic plant overview.
During the initial phases of the project, extensive work was done to procure the necessary air permits to satisfy both state and federal regulatory agencies. Regulatory officials recognized that SCR was being used successfully to control NOx emission in conjunction with low-NOx burners and overfire air. Therefore, they chose to impose the NOx limit at a level not previously applied to coal-fired power plants.
The main regulatory issues were:
z -Reconciling state policy of 0.10 lbs/MBtu with the lowest world standard (Germany) of 0.15 to 0.17 lbs/MBtu;
z -Preserving integrity of case-by-case, top-down analysis for the Logan and Carneys Point coal-fired projects (located 10 miles apart) but with different economic and operating parameters; and
z -Recognizing technical uncertainty and providing flexibility in the permit.
U.S. Generating originally considered using selective non-catalytic reduction (SNCR) to meet the emissions requirements. However, it decided the complex SNCR control system would affect startup and long-term operation of the plant. Complex ammonia injection grids and controls were necessary to match fluctuating furnace temperatures and maximize NOX conversion. Initial projections showed the plant would operate at reduced loads for significant periods of time and SNCR was not conducive to low loads or cycling operation. It also became obvious that the complexity of control piping and valves would cause significant operational and control problems. Therefore, the project management team decided to change from SNCR to SCR.
Logan`s SCR system description
Logan Generating Plant`s SCR system, shown in Figure 3, consists of an economizer bypass duct, ammonia injection grid, flow-turning vanes, flow rectifier, SCR reactor with catalyst and steam sootblowers.
The economizer bypass duct maintains a SCR inlet flue gas temperature above 610 F when the plant is operating at reduced loads. This minimum gas temperature must be maintained to prevent the formation of ammonium sulfate/bisulfate. The flue gas temperature must be above the minimum limit before ammonia can be injected.
The ammonia injection grid distributes and delivers ammonia gas to the flue gas stream. Ammonia vapor is generated with a carrier air stream and is injected into 18 flue gas zones. A combination of branch piping, manual valves and nozzles distributes the gas evenly across the flue gas directional plane. Balancing is achieved by monitoring individual zone vapor flow and adjusting manual valves.
Optimum design of the SCR requires proper distribution of the flue gas and ammonia vapor at the catalyst inlet. Two sets of turning vanes provide good flow distribution while minimizing gas-side pressure drop. Locations, number and geometric shapes of the vanes were determined by scale modeling flow tests.
Because of high dust loading associated with coal firing, the gas flow entering the catalyst layer is straightened by a flow rectifier made of square pipes. The inlet velocity, limited to 6 m/s, is in line with catalyst flow which minimizes catalyst erosion potential.
The reactor has three sections to support catalyst modules. Initially, the top and one-half of the middle layers were filled with catalyst for an initial volume of 184.7 cubic yards. Each layer contains 56 catalyst modules. The catalyst design was specifically selected for the specific coal being burned. Design considerations included catalyst pitch to prevent plugging; strength of material to prevent erosion; and a low SO2-to-SO3 conversion rate to prevent the formation of ammonium sulfate/bisulfate.
Rake-type sootblowers with multiple nozzles are installed above each module layer for cleaning fly ash accumulations from the catalyst surface. Superheated steam is utilized as the cleaning medium. The steam pressure is kept below 30 psig to minimize damage to the catalyst plates.
The plant utilizes aqueous ammonia with an ammonia content less than 27 percent by volume–less than the New Jersey Toxic Catastrophe Prevention Act limit. A 24,000 gallon storage tank provides storage capacity. Two 100 percent ammonia transfer pumps are used to transfer ammonia to the ammonia vaporization skid. The ammonia vaporization skid is comprised of two 100 percent capacity vaporization trains. Aqueous ammonia is pumped, metered and sprayed into the vaporizer. Ambient air, drawn by a blower and heated by an electric heater, enters the same vaporizer. The liquid ammonia solution is vaporized and routed to the injection grid via a distribution manifold system.
Continuous emission monitoring systems (CEMS) are located upstream and downstream of the catalyst reactor to measure the NOx inlet, NOx outlet and ammonia slip. Fine tuning of the ammonia injection rates were accomplished by monitoring CEMS data and fixed-grid sampling ports in these locations.
During its first year of operation, the SCR system performed very well. NOx and ammonia emissions were maintained under normal parameters. Subsystem deficiencies affecting the overall reliability of the SCR system were identified and remedied.
Ammonia storage and transfer problems were experienced during initial startup. The storage tank was not properly cleaned and it required additional filtering to remove debris from the tank. In addition, the ammonia transfer pumps were failing at the rate of one every three weeks. The main problem was determined to be improperly established recirculation pressure. The high pressure exceeded the relieving capacity of the pump`s internal relief valve causing excessive load on the gears and ultimate failure of the bearings. Once the ammonia pressure was reduced to 100 psig, pump failures stopped and reliability was restored.
Numerous problems were also experienced during the ammonia injection system startup phases. Dilution heater capacity and blower capacity were not adequate to maintain ammonia vapor temperatures above 250 F. During some of the initial tests, operation of both heaters was required to provide enough ammonia vapor. The heaters` kW capacity ratings were subsequently upgraded 32 percent to provide adequate ammonia while operating only one heater. Heater controls and breakers were upgraded to provide proper heating element sequencing. One of the upgraded heaters failed and required replacement after several months of operation. A newer version of the heater that provides a lower heat flux is now used. This new version uses smaller heating elements, but more of them. Another heater modification added more element bundle keepers, offering better element support during installation and operation.
Blower motors were also upgraded from 30 to 40 hp to compensate for limited motor amps. Electrical and blower valve modifications were implemented to allow both blowers to operate. Valves can now be oriented to allow the backup blower to provide additional capacity to reach the 1,800 cfm heater rating.
Due to deposits in the ammonia supply, the vaporizer and vaporizer outlet piping became plugged with white calcium-based deposits. The deposit built up to the point where 50 cfm of blower capacity was lost each day. During operation, the idle vaporizer vessel had to be isolated and steam cleaned to remove the deposits. With the injection system not operating, the vaporizers were cleaned with a hot water soak. The vaporizer outlet check valves were replaced with isolation butterfly valves to provide vaporizer isolation and minimize cleaning periods.
SCR reactor inspection
During the first annual plant outage (summer 1995), four catalyst sample plates were removed from the SCR reactor. For each sample, a neighboring plate was removed to preserve ridges and spacing. The plates were marked for flow direction and numbered.
The upper module`s protective screens (6 mm pitch) were covered with boiler “popcorn” slag, approximately 0.5 inches in diameter (12.7 mm). On the average, 10 percent of the surface area was covered with the slag, but as much as 30 percent of the surface area was covered on several modules. The excess slag was vacuumed from the top of the screens during the outage and slag samples were taken for analysis. The center module`s protective screens also had some slag on them, but not nearly as much as the upper module. The catalyst modules and surfaces were lightly dusted with fly ash, but there was no major accumulation of fly ash or slag on top of the catalyst plates. Plate edges were sharp with no rolled-over edges, and the flow rectifier was also in good condition.
In addition, all ammonia injection nozzles appeared open with no plugging. All reactor turning vanes appeared in good condition and SCR sootblower lances were normal.
Based on operating parameters and catalyst sample tests, an additional half layer of catalyst will be installed every 24,000 hours of operation, or approximately every three years. It is estimated that after three years, the slip will increase to 5 ppmvd.
Operating data compiled during the first year of operation proves Logan`s SCR system is successful. The data reveal that both NOx emissions and ammonia slip fall at or below state-permitted limits. Ongoing activities involve component inspections, furnace NOx optimization and performance monitoring to maximize catalyst life and minimize operating costs. z
Cho, M., D.P. Hannay, Foster Wheeler Energy Corp.; S. Kahn, Bechtel Corp.; S.R. Taylor, U.S. Generating Co.; “Operating experience of a selective catalytic reduction system for flue gas denitrification in a coal-fired cogeneration plant,” 1995.
Bechtel Power Corp., 100-hour performance test report for Logan Generating Plant, 1994.
Wagner, P.A., and J.G. Kelly, U.S. Generating Co., “Permitting and startup experience with the first SCR installed in the USA on a pulverized coal boiler,” presented at the Electrical Generation Association Environmental Conference, 1994.
Rummenhohl, V., STEAG Aktiengesellschaft; and J. Cochran, Black & Veatch, “Relating the German DENOX experience to U.S. power plants: lessons learned from more than 30,000 MW of DENOX retrofits,” presented to the ASME JPG Conference, 94-JPGC-PWR-52, 1994.
Foster Wheeler Energy Corp., Logan (Keystone) Instruction Manual for Boiler, Auxiliaries and SCR, 1994.
Weidinger, G.F., U.S. Generating Co., “Getting to know low-NOx burners and SCR,” ICAC Forum `94, 1994.
Cho, S.M., Foster Wheeler Energy Corp., and Dubow, S.Z., Bechtel Corp., “Design of a selective catalytic reduction system for NOx abatement in a coal-fired cogeneration plant,” presented at the Annual Meeting of the American Power Conference, 1992.
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