Paper presented at the Power Gen ‘96, Orlando, December 4 - 6, 1996

Post-combustion NOx control technologies available to reduce emissions from fossil fueled power plants include selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) systems. An additional post-combustion NOx emissions control strategy is the hybrid combination of SNCR and SCR.

In 1987 OKA (Oberösterreichische Kraftwerke AG) reduced the NOx emissions of its lignite-fired Riedersbach Unit 2, Upper Austria, using air staging and flue gas recirculation by 50%. In 1988 NOx emissions in this power plant were further reduced by 30% - 50% with a combination of combustion modifications and SNCR technology, that is, a urea-water-solution is injected into the boiler using overfire air or recirculated flue gas as carrier medium. The overall NOx removal efficiency is 60% - 75% compared to 1987 levels.

Because of fuel switching from lignite to hard coal, an additional technology was necessary to control the ammonia slip contaminating the FGD effluent. OKA decided to install SCR-catalyst material within the boiler itself. The main purpose for this catalyst is to reduce the ammonia slip coming from the SNCR system. In addition, to meet the ammonium emissions limit in the FGD effluent, an improved NOx reduction efficiency is required.

As this approach to overall high efficiency and low-cost NOx control does not require space for a stand-alone SCR reactor, it is an opportunity especially suited to those power plants which have to be retrofitted under restricted space conditions.

The novelty of the SCR application is the arrangement of catalysts, so that the fly ash laden flue gas passes the catalysts in an upward direction. It is the first application of its type in the world.

Equipping German hard-coal power plants with catalysts for nitrogen oxide reduction was one of the most successful environmental protection measures of the last decade, reducing the fraction of total emissions due to power plants to less than 10% [Fig. 1]. from pre 1985 levels. In Austria, NOx emissions were restricted in 1988 by the clean air act for plants as a function of their thermal power output. Plants with 300 - 500 MW were restricted to 300 mg/m³_stp, and larger boilers to 200 mg/m³_stp.

In response to this, primary measures were taken to reduce the formation of nitrogen oxides in the combustion process. With the exception of lignite combustion systems, it was not possible to meet the strict limits with primary measures alone. The first secondary measures to result for hard coal-fired boilers were full-scale SCR systems. In these systems, the nitrogen oxides are transformed to water and nitrogen by selective catalytic reduction (SCR) with ammonia over a catalyst surface.

At the time this technology was introduced in Europe about 10 years ago, there were still uncertainties about the process and operational reliability of the SCR units and their effects on overall power plant operation. Since then, the behavior of SCR catalysts has become well known for various flue gas conditions and configurations. In the USA, plant manufacturers and operators as well as catalyst manufacturers are in a similar situation to that prevailing in Europe ten years ago. In the USA, as in Europe, test programs were first carried out to determine whether European experience could simply be adopted or whether special plant conditions required special solutions. For example, catalysts were installed in the flue gas ducts of in-duct SCR plants. A DeNOx air preheater was also tested. Finally, a combination of the various systems, known in the USA as hybrid SCR, has been constructed and tested for nitrogen oxide reduction.

The test programs are now essentially complete. Operating experience gathered to date is positive.

Five different plant concepts are included under the general heading of hybrid SCR:

• The combination of SNCR-technology (Selective Noncatalytic Reduction) with a downstream SCR catalytic reactor which reduces ammonia slip from the SNCR unit. Under favorable conditions, this catalytic reactor can be incorporated into the boiler, as in the Riedersbach power plant operated by the Oberösterreichische Kraftwerke AG. This example will be examined more closely below.
• The combination of an SNCR unit with a DeNOx air preheater, where the DeNOx air preheater is used to reduce ammonia slip.
• The combination of SNCR-technology with in-duct SCR, where the ammonia slip from the SNCR unit is used as a reducing agent in the in-duct SCR section. If necessary, ammonia can also be injected upstream of the SCR system.
• The combination of an in-duct SCR plant with a DeNOx air preheater, with ammonia injection upstream of the in-duct SCR section.
• The combination of SNCR with in-duct SCR and a deNOx air preheater.

Fig. 2 shows the installation locations for the various solutions in a simplified power plant schematic. Not shown are the conventional configurations of a deNOx reactor between the boiler outlet and air preheater (high-dust configuration) or between the electrostatic precipitator and the stack (low-dust configuration). However, combinations of some Hybrid SCR arrangements or all of these individual systems were not used in past years in Germany or Austria. This is due to the high separation efficiency required to achieve the NOx emissions limits. To date, legislation in the USA has not been oriented to the high efficiencies proven to be attainable with conventional SCR technology.

The power plant operators in the USA are given more freedom to select a technology. This opens the possibility for individual power plants to implement various measures such as the hybrid systems listed above.

Of course the use of one or another variant must be justified by comparing its advantages over classic SCR technology [Fig. 3].

Advantages of Hybrid-SCR plants can be:

• Low retrofit requirements in existing power plants. For example, changes in the flue gas ducting, air preheater relocation or the installation of a reinforced or new air fan are not necessary.
• Minimal impacts on unit draft loss, resulting in considerably lower operating costs.
• Minimizationof ammonia slip with simultaneous and relatively high NOx removal efficiencies.
• Operating flexibility due to selective activation of DeNOx-subsystems as a function of boiler load.

However, disadvantages must be considered as well. These are:

• The implementation of the various DeNOx-technologies results in increased complexity of the overall system, resulting, for example, in more difficult operation and maintenance. The control requirements are more stringent than for a classic SCR plant due to adaptation to the interactions of various DeNOx-systems.
• As for an SNCR plant, the consumption figures in a hybrid SCR plant are the deciding cost factor, as the ammonia or urea is used with higher stoichiometric ratios.
• Reserve catalyst layers are not possible if the volume of the in-duct SCR section has to be minimized. The disadvantage is that a reloading strategy for optimal utilization of the remaining catalyst activity is not possible.
• Only half of the installed volume of catalyst is used in DeNOx air preheaters, as one half of the catalyst is always on the air side. As no reserve layer is possible here either, the catalyst volume in the air preheater must be exchanged once the minimum activity level has been reached.

To date, the following hybrid SCR systems have been installed:

• San Diego Gas & Electric, USA
  Encina Power Plant. Unit 2
  Fuels: Gas and oil
  SNCR + in-duct SCR + DeNOx air preheater
  
• Southern California Edison, USA
  Mandalay Power Plant, Unit 2
  Fuels: Gas and oil
  SNCR + DeNOx air preheater
  
• Public Service Electric & Gas, USA
  Mercer Station Power Plant. Unit 2
  Fuels: Hard coal and gas
  SNCR + in-duct SCR + DeNOx air preheater
  
• Oberösterreichische Kraftwerke AG, Austria
  Riedersbach power Plant, Unit 2
  Fuels: Hard coal, lignite and oil
  SNCR and SCR integrated into the boiler.

The Riedersbach project in the Oberösterreichische Kraftwerke AG (OKA) will be examined more closely below.

The Riedersbach 2 power plant, a 160 MW unit, was first designed for simultaneous firing of lignite and hard coal or oil. The boiler schematic is shown in Fig. 4. The boiler is a two-pass unit with dry ash removal and the heat exchanger surfaces are all located in the first pass. Initially, typical NOx-emissions were 600 - 700 mg/m³_stp in this plant when fired with high-ash austrian lignite (SAKOG).

The combustion temperatures in pulverized lignite firing systems are generally so low due to the high ash content or the high water content in the coal that most of the nitrogen oxide emissions are caused by the formation of fuel NOx. Operating experience with pulverized lignite firings has shown that the level of the measured NOx emissions can be only slightly reduced by lowering the combustion chamber temperature. Significant reductions in NOx emissions cannot be achieved until the air ratio in the main burner area is reduced.

The engineering concept for NOx reduction in lignite firing systems can be implemented through primary measures in different ways depending on the type of boiler construction. However, all technical solutions will have the following common characteristics:

• Lowest possible air stoichiometry at combustion chamber outlet
• Hypostoichiometric air near main burners
• Main combustion zone situated as low as possible to obtain sufficient distance for NOx-reduction
• Stable ignition with high degassing temperatures at main burners despite operation with hypostoichiometric air
• Lower temperatures in the nitrogen oxide reduction zone
• Thorough mixing of flue gases in the reduction zone
• Sufficient residence time of flue gases in the reduction zone
• Thorough mixing of overfire air to ensure sufficient reduction of CO levels downstream of the reduction zone.

These measures have proven themselves on various designs of steam generators and in firing of various lignites. The results of the staged air combustion are given qualitatively in the NOx emissions as a function of stoichiometry in the burner area, shown in Fig. 5.

The combustion modifications of the firing system in the 160 MW Riedersbach 2 unit performed by OKA over the years 1987 to 1989 to reduce NOx emissions are shown in

Fig. 6. This firing system is based on the following parameters:

• Air stoichiometry in the burner area 0.8 - 0.9
• Air stoichiometry downstream boiler 1.2 - 1.25
• 1st level of overfire air 10% of total air flow (uppermost oil burner level)
• 2nd level of overfire air 20% of total air flow
• Recirculated flue gas 15% of flue gas downstream of electrostatic
  precipitator

The use of all NOx-reducing primary measures in this boiler system enabled the achievement of NOx emission levels of 300 - 350 mg/m³_stp. in simultaneous firing of 80% lignite and 20% hard coal. This is a NOx reduction of approximately 50%.

It should be pointed out that the NOx emission levels of every power are subject to considerable fluctuations, at least +/-10%, in spite of the best flue gas analysis, measuring and control technology. Among other things, the causes for these fluctuations are:

• Routine change of mills
• Operating conditions of the individual mills with their influence on grinding fineness
• Fluctuations in fuel composition, resulting in varying degrees of fouling of the heat exchanger surfaces
• Load gradients
• Soot blowing of heat exchanger surfaces during operation.

Although NOx reduction by primary measures represents the cheapest and most widely used technology, the delayed combustion process caused by the modifications can lead to the following operating problems:

• Impairment of ignition stability
• Increase in unburned carbon in the fly ash
• Corrosion of heat exchanger surfaces
• Influencing of downstream flue gas desulfurization process due to changes in oxygen concentration and flue gas temperature.

Additional measures were required at Riedersbach 2 to achieve the target half-hour averages of 200 mg/m³_stp in lignite/hard coal simultaneous firing.

After combustion modifications, the most inexpensive technology for further NOx reduction is found in SNCR processes. In the process developed by OKA, NOx is reduced by the combination of combustion modifications and an SNCR technique for reducing NOx. This method involves the indirect injection of a finely atomized urea/water solution into the combustion chamber using overfire air or recirculated cold flue gas as carrier medium. Fig. 7 shows a process flow diagram of the SNCR test system in the Riedersbach 2 power plant, planned in 1987, as well as the configuration of the cold gas and overfire air nozzles on the boiler. The first overfire air level is not shown. The plant was improved repeatedly, supplemented with equipment for producing urea solution from solid urea and modified to form a DeNOx-system with the same availability as the boiler. Fig. 8 shows the configuration of a urea lance in an overfire air branch line. A computer simulation was used to model and optimize the mixing behavior of the urea droplets in the flue gas.

The following operating parameters were achieved with this plant in 1989:

• Adherence to the NOx-concentration of 200 mg/m³_stp over the entire load range (calculated as NO₂ at 6% O₂, half-hour average) in lignite/hard coal simultaneous firing
• NH₃ / NOx stoichiometric ratio of 1.0 - 1.7 as a function of load
• Control of ammonia slip upstream of air preheater as a function of load and stoichiometric ratio to between 0.1 - 1.0 mg/m³_stp resulting in ammonia content of fly ash: approx. 50 mg/kg
  The ammonium content in the effluent of the downstream flue gas desulfurization plant (FGD) varied between 4 and 10 mg/l in 4 - 7 m³/h effluent.
• Steam consumtion maintained at 1 -2 t/h

The total DeNOx efficiency of the primary measures and SNCR technology is 60 - 75% from 1986 levels. The DeNOx costs of this process developed by OKA are approx.

20 - 35% of those for full-scale SCR systems.

As a result of the unexpected closing of the brown coal supply mine, the simultaneous firing system of the boiler had to be modified in the summer of 1994. It is now possible to achieve 100% load with hard coal, or 40% with lignite or oil. The combination of combustion modifications and noncatalytic NOx reduction enables adherence to a NOx emission limit of 300 mg/m³_stp in operation with 100% hard coal.

The ammonia slip was changed noticeably by the slightly higher NOx formation rates in hard coal operation and the massive reduction of ash content in the flue gas to less than 20% at roughly constant urea dosing. The ammonia slip upstream of the air preheater increased from 0.1 - 1.0 mg/m³_stp to 1 - 6 mg/m³_stp. This level resulted in tolerable ammonia concentrations of < 100 mg/kg in the fly ash. However, the ammonium emission limit of 10 mg/l in the FGD effluent was exceeded.

OKA decided to control the SNCR ammonia slip with SCR catalytic reactors. The NOx content of approx. 250 - 270 mg/m³_stp in the flue gas downstream of the SNCR and upstream of the SCR now acts as a reactant.

Siemens plate-type catalysts with a pitch of 6.1 mm and a specific geometric surface area of 320 m²/m³ were installed, Fig. 9. Plate-type catalysts was selected because of the very successful operational history in Germany. The catalyst elements are combined in modules of eight each in two superimposed levels. The modules, with dimensions of 956 x 956 x 2000 mm are designed for three-layer charging, thus providing space for later reloading.

The boiler area immediately upstream of the transverse section was selected for installation [Fig. 10]. The inlet velocity is approx. 6.5 m/s at temperatures of 300 - 330  C. A support grid for the 80 catalyst modules was installed there [Fig. 11]. The flue gases passes the catalyst plates from bottom to top. This is a first for a high-dust configuration of this type.

The catalytic reactor has been in successful operation for 5000 hours. The ammonia slip downstream of the catalytic reactor is so low that it cannot be reliably measured in the flue gas, while the ammonia entrainment in the FGD effluent has decreased to 4 - 6 mg/l. The ammonium emission limit of 10 mg/l can be adhered to reliably. Clogging or erosion of the catalyst has not been observed to date. For safety reasons, a permanent steam sootblowing system was installed below the catalyst on the upstream side of the catalytic reactor . These steam soot blowers are operated once weekly with superheated steam at a pressure of 4 bar. An increase in pressure drop across the catalytic reactor has not been observed. For reasons of availability, it was not tested whether periodical sootblowing is actually required.

In summary, it can be stated that retrofit hybrid SCR units may offer advantages over conventional SCR units for certain units, considering required NOx reduction and existing plant conditions. In various plants it has been demonstrated that SIEMENS catalysts are reliable tools to build up high performance hybrid systems as well as conventional full-scale SCR units.

This type of application requires unique engineering to assure that the design and operation of a hybrid system, is, as at Riedersbach, the appropriate NOx reduction solution.