Boilers

SCR Performance

As a result of the Cross-State Air Pollution Rule (CSAPR) and the Ozone National Ambient Air Quality Standard (NAAQS), utilities such as Duke Energy are faced with the need to achieve further reductions in annual and ozone-season NOx emissions. 
At Duke Energy’s Gibson Generating Station in Owensville, Indiana, SBS Injection® technology has been used for SO3 control on all five units since 2005. Photo courtesy: AECOM

SO3 Mitigation to Reduce Emissions & Operating Costs

By Sterling Gray, Jim Jarvis, Chad Donner and Josh Estep

As a result of the Cross-State Air Pollution Rule (CSAPR) and the Ozone National Ambient Air Quality Standard (NAAQS), utilities such as Duke Energy are faced with the need to achieve further reductions in annual and ozone-season NOx emissions.

Consequently, utilities must develop ways to maximize the value and performance of their SCR system equipment. Two strategies that can cut NOx emissions include boosting the percentage NOx reduction efficiency during periods of higher-load operation and developing the ability to keep their SCR systems in service during reduced-load operation.

Implementation of these strategies is hampered by the presence of SO3 in the flue gas. During higher-load operation, SO3 produced in the boiler and by the SCR catalyst itself forces operation with low ammonia slip levels (typically 2 ppm or less) to avoid air heater fouling from ammonium bisulfate (ABS) deposition. Although many variables are involved, the ammonia slip constraint effectively caps the NOx reduction efficiency for a given SCR system configuration. Similarly, ABS deposition within the catalyst due to “capillary condensation” dictates the minimum operating temperature (MOT) for the SCR system and, therefore, the minimum reduced-load operating condition where ammonia can be injected for NOx reduction. The ability to operate a unit at the lowest possible load – with the SCR in service – helps minimize losses during periods of negative power pricing. This allows the unit to be dispatched and avoids operating costs associated with unit start-ups and shutdowns.

SO3 removal upstream of the air heater, and ideally upstream of the SCR reactor itself, is becoming an increasingly important part of both the higher- and reduced-load strategies for reducing NOx emissions. For higher-load operation, the concept is to reduce SO3 to very low levels at the air heater inlet. This relieves the constraint on ammonia slip because there is not enough SO3 available to form appreciable amounts of ABS in the air heater. With the ammonia slip constraint relaxed, modest increases in ammonia slip are possible, which allows the NOx reduction efficiency to be increased.

If a reduction in NOx emissions is not necessary for environmental compliance, then an alternative approach for implementing an elevated ammonia slip strategy is to instead operate the SCR reactor at a lower average reactor potential. This might be accomplished, for example, by operating with two catalyst layers instead of three, or alternatively, through less frequent catalyst replacement. Over time, these approaches result in a lower catalyst consumption rate and an appreciable reduction in life-cycle catalyst costs.

The ability to operate with elevated ammonia slip and without air heater fouling is also helpful when there are local variations in the ammonia-to-NOx ratio at the SCR inlet. These variations might occur due to variations in the local NOx concentration, an inability to fully “tune” ammonia injection, variations in local gas flow, etc. When these conditions exist, it may be more cost-effective for the utility to control air heater fouling by reducing SO3 rather than ammonia slip. The lack of air heater fouling has been demonstrated at plants using the SBS Injection process for SO3 mitigation during both short-term testing and longer-term operation at slip levels well above 2 ppm.

Minimum SCR Operating Temperature versus Flue Gas SO3 Concentration – 1

Pre-SCR SBS Injection as Implementd on Unit 5 at Gibson Generating Station – 2

Indeed, the ability to tolerate elevated ammonia slip or to adopt an elevated ammonia slip operating strategy may more often be constrained by the presence of higher ammonia levels in the water and scrubber solids streams than by air heater fouling.Reducing SO3 to very low levels also helps minimize ABS condensation within the SCR catalyst when operating at reduced-load (low temperature) conditions.

With less SO3 present, the MOT decreases, which allows the SCR system to stay in operation at lower-load conditions where ammonia injection would not otherwise be possible.

Duke Energy employs both dry and wet sorbent injection technologies at their plants for SO3 control.

At Duke Energy’s Gibson Station in Owensville, Indiana, the SBS Injection® technology has been used for SO3 control on all five units since 2005.

In the period between 2009 through 2014, the plant relocated the sorbent injection equipment from downstream of the air heater to upstream of the SCR reactors. As the equipment on each unit was relocated, this “pre-SCR” SO3 mitigation capability was used to expand the operating range of the SCR reactors to keep ammonia injection in service at lower loads.

Duke Energy recently performed testing to further leverage this capability to allow even lower-load operation of the SCR reactors while maintaining high NOx reduction efficiencies.

This testing included a bench-scale evaluation, conducted by the SCR catalyst supplier, and on-site testing incorporating the operation of both the SCR and SO3 mitigation systems.

Although Duke Energy has an interest in operating at higher percentage NOx reduction efficiencies (via elevated ammonia slip operation), the primary focus of the testing was directed towards enhanced operation of their SCR systems at very low load conditions.

The results of the testing were favorable, and Gibson Station has again revised their SCR system operating guidelines. The new guidelines allow full ammonia injection (85 percent NOx reduction efficiency) at lower loads than ever before. Duke Energy’s goal is to maximize the value of their emission control system investments to meet ever-changing emission control and economic challenges.

The Minimum Operating Temperature Issue

The presence of SO3 in the flue gas often dictates the minimum operating temperature (MOT) of the SCR system during reduced-load operation. When SO3 is present, the reactor temperature is typically maintained above the minimum operating temperature when ammonia is being injected to avoid ABS condensation within the catalyst pores. In practice, the reactor can be operated below the MOT for short periods of time if these periods are followed by operation at higher reactor temperatures. Nonetheless, operation below the MOT has the potential for both short-term and long-term impacts to catalyst performance.

The consequences of an MOT limitation can be significant. If the minimum load with the SCR system in service is higher than the minimum load for the boiler, then power producers may be forced to operate at higher than desired loads during periods of low or negative power pricing, just to keep the SCR systems in service. In some cases, operating costs may increase due to unit shut down and startup costs, or the unit may even be idled. With the trend towards reduced capacity factors for many coal-fired boilers, the ability to keep the SCR system in service at the lowest-possible load conditions is a significant economic benefit.

Evolution of SCR Operation and NOx Reduction Goals for Gibson Unit 1 – 3

Full-Scale Test Results from Unit 1 at Gibson – 4

The minimum operating temperature for SCR catalyst is a function of the concentrations of both ammonia and SO3, and the tendency for ABS formation within the catalyst is the greatest near the inlet of the SCR where the ammonia concentration is the highest. Figure 1 depicts the relationship between the minimum operating temperature and the concentration of SO3 in the flue gas. The relationship is a function of many variables, including the SCR inlet NOx concentration, the desired percentage NOx removal, the type of catalyst, and other variables; thus, the minimum operating temperature is shown as a range in Figure 1. However, the figure illustrates a key point – the minimum operating temperature can be significantly reduced if the SO3 can be reduced to very low levels. Thus, SO3 mitigation upstream of the SCR reactor allows full or at least partial NOx reduction at significantly lower boiler loads relative to what would be possible without SO3 mitigation.

In theory, SCR performance enhancement should be possible through SO3 reduction via either wet or dry sorbent injection. Duke Energy has both types of systems and is exploring the benefits available through SO3 reduction at the air heater inlet and/or SCR inlet. In the case of the SBS Injection technology, the process can be installed at locations along the flue gas path from the economizer outlet to scrubber inlet. However, most of the recent installations have been installed upstream of the SCR, and at the present time, the process has been applied at the pre-SCR location on 14 units. In many of those applications, minimum operating temperature was a factor in selecting the injection location.

In the pre-SCR configuration, the reagent injected upstream of the SCR is intended to control the boiler SO3, as well as the SO3 produced by the SCR catalyst. At the inlet to the SCR, however, only the boiler SO3 is present. Consequently, the concentration of the reagent is very high relative to the concentration of the SO3, and the SO3 concentration at this critical location can be reduced to very low levels. As shown in Figure 1, this is exactly what is needed to achieve significant reductions in MOT.

Reduced-Load SCR Performance Enhancement

Duke Energy’s Gibson Station consists of five, 675MW units firing 4 to 6 lb/mmBtu coal. Each unit is equipped with a high-dust SCR system (3 catalyst layers), horizontal-shaft air heaters and cold-side ESPs. In 2005, the plant installed the SBS Injection SO3 mitigation technology downstream of the air heaters on all five units. In the period from 2006 to 2008, work sponsored by a consortium of utilities demonstrated the feasibility of injecting sodium-based reagents upstream of the SCR. Based on the favorable results from this testing, Gibson elected to move the reagent injection location upstream of the SCR reactors on Unit 5. Figure 2 shows a diagram of the SCR system on Unit 5. On this unit, the Par Mixers that were originally part of the SCR system design were removed to make room for the SBS system injection lances. Similar conversions were implemented on the remaining units, and the final conversion was completed in 2014. All five units are now operated in the pre-SCR configuration with soda ash reagent injection upstream of the SCR reactors.

Once the conversions were completed, Gibson used the pre-SCR SO3 mitigation capability to operate the SCR’s with ammonia in service at lower loads and temperatures than were permitted prior to the conversions. For example, prior to the relocation on Unit 1, the SCR system was operated at the design minimum operating temperature was 622°F. After relocating the SO3 mitigation system to the pre-SCR location, a phased injection approach was implemented:

  • 85% NOx reduction at temperatures down to 580°F;
  • 50% NOx reduction at temperatures down to 570°F; and
  • 25% NOx reduction at temperatures down to 550°F (about 250 MW).

This strategy was based on the premise that the SO3 concentration at the SCR inlet was nominally 5 ppm (even though test data suggested the actual concentration might be much lower). Over time, this operating strategy has resulted in significantly lower NOx emissions for this unit than would have been possible before the pre-SCR conversion.

During the summer of 2016, Duke Energy conducted testing at several stations to demonstrate the capability to keep the SCR’s in service at even lower load conditions. At Gibson Station, one objective of the testing was to demonstrate full NOx reduction at a minimum boiler load of 200 MW, where the minimum flue gas temperature entering the SCR reactor approaches 500°F. Figure 3 illustrates the goal for that testing for Unit 1 relative to the operation prior to, and after, the pre-SCR conversion.

The program conducted by Duke Energy included SCR pilot testing, which was conducted by Cormetech, along with full-scale testing at several plants. The Cormetech testing confirmed that it is possible to operate an SCR reactor at temperatures as low as 500°F if the SO3 concentration at the SCR inlet can be reduced to very low levels.

Data from testing on Unit 1 at Gibson Station is shown in Figure 4. For enhanced operation at full load, an SO3 concentration of no more than a few ppm at the air heater inlet would be necessary to permit operation with elevated ammonia slip levels. The results show that the SO3 concentration was reduced from about 47 ppm (without SO3 mitigation) to an average of 2.4 ppm (with SO3 mitigation in service). For low-load operation, the SCR inlet SO3 concentration is critical for the purpose of reducing the MOT. On Unit 1, the SO3 concentration at the economizer outlet is higher during low-load operation than at full load, probably as a result of higher excess oxygen concentrations in the flue gas. Nonetheless, the average SO3 concentration at the SCR inlet was reduced to about 0.5 ppm with SO3 mitigation in service. This is an SO3 concentration that is even lower than what was determined to be sufficient during the Cormetech bench-scale testing.

Based on the test results, the plant modified the SCR operating guidelines to be consistent with the goal depicted in Figure 3. This change was implemented near the end of 2016; thus, there is limited operating experience at the present time. However, operating experience on Unit 3 included considerable low-load operation at loads as low as 236 MW. The NOx removal efficiency was maintained at 85 percent with no indication of problems associated with the new SCR operating guidelines.

Summary

Utilities are looking for new strategies to improve the performance of their SCR systems. SO3 mitigation, implemented upstream of the air heater or upstream of the SCR system, offers the opportunity for increased SCR operating flexibility and reduced operating costs. Consequently, utilities are evaluating and implementing alternative operating strategies that maximize the value of their existing emission control systems.

Authors:

Sterling Gray is a Business Development Manager for AECOM’s Process Technologies Group in Austin Texas. Jim Jarvis is a project manager for AECOM. Chad Donner is the Sorbent Injection Subject Matter expert for Duke Energy’s Fleet Consulting Services Organization. Josh Estep is an engineer at Duke Energy’s Gibson Station.

Tags