01 POWER ISLAND / 01 CCPP / V. Ganapathy-Industrial Boilers and HRSG-Design (2003)

FIGURE 4.6 Gas bypass system in boiler using (a) FGR and (b) SCR methods for NOx control.

temperature there is very high. As shown in Fig. 4.7, the two evaporator circuits are in parallel. External downcomers and risers are used to ensure adequate circulation through both the evaporator modules. Figure 4.8 shows the gas temperatures entering various sections of a fired HRSG—superheater, evaporator, economizer, and stack—at various steam flows. The gas temperature at the entrance of the second-stage evaporator section may be seen to be in the range of 650–800 F. The SCR system adds about 3–4 in. WC to the boiler or HRSG gasside pressure drop, which is an operating expense as discussed earlier.

The selective catalytic reduction (SCR) method uses the same reaction process as SNCR except that a catalyst is employed to lower the temperature of operation and also increase the efficiency of conversion. Ammonia or urea is used in these reactions as the reagent. Figure 4.9 shows how ammonia is added in three different systems. The most common method uses anhydrous ammonia, which is pure ammonia. Anhydrous ammonia is toxic and hazardous, particularly if the neighborhood has a large population. It has a high vapor pressure at ordinary temperatures and thus requires thick shells for the storage tanks. Its release to the atmosphere can cause environmental problems, and extreme caution is required to handle such a situation. However, this is the least expensive way to feed ammonia into the HRSG.

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FIGURE 4.7 HRSG showing location of NOx (SCR) and CO catalysts.

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FIGURE 4.8 HRSG gas temperature profiles as a function of steam generation. sh, superheater; econ, economizer; evap, evaporator.

FIGURE 4.9 Ammonia injection methods. (Courtesy of Peerless Manufacturing, Dallas, TX.)

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Aqueous NH3ðNH4OHÞ, which is a mixture of ammonia and water, is safer to handle. A typical grade contains 30% ammonia and 70% water. It has nearly atmospheric vapor pressure at ordinary temperatures. The liquid ammonia is pumped to a vaporizer and mixed with heated air before being sent to the mixing grid. Urea systems, which generate ammonia on-site, are also safer and have been recently introduced. Dry urea is dissolved to form an aqueous solution, which is fed to an in-line reactor to generate ammonia by hydrolysis. Heat is applied to carry out the reactions under controlled conditions. The ammonia is mixed with air and then injected through a grid into the gas stream.

Computational fluid dynamics (CFD) analysis is done to ensure that the gas velocity distribution across the boiler or HRSG cross section is uniform, with variations within 15%. The ammonia vapor is mixed with air and sprayed into the flue gas stream at the desired location before coming into contact with the catalyst. A heat transfer surface located immediately behind the ammonia injection grid ensures good mixing of ammonia vapor with the flue gases. The optimum gas temperature for the NOx reduction reactions with most catalysts is 600–780 F as mentioned earlier. Below this temperature, chemical reactivity is impaired, and above it physical damage can occur to the catalyst through sintering. From the boiler or HRSG design viewpoint, a suitable location has to be found for the SCR so that at the wide range of loads, the temperature window is maintained, to ensure that undesirable oxidation of ammonia to NO does not take place. This is accomplished in a boiler by using a gas bypass system as discussed earlier. The ammonia injection system is located upstream of the SCR and should have sufficient mixing length that the flue gases can react with ammonia. SCR efficiency ratings are in excess of 90%. A gas pressure drop across the catalyst of about 3–4 in. WC adds to the fan power consumption in a steam generator and could be a significant power decrement in a gas turbine plant. Catalysts are typically platinum, vanadium, tungsten, and noble metals and zeolites, which are used at higher temperatures.

Typical reactions are

catalyst

4NH3 þ 4NO þ O2 ! 4N2 þ 6H2O

catalyst

4NH3 þ 2NO2 ! 3N2 þ 6H2O

To complete these reactions, slightly more NH3 than required is injected into the gas stream. This excess ammonia, which is called slip, is generally limited to a single-digit value (less than 5 ppm), through a control and emission monitoring system. The slip value increases gradually over a period of time as the catalyst nears the end of its service life.

Sulfur-containing flue gas streams present problems for boilers and HRSGs. The presence of vanadium in the SCR converts SO2 to SO3, which

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can react with excess ammonia to form ammonium sulfate or with water vapor to form sulfuric acid, causing problems such as fouling and plugging of tubes downstream of the boiler or HRSG. Distillate oil contains a small amount of sulfur, hence the only way to minimize this concern is to limit the operating hours on oil fuels. Lowering the ammonia slip also helps, but this can lower the NOx reduction efficiency.

Environmentally ammonium sulfate and bisulfate are particulates that contribute to visible haze and acidify lakes and ground areas when they settle out of the air.

Sulfates are formed according to the equations

SO3 þ NH3 þ H2O ! NH4HSO4

SO2 þ 2NH3 þ H2O ! ðNH4Þ2SO4

Ammonium sulfate is a sticky substance that can be deposited on heat transfer surfaces and cause fouling. The gas pressure drop across the heating surfaces also increases over a period of time. If the ammonia slip is less than 10 ppm and the SO3 concentration is less than 5 ppm, expert opinion is that the probability of ammonium sulfate formation is practically nil unless the gas temperature is low, on the order of 200 C. Hence low gas temperatures should be avoided, particularly at the catalysts, because salt formation and deposits there would be detrimental to the life of the catalyst. Some suppliers require a minimum of 450– 500 F at the catalyst to minimize these reactions. Either ammonium sulfate or ammonium bisulfate will be formed by the reaction of SO3 and excess ammonia downstream of the SCR catalyst. In general, ammonium sulfate is considerably less corrosive than ammonium bisulfate.

One should keep the boiler or HRSG warm in standby conditions during brief shutdowns if fuel oils are fired. Shutdown and isolation of the HRSG after oil firing should be avoided because the SO3 can condense during the cooling phase. For boilers or HRSGs firing natural gas fuels, fortunately, there are no such concerns as those just discussed. It may be noted that the presence of water vapor in the flue gases has an adverse effect on NOx reduction efficiency.

Selective catalytic reduction systems have efficiencies of 90–95%. However, they are expensive and may cost from $3000 to $5000=MM Btu=h in gas or oil-fired packaged boilers. For gas turbines the cost could range from $40 to 100=kW. In some coal-fired plants where regenerative air heaters are used, the hot end heating elements are coated with a catalyst material to convert NOx to N2 and H2O.

SCONOx

The SCONOx system is a recent development that is claimed to reduce NOx and CO levels to 2–5 ppmv with a single catalyst. It does not use ammonia or urea and

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hence avoids the concerns associated with handling ammonia. The system can operate efficiently at 300–700 F, which is an advantage because the HRSG evaporator need not be split up. Typically the gas temperature between the evaporator and economizer of an HRSG is in this range. Dampers are not needed to control the gas temperature in steam generators at low loads. This method has been used in a few HRSGs but not in packaged boilers.

The SCONOx catalyst works by simultaneously oxidizing CO to CO2, hydrocarbons to CO2 þ H2O, and NOx to NO2 and then absorbing NO2 onto its platinum surface through the use of a potassium carbonate absorber coating. These reactions, shown below, are referred to as the ‘‘oxidation=absorption cycle.’’

CO þ 12 O2 ! CO2

NO þ 12 O2 ! NO2

CH2O þ O2 ! CO2 þ H2O

2NO2 þ K2CO3 ! CO2 þ KNO2 þ KNO3

The CO2 produced by these reactions is exhausted up the stack. The potassium carbonate coating reacts to form potassium nitrates and nitrites, which remain on the surface of the catalyst.

The SCONOx catalyst can be compared to a sponge absorbing water. It becomes saturated with NOx and must be regenerated. When all of the carbonate absorber coating on the catalyst surface has reacted to form nitrogen compounds, NOx will no longer be absorbed, and the catalyst must enter the regeneration cycle.

The unique regeneration cycle is accomplished by passing a dilute hydrogen reducing gas across the surface of the catalyst in the absence of oxygen. The hydrogen reacts with nitrites and nitrates to form water and elemental nitrogen. Carbon dioxide in the regeneration gas reacts with potassium nitrites and nitrates to form potassium carbonate, which is the absorber coating that was on the catalyst surface before the oxidation=absorption cycle began. This cycle is called the ‘‘regeneration cycle.’’

KNO2 þ KNO3 þ 4H2 þ CO2 ! K2CO3 þ 4H2O þ N2

Water and elemental nitrogen are exhausted up the stack instead of NOx, and potassium carbonate is once again present on the catalyst surface, allowing the entire cycle to begin again.

Because the regeneration cycle must take place in an oxygen-free environment, a section of catalyst undergoing regeneration must be isolated from the exhaust gases, usually by a set of louvers, one upstream of the section being regenerated and one downstream. During the regeneration cycle, these louvers

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close and a valve allows the regeneration gas into the section. Stainless steel strips on the louvers minimize leaks during operation. A SCONOx system has five to 15 sections of catalyst, depending on gas flow, design, etc. At any given time, 80% of the sections are in the oxidation=absorption cycle and 20% are in the regeneration mode. Because the same number of sections are always in the regeneration mode, the production of regeneration gas proceeds at a constant rate. A regeneration cycle lasts for 3–5 min, so each section is in oxidation=absorption mode for 9–15 min.

The SCONOx technology is still being developed and have yet to accumulate significant operational experience compared to the SCR system. It is also very expensive and is sensitive to sulfur, even the small amount in natural gas. For a 2.5 ppmv NOx limit from a 501 F Westinghouse gas turbine, studies show that the cost of SCONOx is more than that of the SCR system. However, with technological improvements, it could become an economically viable option.

Combustion Control Methods

The formation of NOx has been well understood by burner manufacturers, who are able to offer several methods to reduce the formation of NOx in steam generators. Gas turbine manufacturers also have come up with design improvements to lower NOx emissions.

During the combustion process, several complex reactions occur within the flame, and NOx formation is a function of temperature, oxygen, and time of residence in the high temperature zones. Figure 4.1 shows the effect of temperature on NOx formation. As the combustion temperature is reduced from 2700 F to 2300 F, NOx is reduced by a factor of 10.

As the excess air increases, the NOx increases and drops off as shown in Fig. 4.10 Because CO is another pollutant, its emissions should also be limited. As the excess air increases, CO decreases. Hence there is a band of excess air in which one can operate the burner to minimize both NOx and CO.

Gas turbine manufacturers have come up with dry low-NOx (DLN) combustors, which limit the NOx to single-digit levels. Most of the NOx emitted by a gas turbine firing natural gas is generated by the fixation of atmospheric nitrogen in the flame, and the amount of this ‘‘thermal NOx’’ is an exponential function of flame temperature. The DLN combustor lowers the flame temperature by burning a leaner mixture of fuel and air in premixed mode. To reduce NOx emissions in traditional combustors, steam or water is injected to reduce the flame temperature; benefits include additional power output. However, there is a loss in engine life and shortening of combustor life. CO formation also increases as the amount of water or steam increases, as shown in Fig. 4.11.

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FIGURE 4.10 Typical NOx and CO levels versus excess air.

Oxygen Control

In steam generators, oxygen trim can be added to control the excess oxygen levels. Too little oxygen increases CO formation, and too much can increase the NOx. Also, the boiler efficiency is impacted by the excess air levels as discussed in Chapter 3. The higher mass flow also affects the gas temperature distribution throughout the boiler and can affect the superheated steam temperature.

Steam–Water Injection

Boiler and burner suppliers sometimes use steam injection to reduce the flame temperature and thus decrease NOx. Steam generators as well as gas turbines use this method. In boilers the steam consumption could vary by 1–3% of the total steam generated, thus reducing the boiler output; however, the significant reduction in NOx may offset the need for FGR or other methods. The NOx reduction is more significant with gas firing than with oil firing. A side effect of water or steam injection is the increase in CO content. Hence there should be a compromise between the efforts to reduce NOx and CO.

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FIGURE 4.11 Effect of steam–water injection on NOx and CO.

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In HRSGs, steam or water injection in to the gas turbine combustor is used along with catalysts located in the HRSG to limit NOx to single digits. The increase in water vapor content on SCR performance has to be reviewed. Steam injection also increases the gas turbine power output due to the increased mass flow and higher specific heat of the gases with increased water vapor content. This concept is used in the Cheng cycle power system discussed in Chapter 1.

Water or steam injected into gas turbines has to be treated to give high steam purity. Steam purity should be preferably in the parts per billion range. The treated water is lost to the atmosphere and has to be evaluated as an operating cost in such systems.

Burner Modifications

Staged combustion is widely used by burner suppliers to reduce NOx. In this method, the fuel or air is added in increments (Fig. 4.12) so that at no point in the flame is an exceptionally high temperature obtained. In air staging, a fuel-rich mixture is initially created, followed by the addition of air at the burner tip to burn the remaining fuel. As little as 60% of the total combustion air is introduced into the primary combustion zone. The substoichiometric operation generates a high level of partial pressures of hydrogen and CO, and these reducing agents limit the NOx formation. The second-stage air is introduced downstream to complete the combustion process after some heat has been transferred to the process, thereby limiting the formation of thermal NOx. The staging of air does provide some control over both thermal and fuel NOx.

A concept that is a little more effective for reducing thermal NOx is fuel staging. Staged fuel burners are widely used. A portion of the fuel and all of the combustion air are introduced into the primary combustion zone. Rapid combus-

FIGURE 4.12 Staging of fuel and air in burners.

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