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

Q5.17. In some refinery projects, I have seen very poor feedwater being used, which results in 10% to even 20% blowdown, which is a tremendous waste of energy; it also affects the boiler duty and heat input significantly. Heat input, in turn, affects the flue gas quantity and gas pressure drop.

4.Emission limits of NOx and CO should be stated up front because they affect the burner design as well as the furnace design, the flue gas recirculation rates, and therefore the entire boiler design and performance. The use of SCR may also have to be looked into, and the cost implications are significant.

5.Fuels used and their analysis should be stated. Standard natural gas or fuel oil may not have significant variations in analysis within the United States, but for projects overseas the fuel analysis is important. Some natural gas fuels overseas contain a large percentage of hydrogen sulfide, which can cause acid dew point problems. Gaseous fuels should have the analysis in percent by volume and not in percent by weight, whereas liquid and solid fuels should have the analysis in percent by weight.

6.Surface areas should not be specified, for reasons discussed earlier.

7.Operating costs such as the cost of fuel and electricity should be stated as well as the norm for evaluating operating costs. Ignoring operating costs and selecting boilers based on initial costs alone (which is unfortunately being done even today!) is doing a disservice to the end user.

8.Furnace area heat release rates are more important than volumetric heat release rates for clean fuels, as mentioned earlier, therefore specifying volumetric heat release rates is not recommended for gas and oil fuels.

9.Large fan margins should not be used, and efforts must be made to estimate the gas pressure drop accurately. Large margins on flow (such as 20%) and on heat (40%) not only increase the operating horsepower, which is a waste of energy, but also make it difficult to operate the fan at low loads. In boilers with single fans, the margins should be small, say 10–12% on flow and 20–25% on head. Those familiar with utility boiler practice where multiple fans are used try to apply the same norms to packaged boilers, which can lead to operating concerns at low loads unless variable-speed drives or variable-frequency drives are used. The ambient temperature variations and elevation at which the boiler is likely to be used are important because this information helps in the selection of appropriate fans.

These points along with information on mechanical requirements such as materials, corrosion allowances, and future operational considerations, if any, are

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important to the boiler designer. The proposal should also clearly state the required performance aspects.

REFERENCES

1.V Ganapathy. Understand the basics of packaged steam generators. Hydrocarbon Processing, July 1997.

2.V Ganapathy. Heat recovery steam generators: understand the basics. Chemical Engineering Progress, August 1996.

3.V Ganapathy, Customizing pays off in steam generators. Chemical Engineering, January 1995.

4.API Recommended Practice 530, 2nd. ed. Recommended Practice for Calculation of Heater Tube Thickness in Petroleum Refineries. May 1978.

5.V Ganapathy. Understand the basics of packaged steam generators. Hydrocarbon Processing, July 1997.

6.V Ganapathy. Superheaters: design and performance. Hydrocarbon Processing, July 2001.

7.V Ganapathy. 21st century packaged boilers will be larger and more environmentally friendly. Power Engineering, August 2001.

8.O Jones. Developing steam purity limits for industrial turbines. Power, May 1989.

9.J Robinson. A practical guide to avoiding steam purity problems in the industrial plant. International Water Conference, October 1992.

10.Nalco Corp. The Nalco Guide to Boiler Failure Analysis. New York: McGraw-Hill, 1991.

11.Editor. Attraction grows for heat pipe air heaters in flue gas streams. Power, February 1989.

12.V Ganapathy. How important is surface area? Chemical Engineering Progress, October 1992.

13.V Ganapathy. Understand steam generator performance. Chemical Engineering Progress, December 1994.

Copyright © 2003 Marcel Dekker, Inc.

4

Emission Control in Boilers and HRSGs

INTRODUCTION

Boiler and HRSG designs have undergone significant changes during the last few decades with the enforcement of emission regulations in various parts of the world. Decades ago boiler and HRSG users were concerned about two issues only: the initial cost of the boiler or HRSG and the cost of operation. Low boiler efficiency, for example, meant higher fuel cost, and a large pressure drop across boiler heating surfaces resulted in increased fan power consumption. Each additional 1 in. WC pressure drop in a boiler of 100,000 lb=h capacity results in about 5 kW of additional fan power consumption. In a gas turbine HRSG, an additional 4 in. WC of gas pressure drop decreases the gas turbine power output by about 1.0%. At 320 F stack gas temperature, the difference in efficiency between 5% and 15% excess air operation on natural gas is about 0.4%. Therefore, steam generators were operated at the lowest possible excess air, about 5% or so, to maintain good efficiency. With strict emission regulations in vogue throughout the world, present-day steam generators or HRSGs, in addition to having low operating costs, must limit the emissions of CO2; CO; NOx; SOx, and particulates. The expression ‘‘low NOx, no SOx, and no rocks’’ aptly describes the direction in which we are headed. However, several of the techniques used for emission control increase the cost of owning and operating

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the boilers and HRSGs. For example, in order to meet the stringent levels of NOx and CO, today’s boilers have to operate at higher excess air and use some flue gas recirculation (FGR), which affects their efficiency as well as their operating costs significantly, as we discuss later.

One of the important changes is in the use of an economizer instead of an air heater for heat recovery in packaged boilers. Air heaters were used in industrial boilers several decades ago even if the fuel fired was natural gas. However, as the combustion air temperature to the boiler increases, the NOx formation increases, because it is a function of flame temperature, as shown in Fig. 4.1. With natural gas at 15% excess air, each 100 F increase in combustion air temperature increases the flame temperature by about 65 F. Hence today’s packaged oiland gas-fired boilers do not use air heaters. Economizers are used to improve their efficiency. In addition to increasing NOx, an air heater adds about 3–5 in. WC to the gasand air-side pressure drop, while the typical gas pressure drop across the economizer is 1 in. WC. Therefore, with an economizer as the heat recovery equipment, substantial savings in operating cost can also be realized.

Owing to the use of low-NOx burners, the furnace dimensions of standard boilers may have to be reviewed to avoid flame impingement concerns. The completely water-cooled furnace (Fig. 4.2) is another innovation that helps in lowering emissions. If the desired emission levels are in single digits, HRSGs and packaged boilers use catalysts to minimize NOx and CO, which influences their design significantly. For example, a gas bypass system has to be provided in boilers, and the evaporator may have to be split up in the case of HRSGs to accommodate the selective catalytic reduction (SCR) system.

Thus, there are several variables that affect emissions and numerous options to minimize them, as indicated in Fig. 4.3, which will be addressed in this

FIGURE 4.1 Typical NOx formation versus flame temperature for natural gas.

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FIGURE 4.2 Water-cooled furnace. (Courtesy of ABCO Industries, Abilene, TX.)

chapter. These emission control strategies naturally add to the initial and operating costs of boilers and HRSGs and impact their design as well, a price we must pay for cleaner air.

HOW POLLUTANTS ARE GENERATED

Before going into further details of how the boiler or HRSG is impacted by emission regulations, one should first understand what the various pollutants are

FIGURE 4.3 Options for NOx removal in boilers and HRSGs.

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and how they are formed. In the process of combustion of fossil fuels, be it in steam generators, gas turbines, or engines, several pollutants are released to the environment. These include carbon dioxide (CO2), oxides of nitrogen (NOx), carbon monoxide (CO), oxides of sulfur (SOx), and volatile organic compounds (VOCs).

Carbon dioxide is considered to be responsible for the greenhouse effect and global warming. Concentrations of 3–6% can cause headaches; larger concentrations can lead to unconsciousness and possibly death. Coal generates about 200 lb CO2=MM Btu fired; oil generates 150 lb and natural gas about 100 lb per MM Btu. Hence one can see why natural gas is the preferred fuel in any fired equipment. CO2 molecules retain infrared heat energy, preventing normal radiation from the earth and leading to warming of the atmosphere. There are several processes, such as amine-based systems that can remove CO2 from flue gas streams, but these can be justified only in large plants.

The presence of carbon monoxide (CO) in flue gases is indicative of inefficient combustion and may be due to poor burner operation, improper settings, or even poor boiler design. CO is dangerous to the health of humans and other living creatures. It passes through the lungs directly into the bloodstream, where it reduces the ability of the red blood cells to carry oxygen. It can cause fainting and even death. At an exposure of only 0.1% by volume (1000 ppm) in air, a human being will be comatose in less than 2 h. A few regulations establish a maximum exposure of CO of 9 ppm for an 8 h average and 13 ppm for any 1 h period.

Oxides of nitrogen, NOx, are predominantly NO and NO2. The majority of NOx produced during combustion is NO (95%). NOx is responsible for the formation of ground-level ozone or smog. Oxides of sulfur, SOx, are formed when fuels containing sulfur are fired. Sulfur dioxide (SO2) and sulfur trioxide (SO3) are responsible for acid rain and can damage plant life and materials of construction. The Taj Mahal in India is a good example of what acid formation from nearby refineries emitting oxides of sulfur can do to the luster and beauty of marble over a period of time. Particulates are also formed during combustion that disperse in the air to form haze and smog, affecting visibility. Dangerous driving conditions are created in some places due to smog formation. Inhalation of particulates affects the lungs and the digestive system.

Volatile organic compounds (VOCs), which are generated in industrial processes such as those of chemical and petrochemical plants, also cause harmful ozone.

Tremendous efforts are being made to reduce these pollutants in power and process plants, refinery heaters, and combustion equipment.

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NOx FORMATION

Nitrogen oxides are of environmental concern because they initiate reactions that result in the formation of ozone and acid rain, which can cause health problems, damage buildings, and reduce visibility. The allowable NOx emissions from boilers and HRSGs vary depending on local regulations but are gradually edging toward single-digit values in parts per million volume (ppmv) due to advances in combustion and pollution control technology. The principal nitrogen pollutants generated by boilers, gas turbines, and engines and other combustion equipment are nitric oxide (NO) and nitrogen dioxide (NO2), collectively referred to as NOx and reported as NO2. Once released into the atmosphere, NO reacts to form NO2, which reacts with other pollutants to form ozone (O3). Oxides of nitrogen are produced during the combustion of fossil fuels through the oxidation of atmospheric nitrogen and fuel-bound nitrogen. These sources produce three kinds of NOx: fuel NOx, prompt NOx, and thermal NOx.

Fuel NOx is generated when nitrogen in fuel combines with oxygen in combustion air. Gaseous fuels have little fuel-bound nitrogen, whereas coal and oil contain significant amounts. Fuel-bound nitrogen can account for about 50% of total NOx emissions from coal and oil combustion. Most NOx control technologies for industrial boilers reduce thermal NOx and have little impact on fuel NOx, which is economically reduced by fuel treatment methods or by switching to cleaner fuels. Fuel NOx is relatively insensitive to flame temperature but is influenced by oxygen availability.

Prompt NOx results when fuel hydrocarbons break down and recombine with nitrogen in air. Prompt NOx is chemically produced by the reactions that occur during burning; specifically, it forms when intermediate hydrocarbon species react with nitrogen in air instead of oxygen. Prompt NOx, so called because the reaction takes place ahead of the flame tip, accounts for about 15–20 ppm of the NOx formed in the combustion process and is a concern only in low temperature situations.

Thermal NOx forms when atmospheric nitrogen combines with oxygen under intense heat. This rate of formation increases exponentially with an increase in temperature and is directly proportional to oxygen concentration. Its formation is well understood and straightforward to control. Keeping the flame temperature low reduces it. Below a certain temperature, thermal NOx is nonexistent, as indicated in Fig. 4.1. Combustion temperature, residence time, turbulence, and excess air are the other factors that affect the formation of thermal NOx. Most NOx is formed in this manner in gas turbines, industrial boilers, and heaters fueled by natural gas, propane, butane, and light fuel oils.

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Common boiler fuels in the order of increasing NOx potential are methanol, ethanol, natural gas, propane, butanes, distillate fuel oil, heavy fuel oils, and coal.

NOx CONTROL METHODS

Methods for NOx control can be classified into two broad categories:

1.Postcombustion methods: methods that are deployed after flue gases are generated.

2.Combustion control methods: methods that are deployed during the combustion process.

Postcombustion Methods

As the name implies, postcombustion methods deal with the flue gases obtained after combustion. They are more expensive than combustion control methods, because they handle large quantities of flue gases generated in the process of combustion. The ratio of flue gas to fuel on a weight basis is about 21 for natural gas and 18 for fuel oils in steam generators. In gas turbines, the exhaust gas quantity generated is very large because on the order of 200–300% excess air is used. The two commonly used methods of control are

1.Selective noncatalytic reduction (SNCR) methods

2.Selective catalytic reduction (SCR) methods

SNCR

In selective noncatalytic reduction a NOx reduction agent such as ammonia or urea is injected into the boiler exhaust gases at a temperature of approximately 1400–1650 F. The ammonia or urea breaks down the NOx in the exhaust gases into water and atmospheric nitrogen, plus CO2 if urea is injected. This reaction takes place in a narrow range of temperatures; as shown in Fig. 4.4, ammonia is formed below a certain temperature, and above this temperature the NOx level increases. SNCR reduces NOx by about 70%. The SNCR method is used in large industrial and utility boilers, which have adequate residence times for the reduction reactions. In packaged boilers it is difficult to apply this method because the ammonia or urea must be injected into the flue gases at a specific flue gas temperature; however, the gas temperature profile varies with load, excess air, and fuel fired as shown in Fig. 4.5 and residence times in oiland gas-fired packaged boilers are generally very small.

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FIGURE 4.4 Range of temperatures for SNCR operation.

FIGURE 4.5 Boiler temperature profiles as a function of load. Furn, furnace; scrn, screen; SH, superheater evap, evaporators; econ, economizer.

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Typical reactions, that take place with ammonia injection are:

NO þ NH3 þ ð1=4ÞO2 !N2 þ ð3=2ÞH2O

NH3 þ ð5=4ÞO2 ! NO þ ð3=2ÞH2O

Both oxidation and reduction take place. Ammonia oxidizes to form NO. Because reduction and oxidation reactions are temperature-sensitive, there is a narrow range of temperatures in which the conversions are efficient. An increase in ammonia increases the efficiency of conversion; however, excessive ammonia can slip through the reactions and cause plugging of components downstream. SNCR has a low cost of operation and may be used in conjunction with other methods such as a low-NOx burner to improve the efficiency of NOx reduction.

In large field-erected boilers, wall injectors are located at several locations to inject the ammonia or urea using specially designed lances. This method is not used in HRSGs because it is difficult to find such a temperature window and also have a suitable residence time.

Benefits of SNCR include

Medium to high NOx reduction.

No by-products for disposal—minimizes waste management concerns,

Easy to retrofit—little downtime required.

Minimum space required.

Can be used along with other NOx reduction methods.

Low energy consumption. Additional gas pressure drop of flue gases is zero, unlike in SCR method, where the catalyst could add about 3 to 4 in. WC to the gas pressure drop, adding to the operating cost.

SCR

If the desired CO and NOx levels are very low, on the order of single digits, a selective catalytic reduction (SCR) system may have to be used in boilers and HRSGs, Because most catalysts operate efficiently within a temperature window, generally 650–780 F, the boiler should have a gas bypass system to accommodate the gas temperature window at all loads. One can see from Fig. 4.5 how the gas temperature profile across a packaged boiler varies with load. As the load decreases, the gas temperature at the various surfaces decreases because a smaller amount of flue gases is generated at lower load. Hence a gas bypass system, as shown in Fig. 4.6, that mixes the hot flue gases taken from the convection bank with the cooler gases at the evaporator exit ensures a higher gas temperature at the SCR at low loads. Heat recovery steam generators (HRSGs) also use the SCR system to limit NOx, and, again, to match the gas temperature window of 650– 780 F the evaporator is often split up as shown in Fig. 4.7. If we did not split up the evaporator, we would have a very low gas temperature at its exit; also we cannot locate the SCR system ahead of the evaporator, because the gas

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