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

FIGURE 3.23a Economizer in a packaged boiler. (Courtesy of ABCO Industries, Abilene, TX.)

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FIGURE 3.23b Photo of an economizer. (Courtesy of ABCO Industries, Abilene, TX.)

increase due to the higher exit gas temperature. The casing loss decreases as a percentage but, as explained in Q6.24, in terms of Btu=h it remains the same because the evaporator operates at saturation temperature, so heat losses in Btu=h are unaffected by boiler load except if ambient temperature or wind velocity changes. Thus the combination of these losses results in a parabolic shape for efficiency as a function of load.

3.The steam temperature generally increases with load owing to the convective nature of the superheater. If a radiant design were used, it would decrease slightly at higher loads.

4.It may also be seen that the gas temperature leaving the evaporator decreases as the load decreases. If an SCR is used between the

evaporator and the economizer, the gas temperature should be maintained in the range of typically 650–780 F; hence one may have to use a gas bypass system to obtain a higher gas temperature at low loads. Chapter 4 shows the arrangement of dampers to achieve this purpose.

5.The steam temperature on oil firing is lower than that in gas firing. This is due to the better absorption of energy from the oil flames in the

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TABLE 3.7 Boiler Performance—Oil Firing

Steam pressure ¼ 500 psig, oil firing. HHV ¼ 19,727; LHV ¼ 18,463 Btu=lb. Flue gas analysis (vol%): CO2 ¼ 10:76, H2O ¼ 11:57, N2 ¼ 73:63, O2 ¼ 2:51.

FIGURE 3.24 Boiler performance versus load.

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furnace, which results in a lower furnace exit gas temperature and lower gas temperature at the superheater in oil firing. Hence the steam temperature is lower. However, if we wanted to maintain the same steam temperature on both oil and gas firing, we would have to size the superheater so that it makes the steam temperature in the oil-firing case and then control it in gas firing by attemperation.

Performance Without an Economizer

If we look at Table 3.4 for performance of a boiler at, say, 100% load, we see that the gas temperature leaving the evaporator is 739 F and leaving the economizer it is 327 F. Now if the economizer is removed from service, can we assume that the exit gas temperature will still be 739 F? The answer is No, for the following reasons:

1.The boiler efficiency drops significantly, by at least (739 7 327)=40 ¼ 10.3%. Hence the efficiency will be at best 83.66 7 10.3 ¼ 73.36% HHV.

2.The boiler fuel input increases by this ratio. The new heat input is

(118.71=0.7336) ¼ 161.8 MM Btu=h versus (118.71=0.8366) ¼ 141.9 MM Btu=h. Hence the flue gas flow, which is proportional to heat input, will be higher by 161.8=141.9 ¼ 1.14 or 14%, or about

1.14 125,246 ¼ 142,800 lb=h.

3.The furnace heat input and heat release rate will also be higher due to the lower efficiency and hence higher furnace exit gas temperature. The combination of higher gas flow and higher gas inlet temperature to

the convection bank will increase the exit gas temperature from the evaporator from 739 F to a slightly higher value. Therefore another iteration will have to be performed to arrive at the exit gas temperature

based on the revised efficiency and fuel input. The exit gas temperature could be close to 770–780 F.

4.Because of the larger flue gas flow and higher operating temperature in the evaporator bank, the gas pressure drop will also be higher; it could be as much as in the earlier case or even more. Hence, the assumption that removing the economizer will reduce the total gas pressure drop is incorrect. One has to do the performance calculations before arriving at any conclusion.

Why the Economizer Does Not Steam in Packaged Boilers

Unlike HRSGs, packaged boilers, fortunately, do not have to deal with the issue of steaming. The reason is illustrated in Fig. 3.25, which shows the temperature

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FIGURE 3.25 Economizer temperature pick-up in boiler versus HRSG.

profiles of the economizer of the boiler whose performance is given above and an HRSG.

Because of the small ratio of gas to water flow in packaged boilers, the temperature drop of the flue gas has to be large for a given water temperature increase. If the water temperature increases by, say, 145 F, the gas temperature drop is given by

1:23 0:286 ðT1 T2Þ ¼ 145 or

T1 T2 ¼ 412 F

whereas in an unfired HRSG, the gas temperature drop of only 105 F accomplishes a water temperature increase of 248 F! Thus it is easy for the water to reach saturation temperature in HRSGs. Thus in spite of the fact that the gas entering temperature is quite large in packaged boilers (due to the high furnace exit gas temperature), the water temperature does not increase significantly.

If the water temperature approach is large at 100% load, it will be even larger at partial loads, because the gas temperature entering the economizer decreases.

Performance with Oil Firing

Steam generators have been fired with both distillate fuel oils and residual oils. The design of the boiler does not change much for distillate oil firing compared to gas firing. The fouling factor used is moderately higher, 0.003–0.005 ft2 h F=Btu, compared to 0.001 ft2 h F=Btu for gas firing; rotary soot blowers located at either end of the convection section are adequate for cleaning the surfaces for distillate oil firing. With heavy fuel oils, retractable soot blowers are required. Economizers

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also use rotary blowers in oil-fired applications. Solid fin tubes of a fin density of three or four per inch may be used if distillate fuels are used, but if heavy oil is fired it is preferable to use bare tubes or at best 2–3 fins=in. The emissions of NOx will be higher on the basis of fuel-bound nitrogen, because it can contribute to nearly 50% of the total NOx. Flue gas recirculation has less effect on NOx in oil firing than in gas firing.

With residual fuel oil firing, there are several aspects to be considered.

1.High temperature corrosion due to the formation of salts of sodium and vanadium in the ash has been a serious problem in with heavy oil boilers fired. The furnace exit region is a potentially dirty zone prone to deposition of molten ash on heating surfaces. The use of superheaters in such regions presents serious performance concerns. Retractable steam soot blowers are required, with access lanes for cleaning. Tubes should preferentially be widely spaced at the gas inlet region to avoid bridging of tubes by slag. Vanadium content in fuel oil ash should be restricted to about 100 ppm to minimize corrosion potential.

2.Superheater materials used in heavy oil firing applications should consider the high temperature corrosion problems associated with

sodium and vanadium salts. The metallurgy of the tubes should be T22 or even higher if the tube wall temperature exceeds 1000 F. A large corrosion allowance on tube thickness is also preferred. This is yet another reason for preferring a convective superheater design to a radiant superheater.

3.Steam temperatures with oil firing will be lower than on gas firing as discussed above.

4.Furnace heat flux will be higher in oil firing than in gas firing. Therefore one has to check the circulation and the furnace design.

5.One of the problems with firing a fuel containing sulfur is the formation of sulfur dioxide and its conversion to sulfur trioxide in the presence of catalysts such as vanadium, which is present in fuel oil ash. Sulfur trioxide combines with water vapor to form sulfuric acid vapor, which can condense on surfaces whose temperature falls below the acid dew point. Q6.25 illustrates the estimation of dew points of

various acid vapors. Sulfuric acid dew points can vary from 200 to 270 F depending on the amount of sulfur in the fuel. If the tube wall temperature of the economizer or air heater falls below the acid dew point, condensation and hence corrosion due to the acid vapor are likely. I have seen a few specifications where a parallel flow arrangement was suggested for the economizer to minimize acid dew point corrosion. Because the feedwater temperature governs the tube wall temperature and not the flue gas temperature, only maintaining a high

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water temperature avoids this problem, as shown in Q6.25c. One could use steam to preheat the feedwater or use the water from the exit of the economizer to preheat the incoming water in a heat exchanger. Experience and research show that acid corrosion potential is maximum not at the dew point but at slightly lower values, about 15–20 C below the dew point. Hence one may use a feedwater temperature even slightly lower than the dew point of the acid vapor in order to recover more energy from the waste gas stream. In waste heat boiler economizers, other acid vapors such as hydrochloric acid or hydrobromic acid may be present. The dew points of these are much lower than that of sulfuric acid, as discussed in Q6.25, so care must be taken in the design of economizers or air heaters in heat recovery applications.

Table 3.7 shows the boiler performance with distillate oil firing. The efficiency on LHV basis is nearly the same as for gas firing, but on HHV basis there is a difference. The flue gas analysis with 15% excess air is shown. The flue gases have less water vapor but more carbon dioxide than flue gases from natural gas combustion.

Effect of FGR on Boiler Performance

Flue gas recirculation is widely used as a method of NOx control because it reduces the flame temperature and thus lowers NOx formation as discussed in Chapter 4. The effect of FGR on boiler performance is quite significant. Not only is the gas temperature profile across the boiler different, but the steam temperature and gas pressure drop are also affected.

Table 3.8 shows the performance of a 150,000 lb=h boiler with and without FGR. The following points may be noted:

1.The flue gas quantity increases with FGR; hence the backpressure increases at all loads.

2.The steam temperature is higher with FGR in both 100% and 50% load cases, but the difference is greater at low loads.

3.The furnace exit gas temperature is lower with FGR, and the gas temperature across the superheater is higher at 50% load than at 100%. Thus load plays a big role in the temperature profiles.

4.The efficiency naturally drops due to the higher stack gas temperature at both 100% and 50% loads.

Relating FGR and Oxygen in the Wind-Box

Flue gas recirculation affects the oxygen in the wind-box by diluting it. One may measure the oxygen values to evaluate the FGR rate used.

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TABLE 3.8 Effect of FGR on Boiler Performance

Fuel: standard natural gas; 1% blowdown; steam pressure ¼ 650 psig.

Example 8

A boiler firing natural gas at 15% excess air uses 119,275 lb=h of combustion air, and about 14,000 lb=h of flue gases is recirculated. Determine the oxygen levels in the wind-box. Let us assume that the air is dry and is 77% by weight nitrogen and 23% oxygen. Then the amount of nitrogen in air ¼ 0.77 119,275 ¼ 91,842 lb=h, and that of oxygen ¼ 27,433 lb=h.

The flue gas analysis (vol%) is CO2 ¼ 8:29; H2O ¼ 18:17; N2 ¼ 71:07,

and O2 ¼ 2:47.

To convert to percent by weight (wt%) basis, first obtain the molecular weight:

MW ¼ ð8:29 44 þ 18:17 18 þ 71:07 28 þ 2:47 32Þ=100 ¼ 27:61

% CO2 ¼ 8:29 44=27:61 ¼ 13:21

Similarly, H2O ¼ 11:84 wt%; N2 ¼ 72:07, and O2 ¼ 2:88.

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The individual constituents in the mixture of 14,000 þ 119,275 ¼ 133,275 lb=h of gases are

CO2 ¼ 0:1321 14;000 ¼ 1849:4 lb=h

H2O ¼ 0:1184 14;000 ¼ 1658 lb=h

N2 ¼ 91;843 þ 0:7207 14;000 ¼ 101;922 lb=h

O2 ¼ 27;433 þ 0:0288 14;000 ¼ 27;836 lb=h

Converting this to percent by volume basis as we did earlier, we have

CO2 ¼ 0:9 vol %; H2O ¼ 1:98; N2 ¼ 78:37; and O2 ¼ 18:75

SOOT BLOWING

Soot blowing is often resorted to in coal-fired or heavy oil–fired boilers. In packaged boilers, both steam and air have been used as the blowing media, and both have been effective with heavy oil firing. Rotary blowers are sometimes used with distillate oil firing. Steam-blowing systems must have a minimum blowing pressure of 170–200 psig to be effective. The steam system must be warmed up prior to blowing to minimize condensation. The steam must be dry. Increasing the capacity of a steam system is easier than increasing that of an air system. With an air system, the additional capacity of the compressor must be considered. Also, because steam has a higher heat transfer coefficient than air, more air is required for cooling the lances in high gas temperature regions compared to steam. Moisture droplets in steam can cause erosion of tubes, and often tube shields are required to protect the tubes. The intensity of the retractable blower jet is more than that of the rotary blower jet, and its blowing radius is larger, thus cleaning more surface area. However, one must be concerned about the erosion or wear on the tubes.

Sonic cleaning has been tried on a few boilers. In this system, low frequency high energy sound waves are produced when compressed air enters a sound generator and forces a diaphragm to flex. The resulting sound waves cause particulate deposits to resonate and dislodge from the surfaces. Once dislodged, they are removed by gravity or by the flowing gases. Typical frequencies range from 75 to 33 Hz. Sticky particles are difficult to clean. The nondirectional nature of the sound waves minimizes accumulation in blind spots where soot blowers are ineffective. Piping work is minimal. Sonic blowers operate on plant air at 40–90 psi and sound off for 10 s every 10–20 min.

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WATER CHEMISTRY, CARRY OVER, AND STEAM PURITY

Good water chemistry is important for minimizing corrosion and the formation of scale in boilers. Steam-side cleanliness should be maintained in water tube as well as fire tube boilers. Plant engineers should do the following on a regular basis:

1.Maintain proper boiler water chemistry in the drum according to ABMA or ASME guidelines by using proper continuous blowdown rates. The calculation procedure for the blowdown rate based on feedwater and boiler water analysis is given in Q5.17.

2.Ensure that the feedwater analysis is fine and that there are no sudden changes in its conductivity or solids content.

3.Check steam purity to ensure that there are no sudden changes in its value. A sudden change may indicate carryover.

4.Watch superheated steam temperatures, particularly in boilers with large load swings. If slugs of water get carried into the steam during large load swings, the deposits are left behind after evaporation, potentially leading to tube failure. An indication of slugging, which is likely in boilers with small drums, is a sudden decrease in steam temperatures due to entrainment of water in the steam.

In the process of evaporating water to form steam, scale and sludge deposits form on the heated surfaces of a boiler tube. The chemical substances in the water concentrate in a film at the evaporation surface; the water displacing the bubbles of steam readily dissolves the soluble solids at the point of evaporation. Insoluble substances settle on the tube surfaces, forming a scale and leading to an increase in tube wall temperatures. Calcium bicarbonate, for example, decomposes in the boiler water to form calcium carbonate, carbon dioxide, and water. Calcium carbonate has limited solubility and will agglomerate at the heated surface to form a scale. Blowdown helps remove some of the deposits. Calcium sulfate is more soluble than calcium carbonate and will deposit as a heat-deterrent scale. Most scale-forming substances have a decreasing solubility in water with an increase in temperature.

In boilers that receive some hardness in the makeup water, deposits are generally compounds of calcium, sulfate, silica, magnesium, and phosphate. Depending on tube temperatures and heat flux and the solubility of these compounds as a function of temperature, these compounds can form deposits inside the boiler tubes. These scales, along with sludge and oils, form an insulating layer inside tubes at locations where the heat flux is intense. Alkalinity and pH of the water also affect the scale formation. Salts such as calcium sulfate and calcium phosphate deposit preferentially in hot regions. Boilers are considered generally clean if the deposits are less than 15 mg=cm2. Boilers having more than 40 mg=cm2 are considered very dirty. The least soluble compounds deposit

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