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

FIGURE 3.18 Steam temperature control methods.

the steam. The solids in the feedwater used for attemperation should be in the same range as the final steam purity desired, which could be as low as 30–100 ppb. If solids are deposited inside the superheater, the tubes can become overheated, particularly if operated at high loads and high heat flux conditions. The convective superheaters are generally oversized at 100% load as explained earlier. The quantity of water spray is larger at higher load. In the radiant design, the steam temperature remains nearly flat over the load range because the radiant component of energy increases at lower loads and decreases at higher loads. Thus many radiant superheaters do not use a two-stage design. However, reviewing other concerns such as possible overheating of tubes and higher tube wall temperatures, the choice is left to the user.

When demineralized water is not available, a portion of the saturated steam from the drum is taken and cooled in a heat exchanger, preheating the feedwater as shown in Fig. 3.18. The condensed water is then sprayed into the attemperator between the two stages of the superheater. Often, in order to balance the pressure drops in the two parallel paths, a resistance is introduced into each path or the exchanger is located vertically up, say 30–40 ft above the boiler, to provide additional head for the spray water control valve operation.

Spraying downstream of the superheater for steam temperature control is not recommended, because the steam temperature at the superheater exit increases with load, thus increasing the superheater tube wall temperature, which can lead to tube failures. For example, if 800 F is the final steam temperature desired, the steam temperature at the superheater exit may run as high as 875–925 F, which will diminish the life of the tubes over a period of time. Also, the water droplets

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may not evaporate completely in the piping and the steam turbine could end up with water droplets and the solids present in the water, leading to deposits on turbine blades.

Design Aspects

Figures 3.19a and 3.19b show an inverted loop superheater commonly used in packaged boilers, and Fig. 3.19c shows a horizontal tube design with vertical headers. Superheaters operate at high tube wall temperatures; hence their design should be carefully evaluated. The convective superheater design located behind several rows of screen section operates at lower tube wall temperatures than the radiant design, though the steam temperatures may be the same. Figure 3.20 shows the results from a computer program for a superheater located very close to the furnace section and beyond several rows of screen tubes.

Option a shows the results for a packaged boiler generating 150,000 lb=h of steam at 650 psig when a 14-row screen section is used. The gas temperature entering the superheater is 1628 F. For the steam temperature of 758 F, the superheater tube wall temperature is 856 F. The surface area used is 1833 ft2.

In option b, a nine-row screen section is used. The gas temperature entering the superheater is 1801 F. The superheater tube wall temperature is 882 F. However, owing to the higher log-mean temperature difference, the surface area required is smaller, namely 1466 ft2. It can be shown, as discussed under life estimation below, that the difference in the life of the superheater for a 26 F difference for alloy steel tubes such as T11 can be several years. By the same token, one may wonder about the life of the radiant design with a gas inlet temperature of 2187 F. Tube sizes are typically 1.5–2 in. OD, and materials used range from T11, T22, and T91 to stainless steels, depending upon steam and tube wall temperatures. Generally, bare tubes are used; however, I have designed a few packaged boilers, which are in operation in gas-fired boilers, using finned superheaters to make the design compact.

Steam velocity inside the tubes ranges from about 50 ft=s at high steam pressure (say 1000–1500 psig) to about 150 ft=s at low pressure (150–200 psig). The turndown conditions and maximum tube wall temperatures determine the number of streams used and hence the steam pressure drop. In inverted loop superheaters, the headers are inside the gas path and are therefore protected by refractory. A few evaporator tubes are provided in the superheater region to ensure that steam blanketing does not occur at the mud drum and that steam bubbles can escape from the mud drum to the steam drum.

Flow distribution through tubes is another concern with superheater design. If long headers are used, multiple inlets can reduce the nonuniformity in steam flow distribution through the tubes as shown in Fig. 3.21. Inlet and exit connections from the ends of headers should be avoided because they can

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FIGURE 3.19a Inverted loop superheater arrangement. (Courtesy of ABCO Industries, Abilene, TX.)

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FIGURE 3.19b An inverted loop superheater. (Courtesy of ABCO Industries, Abilene, TX.)

result in flow distribution problems. In arrangement 1, the inlet and exit connections are on opposite ends, causing the greatest difference in static pressure at the ends of the headers, and should be avoided. Arrangement 2 is better than 1 because the flow distribution is more uniform. However, arrangement 3 is preferred, because the central inlet and exit reduce the differential static pressure values by one-fourth, so the flow maldistribution is minimal.

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FIGURE 3.19c Horizontal tube superheater arrangement. (Courtesy of ABCO Industries, Abilene, TX.)

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FIGURE 3.20 Results from boiler program showing effect of screen section on superheater performance. Option a: More screen rows; option b: fewer screen rows.

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FIGURE 3.21 Flow nonuniformity due to header arrangements.

Two temperatures are of significance in the design of superheater tubes. One is the tube midwall temperature, which is used to evaluate the tube thickness per ASME code. (The published ASME stress values have increased during the last few years and therefore the latest information on stress values should be used in calculating the tube thickness.) The outer wall temperature determines the maximum allowable operating temperature, sometimes known as the oxidation limit. Table 3.6 gives typical maximum allowable temperatures for a few materials.

One can vary the tube thickness to handle the design pressure, but if the outermost tube temperature gets close to the oxidation limit, we have to review

TABLE 3.6 Maximum Allowable Temperatures

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the design. In large superheaters, different materials and tubes of different sizes may be used at different sections, depending on the tube midwall and outer wall temperatures. In all these calculations one has to consider the nonuniformity in gas flow, gas temperature across the cross section, and steam flow distribution through the tubes. Because of their shorter lengths, a few tubes could have higher flow and starve the longer tubes.

Life Estimation

High alloy steel tubes used in superheaters and reheaters, unlike carbon steel, fail by creep rupture. Creep refers to the permanent deformation of tubes that are operated at high temperatures. Carbon steel tubes operate in the elastic range where allowable stresses are based on yield stresses, whereas alloy tubes operate in the creep-rupture range, where allowable stresses are based on rupture strength. The life of superheater tubes is an important datum that helps plant engineers plan tube replacements or schedule maintenance work. When a new superheater tube is placed in service, it starts forming a layer of oxide scale on the inside. This layer gradually increases in thickness and also increases the tube wall temperature. Therefore, to predict the life of the tubes, information on the corrosion or the formation of the oxide layer is necessary. The corrosion of oxide formation also reduces the actual thickness of the tubes and increases the stresses in the tubes over time even if the pressure and temperature are the same. The data on oxide formation were once obtained by cutting tube samples and examining them but are now obtained through nondestructive methods. There are also methods to relate the oxide layer thickness with tube mean wall temperatures over a period of time.

Creep data are available for different materials in the form of the Larson Miller parameter, LMP. This relates the rupture stress value to temperature T and the remaining lifetime t, in hours.

LMP ¼ ðT þ 460Þð20 þ log tÞ

Every tube in operation has an LMP value that increases with time. LMP can be related to stress values and the relationship then used to predict remaining life. However, there are charts that give what is called the minimum and the average rupture stress versus LMP, and one can compute different life times with the different values. Also, it can be seen that even a few degrees difference, say 10 F in metal temperatures, can change the lifetime by a large amount, which shows how complex and difficult it is to interpret the results. Figure 3.22 shows the relationships between LMP and minimum rupture stress values for T11 and T22 materials.

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FIGURE 3.22 Larson–Miller parameters for T11 and T22 materials.

Example 7

Assume that a superheater of T11 material operates at 1000 F and at a hoop stress of 6000 psi. What is the predicted time to failure? From Fig. 3.22, the LMP at 6000 is 36,800.

Solution: From the above equation, we can see that

36; 800 ¼ ð1460Þð20 þ log tÞ; or t ¼ 160;500 h

If a tube had operated at this temperature for 50,000 h, its life consumed would be 50,000=160,500 ¼ 0.31, or 0.69 of its life would remain. If after this period of 50,000 h, it operated at, say, 1020 F and at the same stress level, then

36;800 ¼ ð1480Þð20 þ log tÞ; or t ¼ 73;250 h

and the number of operating hours at this temperature would be 0.69 73,250 ¼ 50,728 h.

One can see from the above how sensitive these numbers are to temperatures and stress values. Hence we have to interpret the results with caution backed up by operational experience. Simplistic approaches to replacement of tube bundles are not recommended. It should also be noted that if the average rupture stress is used instead of the minimum value, the lifetime would be much higher, casting more uncertainty in these calculations.

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ECONOMIZERS

Economizers are used as heat recovery equipment in packaged boilers instead of air heaters because of NOx concerns as discussed in Chapter 4. They are also less expensive and have lower gas pressure drops across them. Economizers for gas firing typically use serrated fins at four to five fins per inch. For distillate fuel, about 4 fins=in, solid fins are preferred. For heavy oil, bare tubes or a maximum of 2–3 fins=in. are used, depending upon the dirtiness of the flue gas and the ash content of the fuel.

Economizers are generally of vertical gas flow and counterflow configuration with horizontal tubes as shown in Fig. 3.23. The water-side velocity ranges from 3 to 7 ft=s. Small packaged boilers, below 40,000 lb=h capacity, use circular economizers that can be fitted into the stack. Another variation is the horizontal gas flow configuration with vertical headers and horizontal tubes.

Generally, steaming in the economizer is not a concern, as discussed earlier. Feedwater temperatures of 230–320 F are common, depending on acid dew point concerns. The feedwater is sometimes preheated in a steam–water exchanger if the deaerator delivers a lower feedwater temperature than that desired to avoid acid corrosion in the case of oil-fired boilers.

BOILER PERFORMANCE ASPECTS

Plant engineers are interested in knowing how a given boiler performs at various loads. The variables affecting its performance are the fuel, amount of excess air, FGR rate, and steam parameters. Tables 3.4 and 3.7 show how boiler performance varies with load on gas and oil firing. Figure 3.24 shows the results in graph form. The following observations can be made:

1.As the load increases, the boiler exit gas temperature increases. This is due to the larger flue gas mass flow transferring energy to a given heating surface. The water temperature leaving the economizer is higher at loads owing to the higher gas temperature entering the economizer. The approach point (difference between saturation and water temperature entering evaporator) is lower at higher loads. Steaming in the economizer is not a concern in steam generators because the approach point is quite large at full load and increases at lower loads. The ratio of gas flow to steam generation is maintained at 1.2–1.3 at various loads. Hence the economizer does not absorb more energy at low loads as in the case of HRSGs.

2.The boiler efficiency increases as the load increases, peaks at about 50– 70% of load, then drops off. The two major variables affecting the heat losses are the casing heat losses and heat loss due to flue gases. Q6.24 discusses this calculation. As the load increases, the flue gas heat losses

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