Performance with and without Export Steam

In cogeneration plants, saturated steam is sometimes taken off the drum for process heating purposes. This decision may come after a few years after the boiler is installed, and hence, the boiler supplier may not be around to help the plant. Plant engineers wonder if the lower steam flow through the superheater will result in over- heating of tubes. By doing performance calculations, one can check this. Based on the results of the calculation, plant may go ahead with the decision to take the process steam from the drum. Here is an example of such a problem where saturated steam is exported from the HRSG.

TABLE 4.13

a Performance of HRSG with Split Superheaters

Gas Flow, kg/h

Steam press., kg/cm g 54.0 54.0 gas temp. in, °C

Steam temp. out ±5°C

CO 2 , % volume

Steam flow, kg/h

Feed water temp., °C

N 2 75.50 O 2 15.10

Gas in Sh.

Sh. Evap.

Eco.

Burner

Unfired Case

Fired Case

Process Data Surface

Evap. Econ.

Suphtr1 Suphtr2

Evap.

Evap. Econ.

Gas temp. in, ±5°C

576 307 Gas temp. out, ±5°C

307 193 Gas spht, kcal/kg °C

0.2770 0.2644 Duty, NIM kcal/h

5697 4207 Gas press. drop, mm wc

Surface area, m 2 202

9.23 2.97 4.71 4.39 36.69 24.14 9.10 4.10 6.35 5.69 42.77 24.14 Foul factor, gas

0.0002 0.0002 U, Btu/ft 2 h °F

128 83 Max gas vel., m/s

26 13 16 17 18 16 26 18 21 22 22 17 (Continued)

S team G

TABLE 4.13 (Continued)

Performance of HRSG with Split Superheaters en

at or

Unfired Case

Fired Case

Process Data Surface

Suphtr1 Suphtr2

Evap.

Evap. Econ.

sa n

Tube wall temp., ±5°C

Fin tip temp., ±5°C

Weight, kg

Fluid temp. in, °C

Fluid temp. out, ±5°C

Pr drop, kg/cm 0.07 0.18 0.00 0.00 0.00 0.18 0.29 0.78 0.00 0.00 0.00 0.77 Foul factor, fluid

Fluid velocity, m/s

10.8 9.6 0.0 0.0 0.0 0.7 22.3 20.1 0.0 0.0 0.0 1.4 :F rs

Fluid httr. coefft.

Steam flow, kg/h

100,000 10,0000 100,000 100,000 Burner duty, MM kcal/h

30.19 ro

ce ss a

n dP

la n tE n g in

ee rs

Waste Heat Boilers 211

TABLE 4.14

Geometric Data of HRSG with Split Superheaters: Burner between Superheaters

Evap3 Econ

Tube OD 38.1 38.1 50.8 50.8 50.8 44.5 Tube ID

30.6 30.6 44.1 44.1 44.1 37.8 Fins/in. or fins/m

0 0 0 78 177 177 Fin height

0 0 0 12.5 12.5 19 Fin thickness

0 0 0 1.9 1.9 1.9 Fin width

0 0 0 0 4.37 4.37 Fin conductivity

0 0 0 35 35 35 Tubes/row

38 38 38 38 38 42 Number of rows deep

4 4 4 2 16 8 Length

8.2 8.2 8.2 8.2 8.2 8.2 Transverse pitch

101 92 Longitudinal pitch

76 76 21 Parl = 0, Countr = 1

1 1 Tubes inline

arrgt.

Example 4.5

Tables 4.16 and 4.17 show the performance of a waste heat boiler in a chemical plant as provided by the HRSG supplier. Flue gas flow is 150,000 kg/h at 650°C and has an

analysis % volume CO 2 = 7, H 2 O = 12, N 2 = 75, O 2 = 6. Boiler generates about 27,684 kg/h of superheated steam at 40 kg/cm 2 g and at 316°C. Field data show performance close

to these predicted values. Now, the plant engineer wants to withdraw 8,000 kg/h of saturated steam from the drum for process heating and superheat the balance of steam when the gas inlet flow is 120,000 kg/h at 600°C with the flue gas analysis remaining the same as before. What will be the performance and steam temperature?

Solution

This problem is more involved unlike the earlier problem of checking field data. More iterations are required as we have no idea of the operating conditions at the new gas inlet conditions. Hence, this is a good exercise for evaluating HRSG off-design performance.

Let us estimate the LMTD and U at each section. Often information on gas–steam temperature profiles will be available in a boiler plant; if not, one may estimate the gas temperatures starting from the cold end and move to the hot gas inlet as was done in Chapter 3 for the steam generator. U may also be estimated for each section by methods discussed in Appendices C and D. Here since we know the gas and steam temperature profile, we may estimate the LMTD at each section. Counter-flow configuration is used. If the duty of each section is not provided, one can use the steam- and water-side data or field measurements, compute the duty and then estimate the gas temperature drop in each section. Water or steam flow measurement is typically more accurate than gas flow measurement, and gas temperature measurements at the cold end are more reli- able than those at hot gas inlet. So one may start at the economizer and work backward to obtain the gas flow and temperature at various sections and arrive at the data given earlier. As mentioned in several places in this book, plant engineers should demand such data from the boiler supplier for various load conditions so that they can deal with problems such as this one, which may arise after several years of operation.

S HRSG with Burner ahead of Superheaters

TABLE 4.15

team G

Burner ahead of HRSG

Fired Case

Unfired Case Process

at or

Data Surface

Evap. Evap. Econ.

Gas temp. in ±5°C

Gas temp. out-±5°C

0.2855 0.2768 0.2645 Dutr, MM kcal/h

Gas spht, kcal/kg °C

Surface area, m 2 149

Gas press. drop, mm wc

3.04 2.97 4.71 4.37 36.35 23.79 4.20 4.02 6.24 5.58 42.02 23.84 ea

Foul factor, gas

U, kcal/m 2 h °C

67.66 66.94 72.70 54.56 37.09 32.83 77.60 76.00 79.19 63.77 40.77 34.75 le oi

124 83 :F Max. gas vel., m/s rs 13 13 16 16 18 16 18 17 21 21 22 16

or P

Tube wall temp., ±5°C

Fin tip temp,. ±5°C

Fluid temp. in, °C

ss a Press. drop, kg/cm 2 0.20 0.18 0.0 0.0 0.0 0.2 0.8 0.7 0.0 0.0 0.0 0.7 n dP

Fluid temp. out, ±5°C

Foul factor, fluid

Fluid velocity, m/s

10.9 9.5 0.0 0.00 0.0000 0.67 21.9 19.2 0.0 0.0 0.0 1.3 n tE

Fluid httr. coefft.

Steam flow, kg/h

Spray, kg/h

Burner duty, MM kcal/h

Unfired

Fired

Gas Flow, kg/h

Evap. Econ.

38.1 38.1 50.8 50.8 50.8 44.5 ste H

Steam press., kg/cm 2 g 54.0 54 Gas temp. in, °C

Tube OD

Steam temp. out, ±5°C 360

CO 2 , % volume

2.40 Tube ID

30.6 30.6 44.1 44.1 44.1 37.8 ea

Steam flow, kg/h 48,447

100,000 H 2 O

7.00 Fins/in. or

Feed water temp., °C 109

N 2 75.50 fins/m

0 0 0 12.5 12.5 19 le

O 2 15.10 Fin height

0 0 0 1.9 1.9 1.9 rs

Fin thickness

Fin width

conductivity Tubes/row

Number of

rows deep Length

pitch Longitudinal

pitch Streams

parl = o,

1 1 Tubes inline arrgt. 1

countr = l

214 Steam Generators and Waste Heat Boilers: For Process and Plant Engineers

TABLE 4.16

Waste Heat Boiler Performance Data 150,000 kg/h Gas Flow

Process Data Surface

Gas temp. in, ±5°C

330 Gas temp. out, ±5°C

247 Gas spht., kcal/kg °C

0.2716 Duty, MM kcal/h

306 Gas pr drop, mm wc

Surface area, m 2 43 766

70.38 Foul factor, gas

0.0002 Steam Side

Steam press., kg/cm 2 g 41 41 41 Steam flow, kg/h

27,684 Fluid temp. in, °C

105 Fluid temp. out ±5°C

221 Pr drop, kg/cm 2 0.88 0.00 0.21

Foul factor, fluid

Tube Geometry Data

Tube OD 31.8 50.8 50.8 Tube ID

25 44 44 Fins/in. or fins/m

0 0 0 Fin height

0 0 0 Fin thickness

0 0 0 Fin width

0 0 0 Fin conductivity

0 0 30 Tubes/row

36 20 20 Number of rows deep

6 60 24 Length

2 4 4 Transverse pitch

90 Longitudinal pitch

Superheater ΔT = [(650 − 316) − (619 − 252)]/ln[(650 − 310)/(619 − 252)] = 350°C.

Then U = Q/AΔT = 1.36 × 10 6 /(43 × 350) = 90.2 kcal/m 2 h °C

Evaporator ΔT = [(619 − 252) − (330 − 252)]/ln[(619 − 252)/(330 − 252)] = 187°C

U= 12.24 × 10 6 /(766 × 187) = 85.44 kcal/m 2 h °C

Economizer ΔT = [(330 − 221) − (247 − 105)]/ln[(330 − 221)/(247 − 105)] = 125°C

U = 3.33 × 10 6 /(306 × 125) = 87.0 kcal/m 2 h °C

Waste Heat Boilers 215

Now at 120,000 kg/h gas flow at 600°C, we have to estimate the U values for each section. We may apply the methods discussed in Appendices B through D, or we may use the U values given earlier and correct it for gas flow and temperature. Let us correct the U values for gas flow effect for the first trial. Once we get a preliminary performance and gas–steam temperature profiles, we may use the correlations in Appendices C and D to fine-tune the U values.

Superheater U p = 90.2 × (0.8) 0.6 = 78.9 kcal/m 2 h °C (0.8 refers to 120,000/150,000

of gas flow ratio) Evaporator U p = 85.44 × (0.8) 0.6 = 74.7 kcal/m 2 h °C Economizer U p = 87 × (0.8) 0.6 = 76 kcal/m 2 h °C. We have to assume two values—the exit gas temperature from the boiler and the steam

temperature—and then fine-tune these later. Let us assume that the exit gas temperature is 240°C and the steam temperature is 370°C. The energy transferred by flue gas to

steam = 120,000 × 0.99 × 0.28 × (600 − 240) = 11.97 × 10 6 kcal/h, where 0.28 is the average

gas specific heat between 600°C and 240°C. The enthalpy of superheated steam at 370°C is 750.48 kcal/kg. Then superheated steam generated is obtained by energy balance.

Using zero blowdown, W s [(750.48 − 105.9) + 8000 × (669 − 105.9)] = 11.97 × 10 6 , where 105.9

is the enthalpy of feed water at 105°C and that of saturated steam is 669 kcal/kg. Hence, W s = 11,580 kg/h.

Superheater may be solved by using either the transferred duty evaluation of Q t = UAΔT or the NTU method. Let us use the transferred duty method.

Superheater Q a = 11,580 × (750.48 − 669) = 0.9435 × 10 6 kcal/h = 120,000 × 0.99 × 0.29 × (600 − T). (Flue

gas specific heat of 0.29 kcal/kg °C was used for the superheater region. Hence, exit gas temperature of superheater T = 573°C. Calculate ΔT as we know all the four temperatures at the superheater. ΔT = [(600 − 370) − (573 − 251)]/ln[(600 − 370)/(573 − 251)] = 273°C. Q t = UAΔT = 78.9 × 43 × 273 = 0.926 MM kcal/h. It is not close to the assumed duty, but let us proceed.

Evaporator Evaporator may be solved by using the method shown in Appendix A.

ln[(573 − 251)/(T − 251)] = 74.7 × 766/(120,000 × 0.99 × 0.283) or T = 310°C. Q t = 120,000 ×

0.99 × 0.283 × (573 − 310) = 8.842 × 10 6 kcal/h (a gas specific heat of 0.283 kcal/kg °C was assumed).

Economizer Q a at economizer = 120,000 × 0.99 × 0.27 × (310 − 240) = 2.245 × 10 6 kcal/h. Enthalpy

pickup of water = 2.245 × 106/(8,000 + 11,580) = 114.7 kcal/kg or exit water enthalpy = 105.9 + 114.7 = 220.6 kcal/kg or water temperature from steam tables is 215°C. (The water flow in economizer is 19,580 kg/h as the 8,000 kg/h of saturated steam has to be added to the superheater steam flow.) (Water-side specific heat = (220.6 − 105.9)/(215 − 105) = 1.042 kcak/kg °C. ΔT = [(310 − 215) − (240 − 105)]/ln[(310 − 215)/(240 − 105)] = 114°C or Q t =

76 × 306 × 114 = 2.651 × 10 6 kcal/h.) Since the difference is significant, another iteration is required. The actual duty Q t of entire HRSG = (0.9435 + 8.84 + 2.651) = 12.43 × 10 6 kcal/h. Revised steam generation = W s × (750.48 − 105.9) + 8,000 × (669 − 105.9) = 12.43 × 10 6 or W s = 12,300 kg/h. Using this value, let us go back to the superheater.

216 Steam Generators and Waste Heat Boilers: For Process and Plant Engineers

Superheater Use the NTU method now. Specific heat of steam = (750.48 − 669)/(370 − 251) = 0.6847

kcal/kg °C. (WC)steam = 12,300 × 0.6847 = 8421 and (WC) flue gas = 120,000 × 0.99 ×

∈ = [1 − exp(−0.4029 × 0.756)]/[1 − 0.244 × exp(−0.4029 × 0.756)] = 0.32 or Q t = 0.32 × 8421 ×

(600 − 251) = 0.94 MM kcal/h. Steam temperature at exit = 251 + 0.94 × 10 6 /12,300 × 0.6847 = 362°C. Exit gas temperature of superheater = 600 − 0.94 × 10 6 /9,120,000 × 0.99 × 0.29) = 573°C.

Evaporator exit gas temperature and duty will be the same as before as gas entering temperature is unchanged.

Economizer (WC) on water side = (12,300 + 8,000) × 1.042 = 21,152 and (WC) flue gas = 120,000 × 0.99 ×

∈ = [1 − exp(−1.099 × 0.341)]/[1 − 0.659 × exp(−1.099 × 0.341)] = 0.571 or duty Q t = 0.571 ×

21,152 × (310 − 105) = 2.475 × 10 6 kcal/h. Exit gas temperature = 310 − 2.475 × 106/9,120,000 × 0.99 × 0.27 = 233°C. Exit water temperature is (105 + 2.475 × 10 6 /21,152) = 222oC. Total duty transferred = 0.94 + 8.842 + 2.475 = 12.257 × 10 6 kcal/h. Superheated steam generated is obtained from energy balance: 12.257 × 10 6 =W s × (745.8 − 105.9) + 8000 ×

(669 − 105.9) or W s = 12,114 kg/h. Final steam temperature is 362°C, and its enthalpy is 745.8 kcal/kg. This is a closer estimation of performance. The gas–steam temperature profile is shown in Figure 4.31. The steam temperature increase is only about 46°C and hence will not affect the tube materials used.

One more iteration may be carried out to finalize the complete performance using the appropriate correlations and correct gas and steam properties. However, the purpose of this exercise is to show how plant engineers may evaluate the HRSG performance even if no operating data or performance data are available and they are doing what if studies.

Evaporator Economizer (a)

HRSG gas–steam profiles (a) with and (b) without export steam.

Waste Heat Boilers 217

As an exercise, plant engineers may see what happens if saturated steam of 8000 kg/h from another boiler is to be superheated in this boiler at the same inlet gas conditions. What will be the new steam generation and steam temperature when the same amount of steam is imported into the HRSG?

Performance with and without Export Steam