Table 73 Plant Energy Supply System Considerations Example

Process steam demands

Net heat to process at 250 psig. 410°F—317 million Btu/hr avg.

Net heat to process at 80 psig, 330°F—208 million Btu/hr avg. (peak requirements are 10% greater than average values) Process condensate returns: 50% of steam delivered at 280°F Makeup water at 80°F Plant fuel is 3.5% sulfur coal

Coal and limestone for SO2 scrubbing are available at a total cost of $2/million Btu fired Process area power requirement is 30 MW avg. Purchased power cost is 3.5 cents/kWh steam conditions are 1450 psig, 950°F with automatic extraction at 250 psig and 80 psig exhaust pressure. The boiler plant has three half-size units providing the same reliability of steam supply as the Base Case. The feedwater heating system has closed feedwater heaters at 250 psig and 80 psig with a 20 psig deaerating heater. The 20-psig steam is supplied by noncondensing mechanical drive turbines used as powerhouse auxiliary drives. These units are supplied throttle steam from the 250-psig steam header. For this alternative, the utility tie normally provides 4.95 MW. The simplified schematic and energy balance is given in Figure 7.16.

The results of this cogeneration example are tabulated in Table 7.4. Included are the annual energy requirements, the 1980 investment costs for each case, and the annual operating cost summary. The investment cost data presented are for fully operational plants, including offices, stockrooms, machine shop facilities, locker rooms, as well as fire protection and plant security. The cost of land is not included.

The incremental investment cost for Case 1 given in Table 7.4 is $17.2 million. Thus the incremental cost is $609/kW for the 28.25-MW cogeneration system. This illustrates the favorable per unit cost for cogeneration systems compared to coal-fired facilities designed to provide kilowatts only, which cost in excess of $1000/kW.

The impact of fuel and purchased power costs other than Table 7.3 values on the GPO for this example is shown in Figure 7.17. Equivalent DRR values based

Fig. 7.16 Simplified schematic and energy-balance diagram: Example 6, Case 1. All numbers are flows in 103 lb/hr; Plant requirements given in Table 7.8, gross generation, 30.23 MW; powerhouse auxiliaries, 5.18 MW; net generation, 25.05 MW.

on first-year annual operating cost savings can be estimated using Figure 7.15.

Sensitivity analyses often evaluate the impact of uncertainties in the installed cost estimates on the profitability of a project. If the incremental investment cost for cogeneration is 10% greater than the Table 7.4 estimate, the GPO would increase from 3.2 to 3.5 years. Thus the DRR would decrease from 17.5% to about 16%, as shown in Figure 7.15.

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