4.3.3 Economic comparison of steam turbine drives with electric motor drives
On the majority of 500 and 660 MW units, a variable-speed drive to the 100% duty feed pump is provided by a back pressure steam turbine, using bled-steam from the main turbine HP cylinder exhaust and exhausting to the main IP/LP crossover.
Bled-steam tappings on the feed pump turbine itself have been used in the past to supply steam to one or more stages of HP feedheaters.
For large modern units (over 660 MW), the capital costs of the extra bled-steam pipework and the boiler feed pump turbine are significantly greater than the provision necessary for 50% electric feed pumps, which includes equivalent bled-steam pipework for the HP heater alone, plus electric motors (including reinforcement of the station electrical system to cope with the high motor-starting currents). Also, the first option usually includes a live steam connection direct from the boiler to the feed pump turbine for operational flexibility, even though the electric pumps are often used for starting. The live steam pipework is expensive, due to its high pressure duty.
There is usually no extra capital cost attributable to the required increase in rating of the main IP/LP turbines and the generator needed to supply the extra power for electric motor-driven feed pumps, since it requires only a marginal increase in steam flow (3%) of the main unit.
With all-electric feed pumps, the system is more compact (less floorspace) and simpler, needing fewer spares holdings. Because the pumps are freed from the constraints of steam pipework they can be placed in the ideal position for NPSH considerations, on the basement floor (instead of a few metres above it to accommodate the steam inlet pipework below the pumps) directly beneath the de-aerator (NPSH is defined in Chapter 4 and de-aerator height, etc., is discussed in Chapter 3). These factors can lead to savings in capital costs for the de-aerator and its civil engineering costs and the feed pump suction pipework between the de-aerator and the pump.
A steady state model of the thermal performance of the turbine and feedheating/pumping plant can be incorporated in a computer simulation program. Such a program can then be used to compare overall cycle efficiencies (it calculates the cycle heat rate) for different input data and can be used to compare the thermodynamic effects on the overall cycle of steam turbine-driven and electric motor-driven feed pumps. Figure 1.72 illustrates these thermodynamic effects graphically for a fixed 900 MW sent-out (SO) unit with a fixed main turbine exhaust area and pressure, for 50% feed pumps. Also shown, is an example calculation to determine the additional work done in the main turbine due to changing from a backpressure feed-pump-turbine drive to an electric-motor drive. This calculation is continued in Fig 1.73, where the additional work done in the main turbine due to not having steam turbine driven pumps is compared with the electrical power used (and associated generator, transformer, cabling, motor, gears and converter or fluid-coupling losses) to drive the motor-driven pumps. It can be seen that in this case, which is for a back-pressure feed pump turbine with no bled-steam tappings to HP heaters (for a future 900 MW unit), there is a unit heat rate improvement with electric motor-driven feed pumps.
The back pressure turbine option considered above has no bled-steam tappings for HP heaters because it has been found that, in practice, the improvement they give to the overall cycle efficiency can be offset by the effect of the main boiler feed pump availability on HP heater availability. Also, feed system stability problems have occurred with this type of system.
Overseas electricity utilities have tended to use condensing turbines with their slower 'International Class' pumps because they can give a better overall steam cycle efficiency (heat rate). Steam is usually extracted from the main turbine IP cylinder exhaust instead of the HP exhaust, and is therefore a lower grade of heat than that used for the back pressure turbine, and the steam is exhausted to the feed pump turbine's own condenser or to the main condenser. This has the advantage of reducing the steam flow (and hence leaving loss) through the main LP turbine, or of reducing its required exhaust area.
CEGB operating data demonstrates that feed pumps can achieve the same availability figure regardless of type of driver. Hence the savings in overall CEGB system running costs from the higher feed pump system availability of a 100% steam and two x 50% electric feed pumps, compared with three x 50% electric feed pumps, are not significant. (Typical feed pump system availabilities would be 99.96% compared with 99.92%.)