Regenerative feedheating has long been recognised as a means of improving turbine-generator plant efficiency and the first practical installation was on a 3 MW set in a British power station at Blaydon Burn near Newcastle-upon-Tyne in 1916.

From this modest beginning the modern feedheating system has evolved, a typical feed system consisting of six to eight heat exchangers, each bleeding steam from the appropriate turbine cylinder.

The economic justification for the use of a particular configuration of feedheaters is given in Chapter 1 of this volume, in which it is explained how the theory of regenerative feedheating is combined with the economic information the purchaser makes available to the manufacturers to determine the most appropriate number and disposition of feed stages. When the ideal cycle has been evolved, it is then used as a basis for the determination of a practical design. The economic need to replicate proven turbine and feed system components, whenever practical, places restraints on the manufacturer. Usually these are of a minor nature and will only change the ideal bleed point pressures by a few tenths of a bar. The minor loss in efficiency is accepted in return for the use of proven plant and the lower cost resulting from the replication of existing designs.

The main parameters for the feedheating systems of a range of typical modern 500 and 660 MW units are shown in Table 3.1. The corresponding heater arrangements are shown on Figs 3.1 to 3.6.

Table 3.1
Cycle parameters for modern power stations

Station Unit size (MW) Fuel Stop valve pressure (bar) Stop valve temp (°C) HP exhaust pressure (bar) Final feed temp (°C) Number of stages
HP   IP *
Type of LP heater Fig

Ince В







3   4



Grain 660 Oil 159.6 538 42.06 252.0 2   3 DC 3.2
Littlebrook D 660 Oil 159.6 538 42.0 251.1 2   3 Surface 3.3
Drax Completion 660 Coal 159.6 565 43.4 254.7 2   5 Surface 3.4
Heysham 2 660 Nuclear 159.6 538 45.2 156.4 0   4 Surface 3.5
Projected PWR units 660 Nuclear 66.77 + 5.86 226.7 3   4 Surface 3.6

* De-aerator not included in number

The turbine/boiler main cycle parameters of stop valve pressure (SVP) and stop valve temperature (SVT) have been standardised for all modern fossil-fired 500 and 660 MW units.

For all stations, the SVP is 160 bar; the SVT is 565°C for coal-fired boilers and 538°C for oil-fired boilers. The cold reheat pressure varies between 42 and 44 bar. As all feed systems for these units use cold reheat (HP turbine exhaust) to supply steam to the final heater, the final feed temperature (FFT) can only vary by a small amount due to the effects of small variations in cold reheat pressure and the terminal temperature difference (TTD) of the final HP heater.

Because of the economics of the advanced gas cooled reactor (AGR) cycle, a lower final feed temperature of about 156°C was specified (see Chapter 1) which has resulted in a feed system having the de-aerator as the final heater.

The relevant cycle details for the feed system for the pressurised water reactor (PWR) are also shown in Fig 3.6.

The steam conditions for the 660 MW PWR of 67 bar, 0.25% wet, result in the stop valve flow being approximately twice that of a conventional 660 MW unit and, in consequence, all flow components must be approximately 1.5 times their normal size to accommodate the doubled flow. The PWR feed cycle is also more complicated than conventional fossil-fired units as provision has to be made to absorb reheater and separator drains into the feed system under all conditions of operation, as shown in Fig 3.6.

Table 3.1 shows that the latest stations, such as Littlebrook D and Heysham 2, are provided with tubular surface type heaters to the exclusion of the 'direct contact' (DC) heaters (i.e., feedwater and heating steam in direct contact within the heater shell). The change in design philosophy was the result of a review, in the early 1970s, of the cost effectiveness of the DC LP heater systems which were then currently being employed.

It was concluded from the review that tubular surface type LP heater feed systems were more cost effective and they have been used for all subsequent 660 MW units.

As unit size increases, so does the power needed to drive the boiler feed pump (BFP), which is about 2 to 3% of main unit output. Multiple electrically-driven BFPs could have been used but a more cost effective solution at the time was to provide a turbine driving a full-duty feed pump. From Figs 3.1 to 3.5 it is seen that each system uses a back pressure turbine as the BFP drive. Steam is taken from the HP exhaust, expanded through the turbine and exhausted to the main turbine or to a heater. A live steam supply from the main boiler is provided on the latest generation of boiler feed pump turbines (BFPTs) to enable the turbine to drive the feed pump under all conditions of unit load. As an alternative route was provided for the BFPT exhaust to the condenser, the BFPT could also be run-up with the main unit. To increase cycle efficiency, heater bleed points on the BFPT are provided. However, more than one heater attached to the BFPT can cause difficulties in the feedheaters downstream of the heaters from the BFPT. The manner in which the BFPT has been integrated into the various feed systems is shown in Figs 3.1 to 3.6.

3.1 Arrangement of feedheaters at Ince B power station


3.2 Arrangement of feedheaters at Grain power station


3.3 Arrangement of feedheaters at Littlebrook power station


3.4 Arrangement of feedheaters at Drax Completion power station


3.5 Arrangement of feedheaters at Heysham 2 AGR power station


3.6 Proposed arrangements of feedheaters for a PWR nuclear power station

Cooling of the generator by condensate is not employed for the latest units. The complex and costly arrangements needed to ensure maintenance of prime and freedom from boiling of stagnant condensate in generator coolers on cessation of condensate system flow was the reason why a simple cooling package, with indirect coolers using condenser cooling water (CW), was developed and is now used. The loss in efficiency is accepted in return for increased operational integrity and simplification, with consequent reduced maintenance costs for the condensate system.


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