With the increasing liberalisation of the power markets and the associated separation of responsibility for power generation and distribution, the grid operator is now becoming ever more responsible for ensuring reliable operation of the interconnected power system in accordance with commercial requirements and mandatory obligations.

Primary control ensuring dynamic load/output compensation on a time scale of seconds is required for this operation. In conventionally operated combined-cycle power plants passive operation of the steam side limits participation in primary control to the gas turbines. However, a concept developed at Siemens Power Generation now enables targeted use of the steam turbine for primary control. This is achieved by a technique that has two components – an altered operating mode for the heat recovery steam generator and an additional co-ordinated operation of the gas turbine(s) and steam turbine. This additional co-ordination function is realised by a new module, inserted in the automation system and influencing the unit co-ordination control and the steam turbine control.

Control reserve

The primary control capacity required by the grid operator, which should correspond to a specific fraction of rated unit output, is usually maintained exclusively with the aid of the gas turbine. The steam side of the combined-cycle power plant is operated in natural sliding pressure mode (ie a passive mode). The following example explains distribution of the control reserve in the unit, which could be 10 per cent, typically, of rated unit output:

When the unit is operated at an output of 90 per cent of rated capacity, 10 per cent of unit capacity is available as primary control capacity. The gas turbine component for this control capacity corresponds to 6.6 per cent, and the steam turbine component to 3.4 per cent. The gas turbine component can be brought on line on demand in a few seconds. The lag in steam generation causes the steam turbine to react with roughly a one-minute delay, releasing its overall control capacity within a period of five minutes. As a result, out of the overall available control reserve of 10 per cent, only the gas turbine component of 6.6 per cent can be used for primary control purposes. This means that the gas turbine additionally has to supply the steam turbine component in order to still provide a control reserve of 10 per cent of rated unit output for primary control. The gas turbine can therefore only be operated at a base load that is further reduced by the magnitude of the steam turbine component.

In this case, provision of the primary control capacity is exclusively dependent on the increase in gas turbine output and is thus also subject to the thermal limits of the gas turbine. The dynamics of the gas turbine therefore determine the dynamic properties of the unit for primary control.

New concept

The steam side activation concept for provision of a primary control reserve is based on use of the storage capacity of the heat recovery steam generator. In contrast to the conventional mode of operation, with turbine inlet valves wide open (natural sliding pressure mode), the steam turbine is operated here in a modified sliding pressure mode. Implementation of a modified sliding pressure mode with throttled turbine inlet valves permits the thermal storage capacity of the individual pressure sections of the heat recovery steam generator to be exploited on demand. This storage capacity is maximised by raising the steam pressure in the individual pressure sections. This stored energy is then released as required in a co-ordinated fashion by controlled opening of the turbine inlet valves. Discharge of this stored capacity leads to a correspondingly rapid increase in steam turbine output. Steam production is temporarily decoupled from the heat input supplied by the gas turbine during this control process, and the steam turbine makes available its contribution to the primary control capacity in a time frame of a few seconds.

Operation of the control process

The block diagram for the control module is shown in Figure 1. The thermal storage capacity is built up by changing over from natural sliding pressure mode to modified sliding pressure mode. The setpoints in the unit control are modified in such a way that the turbine inlet valves are correspondingly throttled. On conclusion of the throttling process, the thermal storage capacity has been charged and the steam side is in modified sliding pressure mode, ready for the steam turbine to participate in primary control.

The grid frequency is compared with the setpoint frequency to generate a frequency-dependent setpoint component (?SETP) from the frequency deviation (?f). This component is then subjected to dynamic weighting (?SETPDYN). The component ?SETPDYN is fed to the unit co-ordination control to generate the control signals and is simultaneously subjected to static weighting for steam turbine control. The statically weighted signals are used to correct the steam turbine setpoint values and control deviations. This results in the desired release of control capacity through the control valves during a time interval of a few seconds.

To co-ordinate the actions of the gas turbine and steam turbine controls during the release of control capacity, appropriate control signals are generated by the module to be fed to the unit co-ordination control.

Once control capacity has been exhausted, the steam side is again automatically returned to modified sliding pressure mode.


A partial shift of the primary control capacity to the steam turbine has two significant advantages over the design concept used to date.

First, the desired primary control capacity can be kept in reserve at a higher base load (the requisite control reserve in the gas turbine is reduced by the steam turbine component); and second, the dynamic properties of the unit are improved by transient activation of the steam process (the power increase in the steam turbine can be achieved with the greater repositioning speed of the turbine inlet valves).

A prerequisite for implementation of the module is that all components of the water/steam cycle are designed to permit an operating mode. This is especially important for drum-type heat recovery steam generators, in which the ratio of usable drum volume to evaporator volume determines the magnitude of the possible control reserve.

The advantages for the operator are shown in Table 1, which gives the results for a combined cycle power plant with a rated unit output of 780 MW, comprising two gas turbines of 260 MW each and a 260 MW steam turbine. The scenarios with a ”passive steam side” and ”active steam side” are each considered in the state where a 10 per cent primary control reserve (78 MW) is maintained.

As Table 1 shows, the combined-cycle power plant can be operated at a 24 MW (3.1 per cent) higher base load with ”active steam side” control while maintaining the same primary control reserve. The shift in primary control reserve to the steam side can be increased at lower part load.

The slight increase in heat load due to throttling of the individual pressure sections is compensated by the improved efficiency of the turbines (especially gas turbines) operated at a higher output level.

The output curves for the gas and steam turbines, together with the combined output curve, are shown in Figure 2.


The new concept has already been implemented and tested in commercial operation at the 500 MW Poolbeg combined cycle power plant in Ireland.

Following successful testing, this control module was further developed, by a team consisting of the authors with Dieter Diegel, Reinhard Frank and Michael Henning, to combine all the required functions for operation with the ”active steam side” and is now commercially available. With necessary adjustments, the module can be used in existing control systems for upgrading of and retrofitting to combined cycle power plants.

Steam side activation results for a combined cycle power plant