The 840 MW Marchwood combined-cycle power plant (CCPP) in the UK has to meet some of the strictest grid stabilization regulations in the world. Siemens Energy explains how this is achieved.

L. Balling, A. Pickard & U. Tomschi, Siemens AG, Germany

Although renewables are key to us achieiving a low-carbon future the growing percentage of renewable resources on the grid can result in its potential destabilization because of the inherent intermittant availability of these resources. Thus, power plants with a high degree of grid reliability, such as combined-cycle gas turbine (CCGT) plants, will become ever more important in order to compensate for this instability.

The requirements with respect to grid stabilization have recently become more rigorous, and power plant operators and suppliers are now presented with several operational challenges.

In a liberalized electric power market, the minimum requirements with respect to the power dynamics of a power plant are defined in grid codes. An example of some of the most stringent requirements imposed on plant dynamics can be found in the UK’s grid code primarily because of its island geography. Here we focus on three of the most critical dynamic properties: load stabilization at low frequencies; primary and secondary frequency response; and island operation capability.

Load stabilization at low frequencies

Normal fluctuations in the balance between power generation and consumption are reflected by variations in grid frequency which can be compensated by regular frequency control measures. However, the frequency can also decrease or even increase significantly in the event of unusually serious and uncommon disturbances.

Unfortunately a decrease in grid frequency also means a reduction in rotating speed and consequently a decrease in power output. This decrease in speed causes the compressor in the gas turbine to produce a reduced volumetric, respectively mass-flow, thus decreasing gas turbine output if appropriate measures are not implemented to compensate for this behavior.

The grid code in the UK stipulates that power output must be maintained down to 49.5 Hz. If a further decrease in frequency occurs, the grid code permits a maximum decrease in output of 5 per cent at 47 Hz (see Figure 1).

Figure 1: Load stabilization at low frequency in accordance with the UK’s stricy grid code

To counteract this power output decrease there are several measures that can be implemented at short notice to increase output. For example, by rapidly opening the inlet guide vanes (IGVs) on the compressor.

The fuel flow is increased at the same time. This can compensate for a drop in power of approximately 6 MW. However, in unfavourable operating conditions this increase in output will not be sufficient on its own to meet the requirement described above. In this case, a Siemens- patented fast-wet-compression concept can be used to mobilize a further power reserve of around 12 MW.

A spray of demineralized water is temporarily injected at the compressor inlet for this purpose. The mass of this injected water increases the mass flow through the compressor. The evaporating water also cools the air flow at the compressor inlet. The air density and consequently the mass flow through the compressor increases because of this cooling.

Rapid activation of the system constitutes a challenge for control systems because the increase in power output can only take effect at short notice if the gas turbine control and the water injection are perfectly coordinated through the optimized I&C system from Siemens.

The implementation of these grid support features has been validated and demonstrated in the Marchwood power plant in the UK, a F-class multi-shaft plant with a power output of approximately 840 MW and an efficiency in excess of 58 per cent (see Figure 2), as well in the Severn Power plant with two single shaft units of 420 MW.

Figure 2: The 840 MW Marchwood CCGT power plant, which was commissioned in late 2009

The measurements from the Marchwood project in UK are presented in Figure 3. It can be seen clearly that an 18 MW increase in output was achieved in each gas turbine by opening the compressor IGVs and then initiating fast-wet-compression. Together this enabled it to meet the requirement of the UK’s grid code.

Figure 3: Load stabilization test at low frequency at Marchwood (data from single gas turbine)

Primary and secondary frequency response

Historically the purpose of load stabilization at low frequencies was to prevent further destabilization of the grid when the frequency decreases because of major disturbances. However, nowadays primary and secondary frequency response are required for grid support during normal operation. For this purpose the grid code in the UK stipulates that a power plant operating at part load must be capable of making additional power available on a temporary basis.

A power plant operating at less than 80 per cent load must be able to make at least 10 per cent of its rated power available within 10 seconds in the event of a decrease in frequency. For a secondary frequency response, 10 per cent of rated power must be made available within 30 seconds. The requirements are reduced at loads over 80 per cent. The load must also be reduced by 10 per cent of rated power within 10 seconds in the event of over-frequency if the grid frequency rises by 500 mHz (high frequency response). The island operation requirement is even more stringent than this, and for this reason high frequency response will not be discussed further.

Unlike load stabilization at low frequencies, there is no need to look for a further power reserve in this case. No new systems are required. The challenge lies more in the speed at which the power must be made available.

To meet the requirements of the UK grid code, Marchwood relies on the fast repositioning of the compressor IGVs on the one hand, and on the other, fuel control optimization so that that load ramps are possible without destabilizing combustion.

Figure 4 illustrates the results of the test at Marchwood, demonstrating that the required additional power is achieved both after 10 seconds and after 30 seconds. In fact, the criterion is exceeded in both cases.

Figure 4: Frequency response test at low frequency at Marchwood (data from single gas turbine)

Island operation capability

Up to now the focus has been primarily on increasing power output, but for island operation capability the primary objective is to stabilize the island grid. In this case, it may happen that an island that has developed a power excess is suddenly faced with an abrupt drop in consumption.

This results in a very fast increase in grid frequency. The power plant must react to this frequency increase by throttling power in order to stabilize the frequency without causing a forced shutdown of the power plant because of over-frequency or any other uncontrolled process. An uncontrolled shutdown of power plants can result in a grid collapse.

This is why the grid code in the UK stipulates that a power plant must be capable of decreasing output from rated power to the design minimum operating level (DMOL) in a worst-case scenario. The DMOL must not be less than 55 per cent of rated power in this case.

This load reduction must be implemented quickly so that the island frequency remains below 52 Hz. Grid studies based on the UK’s grid code requirements show that the load reduction must occur within a narrrow window of 8 seconds.

The power plant must detect island formation of this kind automatically and take immediate action. As soon as island operating mode is activated, permitted load change ramps are set to the maximum value, and the IGVs in the gas turbine compressor are closed without delay.

At the same time, the different closed-loop controls ensure that power is decreased at the maximum load gradient. The primary objectives of closed-loop control optimization are flame stability and prevention of potential flashbacks in the combustion system so as to avoid an emergency shutdown of the gas turbine.

As can be seen in Figure 5, gas turbine output was decreased by 52 per cent within 4 seconds without initiating a plant trip as the result of a simulated fast frequency increase of 0.9 Hz during the test. A further decrease of 4 per cent was achieved in the following 4 seconds, thus also more than meeting the grid code requirement.

Figure 5: Island operation capability test at Marchwood (data from single gas turbine)

The Marchwood plant has demonstrated that all of the UK’s strict grid code requirements with respect to plant flexibility are fulfilled over and above its top efficiency of more than 58 per cent. The proven concepts and technologies are now ready for transfer to future F-class and H-class CCPP projects to support increasing operational flexibility and grid stabilization requirements.

Fast Cycling Concept

All the plant features highlighted above form part of Siemens’ FACY (FAst CYcling) concept that enables a reduction in start-up times while simultaneously increasing the number of allowable start-ups over a plant’s operating life. FACY is described as a fully integrated plant concept comprising: optimization of the turbine design; the heat recovery steam generator; the steam/feedwater/condensate cycle; and the start-up sequence and automation concept.

One of the advanced FACY features is the implementation of a stress controller to allow the plant operator to choose between fast, normal and cost-effective start-up modes, corresponding service intervals and utilization of service life. In the light of these conditions and the high start-up reliability of CCPPs, a daily shutdown and start-up with FACY is an economical solution to reduce the impact of nightly losses.

In combination with an efficiency of over 58 per cent with Siemens’ SCC5-4000F plant concepts, as installed at Marchwood and Severn Power, this maximized operational flexibility ensures a higher dispatch rate compared to conventional power plants.

FACY also significantly increases plant start-up efficiency, and in combination with a nightly shutdown mode – reduces carbon dioxide (CO2) emissions and increases overall power plant profitability.

A concept of this type offers two fundamental advantages. Firstly, the optimized start-up process minimizes CO2 emissions by shortening the start-up times during which the plant is operated at a relatively low efficiency level. Optimum plant efficiency is thus reached faster and total emissions are reduced. Secondly, the increased number of allowable start-ups over the operating life of the plant and the reliable plant start-up behaviour also enable nightly plant shutdowns. This enables a further reduction in CO2 emissions by eliminating inefficient overnight ‘parking operation’.

Customers thus benefit through fuel savings and a reduction in carbon emissions. Simply by reducing the start-up time for a hot start an estimated added value of more than €3 million ($4.3 million), assuming that the savings are realized over the service life of a 430 MW power plant.

Night time parking option

The option of shutting down the power plant overnight offers a further potential in the form of operating cost saving. Night-time electricity prices in Europe are very low so that a CCPP can no longer be operated at a profit during the night because of high gas and carbon costs. In order to minimize these losses, power plants are often ‘parked’ at part load or shutdown altogether at night.

Reducing the load already brings about a significant reduction in losses. However, when load decreases so does overall plant efficiency, resulting in a disproportionately small reduction in gas and CO2 costs.

Although shutting a power plant down at night instead of reducing load results in a significant reduction in losses during this phase because the power plant consumes very little fuel and emits negligible emissions at standstill, but start-up and shutdown costs must still be accounted for in an evaluation of cost-effectiveness.

The CO2 and fuel savings that can be achieved by night-time shutdown compared with night-time parking operation at a part load is approximately 25 per cent. At 200 starts per year, a CCGT power plant can avoid up to 130 tonnes of gas consumption and 362 tonnes of CO2 emissions per night through night-time shutdown. This can increase annual power plant profit by €4.8 million as compared with night-time part load operation.

Currently, grid support features are specified primarily by the grid access requirements of the individual countries. No monetary valuation of the additional plant flexibility is included in tender specifications as of yet. For this reason, today’s plants are designed purely based on country specific grid code specifications.

Depending on the level of electricity market liberalization, the different flexibility features allow the potential generation of additional earnings, first of all by participation in the frequency reserve market. Furthermore, grid operators in several countries are demanding power plants with higher reliability and higher operational flexibility, and are willing to pay extra capacity charges for such units

In the absence of any adequate far-reaching storage or compensation concept, fast and reliably starting and environmentally friendly fossil power plants, especially gas turbines and CCPPs, will remain a major backbone for a low-carbon future.

The plant features and concepts described above can help to secure reliable power supply and grid stability, and enable the fast growing market penetration of intermittent renewable power generation to further reduce CO2 emissions in Europe and elsewhere.

Power Engineering International Archives
View Power Generation Articles on