2 Combined cycle operating flexibility

Nowadays, existing and new combined cycle power plants must face with the challenges of the liberalized electricity market. Further on, also the compliance with more stringent environmental requirements is becoming more and more important, introducing additional constraints on the plant operation.

Typically, combined cycle power plant built in the 1990’s and early years of the new millennium have been designed for base load operation, favouring higher efficiency and lower capital costs, with the main objective of minimizing the cost of electricity production.

Today, a number of operating combined cycle plants are used to cover intermediate and peak load constraints. Therefore, new plants shall be designed for cycling load regimes, to meet recent power market requirements for fluctuating operation, so to cover the daily and seasonal variation of the electricity demand.

Drivers for this new operating philosophy are the risks related to the floating of the fuel and electricity prices, combined with a generating capacity of the power industry in the developed countries that exceeds the actual market demand, particularly in the current scenario of the global economic crisis.

Depending on seasonal load and the dispatch rank of the plant, driven by competition and fuel prices, the newly designed NGCC plants operate as cycling units over their lifetime, increasing load during the day or peak hours and reducing it to the minimum or shutdown during the night or when the electricity demand is low.

As a matter of fact, high flexibility becomes a must for the design and operation of combined cycles, also considering that advanced cycling capability and high efficiency are required at base, as well as at partial loads.

Figure 2-1 shows a possible daily behaviour of the electricity demand. This trend can be typical for many countries, though it may slightly change or having differences in timing in other locations. For example, UK has a shorter morning peak and has generally no need for air conditioning, while there is an earlier evening peak for and early dinner.. In the recent years, the use of Natural Gas Combined Cycles (NGCC) has been increased to cover both variable electricity demand, during day and night (or during the different seasons), and load regulation all over the entire period.

In general, it can be stated that operational flexibility of the combined cycle plants requires:

  • A lower and lower technical minimum environmental load;
  • Good efficiency at partial load operation;
  • High cycling capability (e.g. fast start-up and shut down, fast load change and load ramps, low start-up emissions, high start-up reliability);
  • Frequency control;
  • Low operating costs (high start-up efficiency or short start-up time).

It is also noted that a flexible plant opens up new business opportunities, like utilizing hourly and seasonal market arbitrage, participation in ancillary energy markets or peak load market. Of course, a power plant designed to meet these market requirements shows an investment cost higher than a traditional base-load plant.

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Figure 2-1. Typical daily electricity demand curve

2.1 Technical minimum environmental load

The technical minimum environmental load is defined as the minimum condition at which the Gas Turbine is able to operate, still meeting the environmental limits, in particular NOX and CO emissions.

Actually, the minimum environmental load is generally related to the limits on the NOX emission, as shown in the following Figure 2-2, which illustrates NOX behavior as a function of the gas turbine load.

The CO behavior is similar, though the limit on the minimum load imposed by the CO emission would a little less stringent than the limit on NOX emission. In fact, the CO tent to be more stable down to lower loads, increasing extremely quickly up to very high figure.

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Figure 2-2. NOX emission changes with GT load

The most recent Gas Turbine designs have tried to reduce the technical minimum environmental load, because this allows to:

  • Run the plant in a wider range of production loads. In this way the GT and, consequently the entire combined cycle, can better follow the daily or seasonal electricity demand variations, while meeting the environmental limits.
  • Limit the economic losses during the non remunerative hours, like night hours, through the possibility of running the GT at low load and being able to increase load suddenly, to follow grid services. Otherwise, plant shall be shutdown, to limit economic losses, but in this case it cannot be ramped up so quickly, when required.
  • Reduce the emissions during the plant start-up phase.

Depending on the Gas Turbine manufacturer, it can be stated that nowadays the technical minimum environmental load is generally in the range between 30% and 50% of the base load power production.

2.2 Partial load operation

The combined cycle power plants put in operation in the 1990’s and in the early years of new millennium have been designed for an optimum operation (highest efficiency) at base load. Therefore, their efficiency at partial load is significantly lower than the base-load point. This is intrinsic for the technology, as even at “full-speed-no-load” mode, the power requirement of the GT compressor is significant.

As new plants are requested to operate both at base-load and at partial load over their lifetime, power production shall be optimized along the daily and seasonal floating behavior, to improve the overall economics also when the electric power demand is low.

Figure 2-3 shows the typical net overall plant efficiency vs. GT load for newly designed power plants.

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Figure 2-3. Overall plant efficiency vs. GT load

It can be noted that the efficiency reduction at partial load is relatively low, as the plant achieves an overall efficiency of 55-56% even at 60-65% of the load. Actually, the efficiency penalty corresponding to a load reduction down to 60% is only a few percentage points (2-3%) lower than the base load operation, even if the expected impact on the cost of electricity is much higher (7-8%), as the cost for fuel consumption represents a significant portion in the economics of a natural gas combined cycle.

2.3 Start-up and cycling capability

As an answer to the changed market requirements, and in particular to the daily trend of electricity demand, cycling capability in combined cycle power plants shall be optimised to fulfil the nightly and weekend load reductions or shutdowns. In addition, time required for the subsequent hot start-up (after night shutdown) and warm start-up (after week-end hours shutdown) shall be reduced as much as possible. The cold start-up times after an extended outage (generally longer than 120 h) shall be also low, even if it is usually of low importance as it is generally required few times per year.

For a combined cycle designed to meet these requirements, the economics of the plant are significantly improved because of the following reasons:

  • Possibility to follow the seasonal or daily market trend.A flexible plant can be shutdown in case the electricity prices do not cover the variable costs and run when operation is economically convenient. These plants take advantage from high prices of electricity, while not operating when electricity prices are low, i.e. would result in an economic loss.
  • Higher electricity production during the hours of remunerative service of the plant and greater ability to follow the load changes requirements.
  • Reduced start-up costs through fuel saving, because of the short gas turbine operation in non-profitable loads, i.e. at low efficiency and through fast change over from steam bypass operation to combined cycle operation.
  • Reduced NOX and CO emissions, as lower time is required to reach the technical minimum environmental load.
  • Capability to participate in ancillary services markets.A fast load changing plant can participate in markets for spinning reserve, which means that the plant must provide a guaranteed output in a specified period of time, as well as in hour-reserve markets, where the output must be available after one hour. These operating conditions may be an option to the nightly shutdown.

Table 2-1 compares the typical start-up times of plants built in the 1990’s (base-load) with those of most recent designs for flexible operation. To achieve this reduced start-up time and high cycling capability, some improvements in plant design have been introduced in the last years. This is the result of a significant work made on some of the key features of these plants, which limited their operative flexibility in the past years, like:

  • Gas Turbine and Steam Turbine ramp restrictions;
  • Heat Recovery Steam Generator ramp restrictions;
  • Vacuum system and steam chemistry.

Table 2-1. Comparison of start-up times

Start-up type (to full load) Base-load plants (1990’s) Flexible plants (recent design)
Hot start (night S/D) 90 min 45-55 min
Warm start (weekend S/D) 200 min 120 min
Cold start (120 hours) 250 min 180 min

A key element to optimise the unit start-up process and to significantly increase the load output during start-up is the use of final-stage, high-capacity attemperators in the high pressure and medium pressure reheat steam lines, so to adjust steam temperature end meet the steam turbine requirements.

In the past years, the steam temperature was controlled by varying the gas turbine load and, consequently, the exhaust gases temperature and flowrate. The introduction of final SH and RH steam attemperators has allowed to decouple the gas turbine from the steam turbine start-up and to increase the load output of the gas turbine during start-up, keeping the steam temperature constant and optimal for the operation of the steam turbine. In fact, steam turbine loading ramp is normally limited by temperature transients, not by pressure and/or mass fluctuations.

Because of this decoupling, it is possible to start-up quickly the gas turbine, while the steam turbine is put in operation with its dedicated, slower ramp. Moreover, it is also assured a much greater cycling capability for the entire power plant, as this can follow the load variations with the gas turbine first and then with the steam turbine.

On the other hand, the use of once through steam generators (e.g. Benson design), typically for small-scale power plants, has further reduced the restrictions on the temperature and pressure transients, thus improving the operational flexibility both during start-up and load changes. The Benson design, in fact, eliminates the high pressure thick wall drum and allows an unrestricted gas turbine start-up, including a high number of fast start-up and load changes.

In the steam drum of a conventional HRSG, in order to reduce the inertia relevant to wall drum, the steam generator hold-up shall be significantly reduced, so to decrease drum size and thicknesses. This helps to reduce the inertia in the HRSG, due to the excessive thickness of the drum, designed to operate at high pressure.

Another key element that reduces the start-up duration of the combined cycles is the possibility to avoiding HRSG cooling when the plant is not in operation. In fact, by reducing heat losses, it is possible to reduce considerably the restart-up time. Also, automated drains and vents shall be installed to minimize steam losses during the shutdown phases.

Moreover, in order to minimize heat losses due to natural convection phenomena, two actions can be taken: to consider an insulated breeching between the steam generator and stack, as well as to install a stack damper to minimize the HRSG cooling for natural convection.

The installation of a stack damper, as a matter of fact, also limits the velocity of the HRSG pressure decreasing during a plant shutdown. In case of nightly shutdown (8 hours) the installation of the damper is absolutely recommended, as also shown in Figure 2-4.

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Figure 2-4. HRSG Pressure profile during shutdown

Some manufacturers also provide active measures to keep steam generator warm during hot start-up, introducing an auxiliary boiler that generates low pressure steam to be circulated in a sparging system in the steam drum components, to keep them warm.

A further element to reduce the start-up duration is to maintain the vacuum condition overnight, to prevent air inlet into the condenser hot-well. To achieve this, an auxiliary boiler providing steam to the steam turbine gland system during shutdown and mechanical vacuum pump for evacuating the condenser before the Gas Turbine start-up may be used. This alternative shall be evaluated carefully, as the steam extracted from the condenser shall be either vented (with consequent loss of demineralized water) or condensed in the gland steam condenser (with consequent necessity to keep in operation condensate pumps).

By introducing the above-mentioned design changes in the combined cycles, the start-up sequence of recent plants has been optimised, in order to reduce its duration and allow fast start-up in accordance to the actual market requirements. A qualitative trend that shows both the past and improved start-up curves is also shown in Figure 2-5.

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Figure 2-5. Sequential plant start-up concept

Typical load change rates for the whole combined cycle during hot start-up sequence are reported in Table 2-2.

Table 2-2. Ramp rates for combined cycle power plant

Load range Ramp rates % rated power / min
0% to 40% GT load (GT at minimum environmental load) 3 – 5
HRSG pressurisation 1 – 2
40% to 85% GT load 4 – 6
85% to 100% GT load 2 – 3

In the past years, the plant start-up was performed through the steps described in the following:

  • The Gas Turbine was accelerated and synchronized to the grid at the minimum load of about 20%, although the environmental limits on emissions were not met.
  • The exhaust gases were passed through the HRSG and steam production dumped directly to the condenser through full capacity bypass stations. At the same time, the steam turbine and steam piping were warmed-up, while steam characteristics were adjusted to meet the turbine requirements.
  • The pressurisation of the HRSG in the start-up sequence begun when the gas turbine was at the minimum technical load required to produce steam at an acceptable temperature for the steam turbine, i.e. about 20%.
  • When all preconditions were fulfilled, then steam turbine was accelerated and synchronised, and steam was taken over until the bypass stations were closed (operation in fix pressure mode).
  • Finally, Gas Turbine loads were increased up to full load and the Steam Turbine followed the increased steam production. At higher loads, the Steam Turbine was operated in sliding pressure mode.

In Figure 2-6, the “old” start up sequence is shown. After the GT start up, HRSG pressurisation and ST synchronisation was carried on with the GT at its minimum load, corresponding to about 20%. This was the figure selected in order to allow the pressurisation of the HRSG at low pressure, and the preheating and synchronisation of the ST with a correct steam temperature (about 400°C).

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Figure 2-6. “Old” start-up sequence

In newly designed power plants (refer to Figure 2-7), the pressurisation of the HRSG in the start-up sequence begins when the gas turbine is at the technical minimum environmental load (approx 40%), in order to reduce start-up emissions.

At this load, with respect to the older start-up sequence, a larger amount of steam is generated in the HRSG, at a temperature higher than the one acceptable by the steam turbine. As a consequence, an increased size of the bypass valves and final attemperators for high pressure steam and hot reheat steam are required. In fact, after the synchronisation with the grid, the GT is loaded continuously with its maximum allowable load ramp up to base load, while by means of final steam attemperators and bypass, the steam turbine is started-up following its dedicated, slower, load increasing rate. This procedure can allow a total plant start-up time around 45-55 minutes, versus 90 minutes of the older plants.

Figure 2-6 and Figure 2-7 highlight the different minimum load during the old and the new start-up sequence, as a result of higher minimum technical environmental load of the gas turbine. The reduced start-up time achieved with the new start-up sequence is not shown in these graphs.

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Figure 2-7. “New” start-up sequence

Recently, some of the major gas turbine and combined cycle Vendors, like Alstom, GE Energy, MHI and Siemens, have officially presented the flexibility features of the next-generation plants, which can be summarized as follows:

  • GE Energy claims that its last package, the “FlexEfficiency 50”, will ramp up at a rate of 51 MW per minute, while maintaining the emission limits of 50 ppm NOx, while going from hot start to full rated power in 28 minutes (85% load in less than 20 minutes). The combined cycle part load efficiency will be greater than 60% down to 87% of the plant’s base load power output. The CCPP will turn down to 40% of its load while maintaining the emission limits, thus corresponding to a minimum environmental load for the gas turbine of 30%.
  • The new Siemens’ H Class unit achieved the highest base load operational efficiency of 60.75%. The combined cycle is capable of ramping up at 35 MW per minute. The plant can operate stably at load lower than 20% of the rated power output, with an efficiency typical of peak load power plants.
  • Alstom is claiming a base load efficiency of 61% and the best all-round efficiency over the entire load range, achieved with their last GT26. The combustion system is designed to operate over a wide range of Wobbe Index range, maintaining the NOx emission under 25 ppm at 15%O2 dry from 100% down to 40% of the combined cycle base load power output, as well as at the low parking point. Alstom also claim a ramp up rate of 350 MW in 15 minutes from low load.
  • MHI J series gas turbine achieves a gross thermal efficiency exceeding 60%, but MHI aims to reach 61% later this year. The combined cycle is characterised by a part load efficiency of 55% at 50% load.

2.4 Grid services

Grid services are traded as independent products in liberalized energy market. They are necessary to guarantee grid stability because a stable electrical grid frequency is essential to assure the efficient and safe operation of the electrical users.

Frequency changes occur whenever the electricity supply and demand are not in balance. Frequency control is generally made in three different steps:

  • Primary frequency control: it avoids grid instability, keeping the grid frequency inside a narrow range of acceptable values;
  • Secondary frequency control: it restores the nominal value of grid frequency;
  • Tertiary frequency control: it restores the reserve in case the entire margin kept by plants participating to the secondary frequency control has been used. It may require the start-up of warm stand-by plants.

In many countries, some of the frequency response capabilities (at least the primary) are mandatory for power plants interconnected with the national grid. They must be able to respond quickly, i.e. within a few seconds after a first limited variation in grid frequency. Active reserve to be guaranteed by power plants connected to the grid corresponds to a certain percentage of their net power output production, depending on the local legislations.

The participation in market for optional spinning reserves can significantly increase the plant economics, provided that the plant is able to fulfil the grid requirements. The earnings in these markets normally are split in a payment for the capability to provide the power (availability fee) and a payment for effectively generated and delivered power (utilization fee), which is normally significant higher than the daily market price fluctuations.

Nowadays, depending on the requirement of the grid, plant owners can optimise their load profile participating both in ancillary service markets and power markets.

2.5 Peak load market

Power production in combined cycle power plants can be increased during peak electricity demand hours, by:

  • Air chilling.
  • Gas Turbine over-firing.
  • HRSG post-firing.

Participation in the peak load market increases the economic value of the plant, as the electricity price increases when the demand for a service is at its highest.

2.5.1 Air chilling

The Gas Turbine efficiency and power generation decreases when the ambient temperature increases, as the inlet volumetric air remains constant and consequently the mass flowrate results lower.

Since spot market prices for power generally increases in summer, in countries where the peak power demand is in this season, the reduced gas turbine output at high temperatures affects the economics of a power plant.

One solution to this problem is to install gas turbine inlet air cooling, in order to reduce the temperature at the GT air intake and improve the performance of the machine.

The three most common options for inlet air cooling are: evaporative cooling, refrigeration chillers and inlet fogging.

In evaporative cooler and inlet fogging the air cooling is achieved by means of water vaporisation in the GT air intake duct and therefore humidification and refrigeration of the air at GT compressor inlet. Evaporative cooler and inlet fogging typically exhibit a low capital cost per marginal increase in power output, but become less effective as the relative humidity of the inlet air increases.

In the system based on chillers, instead, the air at GT intake is cooled down by means of chilled water heat exchangers. Although chillers can increase the gas turbine power output, independently from the ambient air relative humidity levels, they have higher capital costs with respect to the previous systems. Moreover, the energy requirements for chillers are significantly higher than the evaporative cooling and fogging system, affecting the overall power plant performance. Finally, the use of chillers leads to the increase of heat load for cooling system and therefore higher investment cost and plot plan requirements.

2.5.2 Gas Turbine over-firing

Over-firing of the gas turbine consists of operating the Gas Turbine at peak load conditions, corresponding to a production capacity a few percentage points higher than the base load. This can be done during peak electricity demand hours, in order to increase the electricity production for a limited time, when required by the market.

During this operation the metal temperatures of some components increase, so prolonged operation at peak load leads to more frequent maintenance and replacement of hot-gas path components, thus increasing the plant operating costs.

2.5.3 HRSG post-firing

Steam generation, and consequently steam turbine power output, can be increased, if required during peak load hours, by firing additional fuel in the post-firing system of the Heat Recovery Steam Generator. This reduces the overall plant efficiency, but increases the net plant electricity production and, therefore, allows the plant covering the higher production requirements, when needed.

The post firing system acts directly on the steam generation and the steam turbine performance and, therefore, the increase/decrease ramp rates are much lower if compared with the gas turbine or the over-firing mode, as they are significantly limited by the steam system inertia.

The addition of post firing in HRSG leads to the increase of the investment cost both of the HRSG itself and of the steam turbine, which shall be greater size, in order to expand the higher steam flowrate.

2.6 Aeroderivative gas turbine

The aeroderivative gas turbine technology has several features that provide an answer to the needs of the liberalized electricity market, in particular for their capability to participating in the peak load market and their possible use as integrated with a renewable energy source.

These machine types have an efficiency generally greater than 40%, which is among the highest value for simple cycle applications, and can reach full power in 5-10 minutes, depending on the gas turbine generator size. They are also capable to follow the grid power demand trend with ramp rates of up to 50 MW/min, thus allowing the plant to reach the target load within few seconds.

In addition, these turbines do not require maintenance activities longer than other machines, even for cyclic operation, i.e. with daily start-up and shutdowns.

Another key advantage of this technology is the flexibility to accept a wide range of liquid and gaseous fuels, also meeting stringent emission limits by using a Dry Low Emission (DLE) combustion system.

The characteristics listed above make the aeroderivative gas turbines particularly suited for the flexible operation of a power plant, including daily start and stop operation, peaking application and grid stabilization during demand changes, as well as to provide power during forced outage of major power plants.

Another natural application of these machines is in conjunction with renewable energy sources, as wind or solar farms, which by their intrinsic nature are intermittent.