Utilities in many parts of the world are turning to gas-fired combined cycle cogeneration plants to cut emissions through increased plant efficiency and better fuel utilization. To address this market need, Alstom has optimized its KA26 combined cycle unit to offer unparalleled flexibility for both heat and power production, as Christian Bohtz writes.

Combined cycle CHP plants have several key advantages over coal-fired boilers. Switching from coal to cleaner-burning natural gas cuts carbon dioxide emissions by half. Compared to electricity only systems, CHP plants also offer a much higher fuel utilization, of about 90%. This further reduces emissions, since less fuel is burned to generate the same amount of power and heat.

A challenge in cogeneration or district heating (DH) systems, however, is that power and heat are not always required at the same time. Heat is usually subject to seasonal variation, typically being needed in the winter. Power, meanwhile, is subject to daily change. Less power is typically needed at night when demand is low.

Having a system that has the flexibility to meet power and heat demand at the same time can therefore be a great benefit to utilities. Alstom has therefore adapted its KA26 combined cycle power plant to the demands of CHP, to offer the market the ‘ecoHEAT’ system.

The name ecoHEAT is derived from its ability to produce economic and ecological heat – which is increasingly important in Europe since the introduction of the CHP Directive several years ago, as well as in other parts of the world where efficient heat production, whether for industry or district heating, is a key consideration in the energy economy.

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The Emsland plant is capable of fast start and quick response to changing demand conditions, with high efficiency and low emissions even at part load


Alstom’s KA26 combined cycle power plant is based on a gas turbine and steam turbine in a combined cycle arrangement. Each power train typically consists of:

• one GT26 heavy duty gas turbine equipped with sequential dry low NOx combustors;

• a triple pressure heat recovery steam generator (HRSG);

• one triple pressure reheat steam turbine (ST) connected to a hydrogen-cooled generator common to the GT and ST (single shaft arrangement).

Alternatively, the gas and steam turbine can each be connected to its own, air-cooled generator (multi-shaft arrangement).

When used for electricity only (condensing mode), a KA26 combined cycle block with the ecoHEAT adaptation is capable of delivering about 430 MW of electricity at a high electrical efficiency of around 59%. However, a slight compromise on electrical power output, around 50 MWe, allows for significant heat production: it can supply up to 250–280 MWth for the district heating system and achieve a fuel utilization of up to 90%. A key benefit of the system is that it offers efficient heat and power production over a wide load range, including a low load operation mode.

This wide operating range can largely be attributed to the design of the GT26 gas turbine, which is perfectly suited to cogeneration.

The gas turbine is designed to run on natural gas, although fuel oil can be used as back-up. The combustion system allows a wide range of natural gas compositions to be burned including natural gases with large high hydrocarbon content.

The KA26 ecoHEAT is designed to offer utilities the flexibility to meet power and heat demand at the same time. With the two revenue streams from power and heat, the cogeneration power plant with a high fuel utilization is not only ecological, but also economic.


The GT26 uses the concept of sequential combustion, or reheat cycle concept. Compressed air is heated in a first combustion chamber (EV or EnVironmental combustor) by adding about 50% of the total fuel (at baseload). After this, the combustion gas expands through the single stage high-pressure (HP) turbine, which lowers the pressure by about a factor of two. The remaining fuel is added in the second combustion chamber (Sequential EV combustor, SEV), where the combustion gas is heated a second time and finally expanded in the four-stage low-pressure (LP) turbine.

Loading is carried out in several phases: the initial ignition of the EV burners; the subsequent ignition of the SEV burners; and then loading of the GT by opening the compressor variable guide vanes (VGV) to allow a greater air mass flow through the GT.

The operational features of the sequential combustion system are characterized by:

• operational flexibility from 100% down to 40% combined cycle load and below;

• high part-load efficiency;

• low NOx emissions at full load down to 40% part load;

• fuel flexibility regarding gas composition.

Steam can still be supplied for heating in part load operation.

The sequential combustion system also allows low load operation (LLO). The LLO capability provides the possibility of avoiding a plant shutdown at short periods of low power demands. This LLO concept has proven profitability versus a start/stop operating regime. A further advantage is the faster availability of power and quicker response to sudden power demand such as in the case of an unplanned outage of other plants serving the grid.

Low load operation takes advantage of the possibility of shutting down the sequential SEV combustor at low part-loads, while keeping the EV combustor on nominal conditions. This allows the plant to be operated in combined cycle mode at a very low load – i.e. about 20% of baseload output – while keeping NOx and CO emissions below legislated limits.

In this mode, the steam turbine can still be kept in operation so that the plant can provide about 90 MWth of heat for the district heating system and about 50 MW of electricity. Fuel utilization is still as high as 75% and the plant is ready to load up anytime.

There is a further optional adaptation, where additional bypasses can be used to take the steam turbine out of operation. This allows a further reduction of electrical load to about 20 MWe, while still producing up to 150 MWth of heat. This operation mode is a great advantage in situations where there is a high demand for heat and low demand for power, for example during the night.

In addition to the large operating range, Alstom has also optimized the KA26 plant arrangement for district heating applications. The KA26 ecoHEAT has a very compact single-shaft design, where even the district heaters are oriented in the shaft line for easy access to the single shaft for maintenance. Alstom’s proprietary way of steam extraction enables a standard, floor-mounted arrangement. This avoids an expensive table-mounted design, where the steam turbine, generator and gas turbine need to be lifted with a heavy concrete structure by several metres.

In the last 67 years, Alstom has installed more than 150 GW of combined cycle plants in 95 countries on a turnkey basis. This includes plants in all fields of CHP applications, such as desalination, chemical and petrochemical plants, refineries, pulp and paper and district heating. The KA26 combined cycle power plant, for example, is being used at large CHP plants in Russia, Germany and the UK.

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In condensing-heating mode, the new CCPP in Moscow provides up to 265 MWth heat with fuel utilization above 85%


Russia has the world’s largest district heating system, with district heating plants providing more than 70% of the heat supply. In large cities, between 70% and 95% of homes are connected to a network of district heating pipes, whose total length amounts to 200,000 km. Around 30% of the heat is produced by nearly 500 CHP plants. The rest is generated from more than 65,000 mainly gas-fired boilers.

Last year, a new KA26 CCPP was completed in Moscow at the TPP-26 generating facility owned by OJSC Mosenergo. The new TPP-26 cogeneration unit is one of a number of new combined-cycle power plants to be built in Moscow. Mosenergo has 17 thermal power plants located in and around the municipality of Moscow, historically designed and developed to provide CHP for the harsh Russian winter conditions.

The new plant, known as unit 8, is designed to operate principally on natural gas, with oil as the back-up fuel. It increases the total installed power generating capacity of TPP-26 from 1400 MW to 1820 MW and is an important project in Russia’s drive to reduce domestic fuel gas consumption by modernizing its district heating plants.

The ability to achieve an electrical efficiency of 59% makes this the most advanced combined cycle plant in Russia. Meanwhile, the additional use of the waste steam to provide district heating brings the overall fuel utilization of the plant to more than 85%.

This high efficiency will reduce gas usage by about 30% compared to existing plants. Mosenergo estimates that, during the first year of operation, the transfer from old plants to the new plant will save 326 million m3 of natural gas. This translates into a double-digit million euro saving from the first year of operation.

The GT26 gas turbine and the steam turbine at this plant are arranged in a multi-shaft configuration. The steam turbine consists of one reheat type HP turbine section, an IP (intermediate pressure) turbine and one double-flow LP turbine.

The IP steam turbine is equipped with extractions to supply two steam/water heat exchangers for district heating. Steam for the first heater is drawn off from the IP exhaust. The second heater receives steam from the IP steam turbine at an intermediate stage.

The new Unit 8 is designed to accommodate daily load variations. It can also handle daily start-up and shutdown cycles. The facility is capable of operating over a very wide ambient temperature range of -42ºC to 35ºC.

There are two possible modes of operation. In full condensing mode, the plant produces power only. District heat extractions are closed and the load is controlled according to the grid requirement. In condensing-heating mode, the variable steam extractions are controlled to maintain the required district heating temperature, whereas the operator of the district heating system is controlling the flow of the district heating water. At the same time, the plant is continuously adjusting gas turbine operation to the required power demand.

In power production mode, TPP-26 Unit 8 now provides 420 MWe. In condensing-heating mode, it provides up to 265 MWth heat with fuel utilization above 85%

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The Grain CCP is very close to the Grain LNG terminal, to which it is designed to provide process heat from the cycle


Last year, a new KA26 combined cycle power plant (CCPP) with 876 MWe output was put in operation at the Emsland site, in Lower Saxony, the northwest of Germany. This plant will help RWE maintain a diverse and balanced primary energy mix and provide the increased flexibility required by the German power sector.

In this plant, with two GT26 gas turbines, each gas turbine and the common steam turbine drive its own, hydrogen cooled TOPGAS generator. Up to 100 t/hr of steam, equivalent to about 80 MWth, can be supplied from the cold-reheat line after the HP steam turbine to a nearby factory for acrylic fibre. For this factory, high reliably and availability of the steam supply is important, as the process is running on a 24/7 basis. The steam export contributes to the success of this CCPP project that is planned to run often in part-load to balance the electrical grid.

With the efficient fuel utilization, the new plant is consuming significantly less fuel than old units with corresponding output. The Emsland plant is capable of fast start and quick response to changing demand conditions, with high efficiency and low emissions even at part load. As well as featuring the latest rating of the GT26 gas turbine, it also includes innovations in the water/steam cycle.

The intermediate and low-pressure sections of the HRSGs are designed according to the principle of natural circulation vaporization. But for the first time in a European plant of this output class, the high-pressure section is a once-through cycle design without a drum but with a water separator. The choice of the once-through cycle principle and the absence of an HP drum subjected to high thermal loads means that higher live steam parameters can be used, leading to higher efficiency, and maintains flexibility for load gradients and short start-up/shutdown times even with the high pressure.

A particular attraction of the site is the excellent gas supply, with access to five gas networks, which allow gas to be supplied at short notice for fast response to power demand changes. The high fuel flexibility of the GT26 with large tolerance to natural gas variations is therefore an additional benefit for the Emsland project.


Alstom has also built a third, but much larger plant in the UK, which will enter full commercial operation in spring this year. At 1275 MWe, the new CHP plant at the Isle of Grain will be the largest of its type in operation in the UK.

The new Grain plant is one of three large gas-fired combined cycle plants Alstom has recently constructed as part of the UK’s effort to meet its short- to mid-term power needs in an environmentally acceptable way.

The southern part of the Isle of Grain in Kent has long been an important industrial area. The area’s heat and power needs have historically been served by an oil-fired power station built in the 1970s. The new gas-fired combined cycle CHP plant will eventually replace the old power station. One of the industrial facilities that will be served by the plant is National Grid’s liquefied natural gas (LNG) import facility.

Grain CCPP is very close to the Grain LNG terminal and has been designed to be able to provide process heat from the cycle to the LNG terminal. At present, National Grid’s Grain LNG terminal uses natural gas to heat the liquefied natural gas into a usable form. Using process heat from the CCPP will eliminate the need for this further gas burning, allowing for a reduction in carbon emissions.

The new plant has three combined cycle units, each comprising an Alstom GT26 gas turbine, a STFC30C reheat steam turbine connected on a single shaft to a hydrogen-cooled TOPGAS generator and a HRSG.

The HRSGs are triple-pressure drum boilers operating at a flue gas temperature of up to 640ºC. Additionally, the hot gas path components in the gas turbines, such as the blades and internal liner segments, are cooled with air. This process heat is used in the water steam cycle to recover an extra 20–30 MW electrical equivalent of heat.

The use of waste heat raises the new Grain plant’s overall fuel conversion efficiency. As a CHP plant, it will also generate carbon credits for its owner, E.ON. Instead of sending the waste heat back into the river, the plant heats a closed demineralized water circuit whereby the hot water is fed to the LNG terminal about 2 km away. The power plant is designed to supply about 270 MWth of heat by water at a temperature of 42ºC to the LNG terminal.

The LNG terminal uses the warm water to vaporize the liquefied gas so that it can be fed into the UK’s National Grid’s gas network. National Grid can therefore burn less gas to re-gasify the LNG. Such a system not only allows National Grid to be more efficient in its operations. It also means that, as a power producer, E.ON has a greener plant.

The new Grain power plant uses a split-shaft condenser that has been specially designed for the CHP and cooling arrangement used in this project. It is twice the size of a standard single-shaft condenser.

The condenser’s role is to transfer heat to the cooling water. The cooling water flows through the condenser tubes. The turbine exhaust steam condenses on the outside of the tubes and thereby transfers its heat to the cooling water.

The condenser is operated with either seawater only, or with demineralized water in a closed loop as a heat exchanger between the National Grid’s submerged combustion vaporizers (SCVs). LNG is a liquid at about -160ºC, which means that heat is needed to vaporize it. The SVCs are essentially a bath of hot water used as a heat source to increase the LNG volume by a factor of about 600, vaporizing it so it can be fed into the gas grid.


Alstom’s ecoHEAT concept for combined cycle power plants can certainly play a major role in situations where significant amounts of power and heat are required. It offers operators a plant that can provide the maximum flexibility in balancing heat and power demands. Beyond Europe and other colder regions, the heat can be used in desalination plants in markets like the Middle East. The three completely different CHP projects demonstrate Alstom’s capability to build tailor-made CCPPs that can even meet very specific heat requirements.

Christian Bohtz is Alstom’s product manager for Gas Power Plant Applications. Email: christian.bohtz@power.alstom.com

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