Credit: Bill Ebbesen/Wikipedia

A comparison of gas engines and turbines in combined heat and power generation for a typical public heat supply network shows economic advantages for engines, write Tobias Vogel, Gerd Oeljeklaus, Thomas Polklas, Christian Frekers and Klaus Görner

The transformation of energy systems currently underway in Germany is having an increasingly noticeable impact on the existing energy industry. Due to the long-term expansion targets of, e.g., 80% renewable energy being used in electricity generation by 2050, it can be assumed that demand from fossil power generation will change and that, especially, time flexibility will gain even more significance in order to shoulder the growing demand for balancing energy.

By 2050, 25% of the fossil-fuel share is expected to be covered by combined heat and power (CHP) plants. This emphasizes the significance of CHP within thermal power plant technology, although the absolute amount of electricity provided by thermal power plants, and therefore CHP, will decrease in the long term due to an increase in renewable energies.

Considering the current situation on the German electricity market, it seems interesting to compare CHP plants based on stationary gas engines with currently utilized systems. Due to their lower greenhouse gas emissions, gas-powered plants offer significant advantages.

The main differentiation to be made in CHP applications is between industrial and public heat supply. A typical example for the latter is municipal power utilities with district heating networks. Many municipal utilities are already using gas-powered CCPP plants as thermal power stations, which offer lower greenhouse gas emissions and higher efficiency levels compared to CHP plants powered by solid fuels. Modern and highly efficient CCPP plants, as shown by the example of Irsching 5, can currently not be operated profitably in Germany due to the low electricity prices and low prices for CO2 emissions. The CHP approach, with its privileges such as revenue from heat sales, CHP bonus and CHP electricity input priority, offers an opportunity to improve profitability, a notion which is also supported by planned construction projects for thermal power plants in Düsseldorf (Lausward Block Fortuna) and Cologne (Niehl 3).

Within the area of CHP applications, modern and highly efficient gas engines arranged in combined power plants can present an alternative to CCPP plants. As well as delivering highly efficient CHP capabilities, these engines can participate in the balancing energy market due to their high flexibility, a factor which can further increase profitability. Their modular construction with unit sizes of around 10 MWe allows operation that is tailored to requirements, and simultaneously offers high efficiency across the entire load range.

The following will describe a study based on the possibility of providing full coverage of all energy supply requirements with engine-based power plants as an alternative to an existing CCPP system. Apart from employing plants that operate purely with engines, it is also possible to equip the engines with a downstream located water/ steam cycle, with the goal of maximizing electricity yield whilst simultaneously fulfilling the CHP requirements.

The district heating network

For this study, the district heating network of a mid-sized city was chosen, representing a typical average district supply system in a moderate climatic area of Germany. At this location, the average annual temperature is +10.5°C, with the daily mean temperature varying between -6.7°C and +26.3°C.

For the district heating supply, a requirement profile representing the dependence of the necessary feed temperature as well as the required district heat load on the ambient temperature has to be established. Depending on the ambient temperature Tamb, the flow temperature varies continuously between +130°C (T< -10°C) and 80°C (T> +15°C), with the return temperature remaining constant at +60°C. The district heating load to be supplied varies continuously between 161 MWth (T= -15°C) and 12 MW (T= +30°C). The district heating demand for the reference year and the chosen location was determined to be 587.8 GWth/a.

Figure 1. Process flow diagram with main process parameters of the reference plant

The study’s baseline was represented by a modern CCPP system in a medium power range (approximately 100 MWe). The gas engine systems were compared on the basis of this reference plant.

The CCGT plant (reference plant)

For CCPP plants in the medium power segment that are operated as thermal power plants, typical configurations consist of two gas turbines plus a heat recovery steam generator (HRSG) with auxiliary firing and a downstream located back-pressure extraction turbine. An auxiliary boiler is usually installed to cover district heat peak loads.

A schematic of the reference plant is shown in Figure 1, along with key process parameters and output data for district heating supply temperatures of +130°C and +80°C. The hot gas turbine exhaust gas (ca 500°C) is further heated in the HRSG with auxiliary firing as required, and subsequently used for superheating, evaporation and preheating of the feed water in the water-steam cycle. A further part of the waste heat contained within the gas turbine exhaust gas is then used to provide district heating.

The HRSG-generated live steam then flows into a back-pressure extraction turbine. Here, the steam is expanded to low pressure level (LP), with partial steam extraction taking place at intermediate pressure level (IP). Extraction steam, as well as exhaust steam is used and thereby condensed in two heating condensers (HeaCo) to supply the district heating system. In order to cover the peak load, a district heating auxiliary heater is coupled downstream of the IP heating condenser on the district heating side.

The CCPP runs at full load for maximum district heating supply temperature. If the required district heating supply flow temperature drops, only the added thermal power from the auxiliary heating is initially reduced. This is then deactivated above approximately +107°C. A further load reduction is carried out by reducing the auxiliary firing in the gas turbine exhaust gas. The final load reduction can be achieved by shutting down one gas turbine, with a further load reduction avoided by operating the remaining gas turbine at part load. For this reason, partial heat removal from the provided district heat takes place via the re-cooler station during times of very low district heating demand.

Gas engine systems

The gas engine used for this study is the MAN Diesel & Turbo SE 20 V 35/44 G in the CHP version, as well as the GCC version (GCC = waste heat recovery using water-/steam cycle), both of which are optimized for the respective application. Both engine versions provide the same 10.6 MWe, but with slight differences in the electrical efficiencies of 45.5% (CHP) and 45.1% (GCC).

Independent of the engine version, waste heat accrues at a total of three temperature levels (exhaust gas, high temperature (HT) and low temperature (LT) cooling water), which are subsequently used further for energy efficiency purposes, for example for district heating or power production. For the CHP version, the waste heat is transferred directly to the district heating network using heat exchangers. At full engine load, this lies at a constant at 9.47 MWth per engine across the entire range of the district heating supply flow temperature (+130°C to +80°C). This configuration is described as the ‘Engine(CHP)’ system. In the GCC version, the engine’s exhaust gas has a temperature of 395°C at full load.

The use of such high temperatures for providing low-temperature heat is exergetically inefficient. Efficiency can be improved by coupling a water/steam cycle for electricity generation downstream of the engine exhaust path. Depending on the application, various layouts are possible. It must be noted whether the requirement is to provide the highest-possible electricity generation capacity (application: condensing turbine) or to provide low temperature heat with concurrent electricity production (application: back-pressure turbine). For the application considered here, the use of a back-pressure turbine similar to the CCPP reference plant seems promising, since the exhaust steam can also provide district heating.

Figure 2 shows the process flow diagram for such a module, consisting of a gas engine (GCC version) coupled with a downstream located water/steam cycle, composed of a single-stage HRSG, a back-pressure extraction turbine and two heating condensers. This will here be referred to as the ‘engine (GCC)+HeaCo’ system.

First, the engine exhaust gas is routed to a HRSG, consisting of superheater, evaporator with drum, and preheater. As a result of the heat transfer from the engine exhaust gas to the water/steam cycle, live steam at 380°C and approximately 20 bar is generated. The live steam is then expanded in a back-pressure extraction turbine, whereby the extraction serves the supply of the deareator (DEA) with bleed steam and ensures degassing. The majority of the steam, however, is still fully expanded to the level of possible back-pressure depending on the district heating supply flow temperature.

Figure 2. Process flow diagram with main process parameters of the engine (GCC)+heating condenser system
Figure 3. Annual profile of district heating demand within the supply area, as well as key performance data (district heating load, re-cooling power, net electrical power and thermal fuel power) of the CCGT plant in the reference year

The turbine exhaust steam condenses in the heating condenser, thereby transferring the heat released in the process into the district heating network. The condensed water is fed to the deareators by the condensate pump, from where it returns to the HRSG via the feed water pump.

In this process flow, the district heating supply is provided in two ways: by directly using the engine exhaust heat in the form of cooling water and residual engine exhaust heat, and indirectly via the heating condenser.

When the engine exhaust heat is used directly, the water returning from the district heating with a temperature of 60°C is routed to the heat exchanger LT-CW-DH-HE. Here, the water is heated for the first time by using the waste heat in the low-temperature cooling water. After this, it flows to the HT-CW-DH-HE, where the HT cooling water further heats the water (on the district heating side). A further temperature increase is provided by the residual heat in the engine exhaust gas.

Depending on the required temperature level of the district heating supply flow, different mass-flow overlays occur, which is why bypasses and additional (district heating return) feeds are provided. In the case of indirect provision, the water from the district heating return is routed back to the heating condenser and is heated up before being added to the water which has been directly heated. A gas-fired peak load boiler ensures that the maximum district heating supply flow temperature can be met.

For both concepts, Engine(CHP) and Engine (GCC)+HeaCo, a modular structure up to the level of a large combined power plant is possible. This means that the supply of district heating networks can be covered in a similar manner as with the CCPP concept.


As well as the investment, the economic efficiency of a CHP plant is determined by the revenue situation. In order to get the CHP bonus, it is necessary to target an annual fuel utilization factor of more than 80%. Figure 3 shows the annual profile line for the district heating demand within the supply area, as well as key performance data (district heating load, re-cooling power, net electrical power and fuel requirements) of the CCPP plant in the reference year.

The profile of the district heating demand in the reference year shows that the required district heating load lies between 142.7 MWth and 14 MWth. But demands of more than 120 MWth only occur on 14 days in the year. Furthermore, the district heating demand profile shows that even in the midsummer, there is still a baseload demand within the district heating network.

The selected layout of the CCPP plant allows sensible deployment of the district heating. It is evident that the peak demand is not covered completely by the CCPP plant. Therfore peak times are covered by the supporting auxiliary boiler. This increases the full load operation of the CCPP plant. At around 110 MWth the nominal district heating decoupling of the CCPP plant takes place, which is required for 87 days in the reference year. Up to this point, the auxiliary boiler is still in partial load operation and provides the residual district heating load, whereas at all other times it is shut down. If the ambient temperature increases, then the district heating supply demand drops. The supplied district heating load is reduced analogously by the power plant controls. With the selected plant design, the minimum district heating load which can be provided from the CCPP plant is reached above a temperature of +15°C.

Since the district heating demand reduces still further with the temperature increase, a re-cooling station needs to be utilized since more heat than required is decoupled from the CCPP plant. The electrical net power shows two plateaus in winter and summer, similar to the district heating supply, with around 101 MWe in the winter and 38.1 MWe in the summer. During the transitional period, the supplied electrical power drops continuously with increasing ambient temperature.

If the supply of a district heating network is provided using gas engines (Engine(CHP)) or gas engine combined power plants (Engine (GCC)+HeaCo) instead of the CCPP plant, the first requirement is to create a comparable base layout. As well as the technical plant configuration, the number of engines in a combined power plant provides a further degree of freedom.

The goal of the study was to create a technically comparable starting point and then to vary the number of the model Engines (CHP) in order to provide a similar district heating baseload in terms of output and duration as with the reference plant. Eleven engines were therefore selected for the combined engine power plant; this is applicable for both engine systems. Furthermore, it was assumed that the engines are continuously operated at baseload and shut down in a modular manner, i.e. stepwise, in order not to exceed the required district heating demand. The auxiliary boiler provides the residual district heating load in each case.

The district heating demand as well as the thermal power output provided from the CCPP plant follow the profile shown in Figure 3.

With the Engine(CHP) system, during coupled generation in winter, a thermal power output of 104.2 MWth is provided, whereby the residual heat load is secured by the auxiliary boiler. In the annual profile line this full load period extends to 94 days, which correlates well with the 87 days full load operation of the CCPP plant. If the ambient temperature increases to above +5.6°C, one of the 11 engines shuts down due to the reducing supply required for the district heating demand. This continues with increasing temperatures so that the typical stepped profile for modular concepts emerges. The resulting residual heat load between stepped profile and district heating load is covered in each case by the auxiliary boiler.

In contrast to the CCPP plant, and particularly at very low district heating loads, the modular construction of the engine combination power plant allows for better matching to the district heating demand so that at the minimum only one engine remains in operation. In addition to this stepped operating mode, it is of course also possible to provide a continuously variable combined operation of the engines. Here, with decreasing heat demand, one engine is operated at part load, for example, so that no operation of the auxiliary boiler is necessary.

The heat output provided by the Engine (GCC)+HeaCo model runs at altogether a lower power level than with the Engine(CHP). This is due to the fact that with the Engine (GCC)+HeaCo, part of the waste heat is converted into electricity and is therefore no longer available for heat supply. Due to the roughly constant heat output per engine, this is more noticeable at higher numbers of engines than at lower numbers. As a result of the lower heat output provided in the Engine (GCC)+HeaCo model, this enables a higher utilization period respective to the number of full load operating hours. The winter plateau with all engines in operation amounts to 118 days for the Engine (GCC)+HeaCo.

During the winter plateau, the net electrical power output is 116.6 MWe. The lowest maximum electrical net power output is provided by the CCPP plant, although there is also a small rise to the right (higher ambient temperature) due to the behaviour of the back-pressure turbine and heating condenser. The minimum power of the CCPP plant is substantially higher than that of the engines, which can be explained by the lower number of gas turbines. Overall, there is a power advantage for the Engine (GCC)+HeaCo system during the winter plateau, lying at 5.1% compared to the Engine (GCC)+HeaCo system and 20.7% compared to the CCPP plant.

All three systems provide the required heat load of 587.78 GWhth demanded by the district heating network, with the highest heat component being delivered in CHP by the CCPP plant with 97.9%, excluding re-cooling power. This high component is primarily due to auxiliary firing of the waste heat boiler, which was not used with the engine systems. The maximum CHP heat output of the engine models is always below that of the CCPP plant. During electricity production, it can be observed that the entire production comes from CHP. The greatest quantity of electricity is provided by the Engine (GCC)+HeaCo system at 666.24 GWhe, which represents an increased yield of 7.8% compared with the CCPP plant, and 12.6% compared with the Engine (CHP) system.

The picture for fuel consumption is very similar to that for electricity production. In this case, the highest demand also lies with Engine (GCC)+HeaCo, followed by the CCPP plant and then the Engine(CHP). The highest CHP fuel utilization factor is shown by the Engine (CHP) system with 86.16%, but with both engine systems comparing favourably with the CCPP plant. Furthermore, all three systems are above the evaluation benchmark of 80% stated in the CHP regulations for the CHP bonus.

The highest CHP coefficient is offered by the Engine (GCC)+HeaCo system, at 1.3, followed by the Engine(CHP) with 1.12 then the CCPP plant with 1.07. The Engine (GCC)+HeaCo system is especially interesting from the point of view of the CHP bonus, since it provides a favourable ratio of electrical energy to heat.

The Engine(CHP) has the highest primary energy saving with 24.15%, followed by the Engine (GCC)+HeaCo with 23.71% and the CCPP plant with 21.11%. Due to its higher electricity production, the Engine (GCC)+HeaCo system has the highest exergetic utilization factor of 51.78%. The CCPP plant has the lowest exergetic utilization factor with 49.77%.

Economic efficiency

All systems must also enable efficient economic operation. All plants are eligible under the CHP regulations. A positive revenue was shown for all three systems, with the highest amount shown with the Engine (GCC)+HeaCo under both scenarios (HPS and LPS).

For the Engine (GCC)+HeaCo system, in most cases only a part of the water/ steam cycle modules is coupled to the engines in operation. However, the investment amount would be equally high even if they were operated during the whole year. A higher utilization period of the coupled water/steam cycles can be achieved if not all of the engines are equipped with the waste heat capture. In this case, the engines with waste heat capture are used for district heating baseload, so that these engines and the downstream processes will have substantially higher full load hours. Ultimately, this results in a better relationship between additional revenue and additional investment.

Flexibility and balancing power

As well as ensuring the supply of a municipal power network, engine combined power plants can be used for grid support due to their high flexibility and modular construction, e.g. in order to supply residual load. Additional revenues can be generated from this, which substantially increase the economic efficiency of an engine combined power plant. Due to the good planning capability of the district heating load several days in advance, the number of modules of the combined power plant which would be available for residual load management can always be identified. The gas engine used for this study enables fast startup from standstill to full load within 180 s, which represents a load gradient of 3.5 MWe/min. Based on the installed power, this means 33% MWe, inst/min.

Modern CCPP plants currently offer higher load gradients of up to 16.6 MWe/min. Based on the installed power, however, this only equates to 3% MWe, inst/min. As a result, a combined engine power plant has a clear advantage in this respect. Furthermore, for engines there is no lifetime consumption related with starting cycles and they have even lower starting costs. For this reason, from the point of view of flexibility, gas engines are a suitable element in a future German energy supply system.

Tobias Vogel, Gerd Oeljeklaus and Klaus Görner are researchers at the University of Duisberg-Essen

Thomas Polklas and Christian Frekers are Development Engineers at MAN Diesel & Turbo SE

This article is available on-line. Please visit