|The Støvring decentralised CHP plant
Credit: Danish Gas Technology Centre
Denmark has a long tradition of cogeneration. At the country’s centralised steam turbine-based plants (most of which were originally coal-fired), cogeneration has been used in connection with district heating grids wherever possible. During the early 1990s, numerous decentralised cogeneration plants were established. Most of these plants are natural gas-fired, based on either engines or turbines. Some 1000 gas engines and some 40 gas turbines are in operation for cogeneration, and most have been built in connection with existing or newly-established district heating systems. A limited number of plants are used for industrial cogeneration.
Decentralised plants were given government subsidies (guaranteed feed-in prices) during the1990s to accelerate the sector’s development. When power and gas markets were liberalised, this subsidy for established plants was changed to a non-production dependable subsidy until expiration. This was done to ensure that plant operation was according to market conditions.
Typical CHP plant
The typical decentralised plant, as constructed and laid out in the mid-1990s, consisted of two to four gas engines, generators, high- and low-temperature heat exchangers, and a number of peak-load boilers. Almost all plants had a short-term heat storage system consisting of insulated vertical steel tanks (see examples in Figure 1).
|Figure 1. Two medium-sized CHP plants including heat storage tanks Credit: Jan de Wit|
Most plants supplied their heat to a district heating grid, and most plants were planned for approximately 4500 full-load annual operating hours. This gave the most beneficial electricity prices, avoiding operation during the lowest tariff hours. The nominal heat output from the CHP production units represented some 60% of the heating power needed on Denmark’s coldest days at -12°C (design temperature). Assistance from the peak-load boilers was needed for heat supply during these cold conditions. However, such climatic conditions only occur for a few days a year, and on an annual basis the CHP units could supply some 90% of the heat needed. Plants were operated at full load during the hours when the best electricity price was offered, while surplus heat was stored in the heat storage system and used during nights and on weekends when electricity was in a low-tariff regime. A significant annual heat contribution from the CHP production units was, in fact, a necessity to achieve the favourable feed-in tariffs. In this way, society received CHP fuel savings at almost maximum, and plant owners benefitted from a cost-effective layout of the CHP production units.
|Figure 2. Denmark’s changing fuel mix: the change to fuels other than coal since the early 1990s
Source: Danish Energy Agency
In the late 1990s and early 2000s, many plants were upgraded – often in connection with major overhauls to achieve even better electrical efficiency. Gas engines underwent significant improvements in shaft efficiency during this period, from about 35% up to 47% for larger spark-ignited engines.
Extra heat exchangers for increased flue gas cooling were often also installed in order to reduce fuel consumption. First-generation plants typically had a flue gas stack temperature of approximately 120°C. Today, many plants are in the 50°C–60°C range, some even operating with flue gas condensation.
The pursuit of increased fuel utilisation has led to initiatives such as the cooling of CHP plants’ flue gas using absorption heat pumps. With this process, the flue gas fed to the stack is even colder than the return water to the plant. Until now, this return water temperature has often been seen as the coldest cooling medium available. Absorption heat pumps are often operated via a hot-side stream of the high-temperature exhaust, which is later fed back into the heat exchangers. The heat from this process can be used to preheat the district heating water (see Figure 3). A total of 15 absorption heat pumps are now installed and supply heat to district heating networks. Most are installed in connection with CHP plants and typically have a heating power ranging from 0.5 MW to 4 MW, typically increasing the heat production from the CHP unit by around 20%–25%.
|Figure 3. Extra cooling of flue gas by means of an absorption heat pump (example from the Bjerringbro CHP plant) Credit: Bjerringbro CHP|
‘Prosumer’ CHP plants
Since the liberalisation of Denmark’s power market, electricity prices fluctuate widely. Hours with extremely high prices, as well as hours with low and even negative prices have been seen!
Most gas-engine CHP plants offer uploading when not in operation, and downloading when in operation, for the electricity/power market. However, even more power balancing is sometimes needed. A number of plants have been equipped with electrical heaters, meaning that a 10 MWe CHP plant in operation can in fact offer 15 MWe downloading, if it is equipped with a 5 MWe electrical boiler. The plant can act as both producer and consumer, hence the phrase ‘prosumer’. If there is no need for the heat in a particular situation, the heat storage facility is used for storing the surplus heat.
In the smallest commercial-sector installations, such electrical heaters could be a low-voltage heater, e.g., installed in hot-water storage tanks. For larger installations such as decentralised CHP plants, both low-voltage (0.4 kV) and high-voltage (mostly 10 kV) installations are used. An example of a high-voltage installation is shown in Figure 4.
|Figure 4. High-voltage electrical boiler for installation at a CHP plant Credit: as-scan|
These low-voltage boilers are based on heat production via electrical resistance through circuit coils, while the high-voltage boilers use electrodes and salts in the boiler water to achieve an electrical circuit and heating. Load control is achieved by raising and lowering shields around the electrodes. To avoid or minimise hard boiling, cavitation and mechanical corrosion around the electrodes, a sufficient water flow must be maintained. As mentioned, the boiler water is salted – in contrast to the water of the prime mover cooling circuits, district heating network and heat storage tank. A heat exchanger is therefore needed for transporting the heat produced in the electrical boiler to the other heat circuits.
Such a boiler has a startup time. If it is in the market for sudden electrical load, it must be kept at ‘idle’, typically 2%–5% load.
A total of 45 electrical boilers with a total nominal power of 400 MWe have been installed in connection with various types of CHP plants.
Another way to use electricity when prices are low is to use larger electrical heat pumps. Return water or water from the lower region of the heating storage tank (30°C–35°C) can be partly (or fully) heated at a low production cost. However, investments in these units are relatively large, so it is necessary to achieve quite a significant number of annual operating hours in order to receive a reasonable return on investment in the heat pump. In Denmark, some 15 larger electrical heat pumps are in operation, mostly in connection with CHP plants. Their heat output is typically in the range of 0.5 MW–3.5 MW.
The Bjerringbro decentralised CHP plant, established in 1993, is based on four large gas engines with a nominal electrical output of 12.8 MWe. To improve the plant’s competitiveness, a number of technical improvements have been made over the years.
In order to minimise district heating grid losses, a lot of effort has been put into optimising the water temperatures of the grid. Improved insulation also has a high priority, both in the district heating grid and at the CHP plants. Piping, valves, pumps and even the engines have been insulated to reduce heat losses.
An extra heat storage tank has been installed to optimise production planning for full-load production when the electricity price is optimal.
Supplementary equipment has been installed at the cogeneration units to improve fuel utilisation. One unit has been equipped with an additional flue gas cooler, while another has been equipped with an absorption heat pump which is driven by a side stream of hot flue gas from the gas engine (see Figure 5). Heat is taken from the flue gas going to the stack, lowering the flue gas temperature from 63°C to 27°C. This heat is used for preheating the return water from the district heating grid.
|Figure 5. Absorption heat pump,installed close to the engine cell Credit: Bjerringbro CHP|
At another CHP production unit, an electrical heat pump has been installed to cool the flue gas.
These initiatives have been launched to reduce heat losses and to improve the efficiency of the production units.
Even more initiatives have been introduced at the Bjerringbro CHP plant. For instance, a few years ago the owners entered into a partnership with the nearby, well-known Grundfos pump factory. During the heating season, heated cooling water from production cooling at Grundfos is taken to a joint Energy Centre, where it is cooled via an electrical heat pump. The heat from the cooling process is used to preheat the district heating water going to the Bjerringbro CHP plant. During the summer months, cold water used for production cooling at Grundfos is taken from an obsolete groundwater borehole and heated water is fed back. Later in the heating season, Bjerringbro can use this heated water via a heat pump for heating or preheating district heating water. The average temperature in the underground seasonal storage reservoir must be kept the same as before the seasonal storage was established.
The cooling machinery and heat pumps at the Energy Centre are ammonia-based and electrically driven. The nominal cooling possible is 2.8 MW, and the nominal heating is 3.6 MW.
The Energy Centre is a partnership between Grundfos and Bjerringbro CHP. Bjerringbro CHP station’s four technicians now have a large number of different production units to choose from depending on electricity prices, heat needs and the storage situation in the two heat storage tanks as well as in the seasonal storage reservoir.
Natural gas-fired boilers are also installed for peak and supplementary production. One of these boilers is equipped with a heat pump for increased heat production, leading to the lowest possible production costs.
|Figure 6. Bjerringbro CHP and Grundfos’ joint Energy Centre. It can be seen from the road with warm lighting during nights to make heat production ‘visible’ Credit: Bjerringbro CHP/Grundfos|
The Brædstrup plant was originally a typical natural-gas fired decentralised CHP plant with two gas engines, peak-load boilers and a short-term heat storage facility. A large solar heating system of around 8000 m2 was subsequently built to be the primary heat supply source during summer and in low-demand periods of the heating season. Because it is based on solar heating in the summer months, the CHP plant uses no fuel for its hot water needs, nor for standby losses in the heating grid.
The Brædstrup CHP plant now also operates an electrical boiler (high-voltage) of some 10 MWe.
Challenges facing the sector
The number of annual operating hours for decentralised CHP plants based on gas engines and gas turbines has decreased over the last five to 10 years. From around 4500 annual operating hours, many plants now only operate for 2500–3000 hours per year. This is due to generally low electricity prices and fierce competition from renewable sources with no energy tax on the fuel. District heating can be produced from such renewables at a lower price than from most CHP plants.
The current low prices of CO2 certificates under the EU Emissions Trading System (ETS) have benefitted coal-fired plants, as well as negatively impacting production opportunities for highly taxed fuels, such as natural gas.
Many decentralised gas engine-based plants offer services in the short-term balancing market. The plants have excellent load response characteristics, an important parameter when more and more fluctuating renewable energy such as wind and solar PV is to be integrated. However, even in this market prices are generally low. As a result, many plant owners are seriously considering phasing out and tearing down their gas engine- and gas turbine-based CHP production units, as the non-production-dependent subsidy will expire in 2018.
Denmark’s official government policy is increased implementation of renewable sources, many of them fluctuating. Decentralised CHP plants are obvious key players in this process, as they:
- Connect both power, gas and heating grids;
- Are mostly installed with short- and/or longer-term heat storage facilities;
- Have excellent load response characteristics;
- Are ready for (if not already in) operation on green gases (biogas, biomethane, etc);
- Fit well with other renewable sources, such as solar heating, heat pumps, etc.
Gas engine and, to some extent, gas turbine plants are in fact the ‘non-missing link’ for the smart grid operation of today and tomorrow. They have the characteristics needed for smart power production and power balancing in a regime with ever more renewable energy.