HOT|COOL NO. 1/2017 - "System Integration"

CONVERSION TO RENEWABLE ENERGY MEANS INCREASED DEMAND FOR WELL-FUNCTIONING DISTRICT HEATING SYSTEMS In recent years we have seen an increasingly focused transition from fossil fuels to renewable energy in both the electricity and the district heating sector. In many countries, an increasing share of the electricity production is now based on the utilization of solar energy in the shape of solar cells and utilization of wind in the shape of large wind farms both off-shore and on land. Since there is often no correlation between the time of production of renewable electricity and the current consumption, there is a need to store the produced electricity. However, this remains a major challenge as the costs of storing electricity on a large scale are very high. If we are to succeed in the transition of our societies to more renewable energy, it is essential that we ensure well functioning district heating systems. Without such systems, we will not be able to utilize waste heat from companies on a large scale; we will not be able to store solar heat from summer to winter and we will not be able to integrate the electricity system and the district heating system in the shape of large electric heat pumps, which utilize cheap wind-based power generation.

N0. 1 / 2017



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By Lars Gullev, Managing Director VEKS and Chairman of DBDH THE COLUMN


In this issue of Hot Cool, we focus on "System Integration" in the broader sense.

In recent years we have seen an increasingly focused transition from fossil fuels to renewable energy in both the electricity and the district heating sector. In many countries, an increasing share of the electricity production is now based on the utilization of solar energy in the shape of solar cells and utilization of wind in the shape of large wind farms both off-shore and on land. Since there is often no correlation between the time of production of renewable electricity and the current consumption, there is a need to store the produced electricity. However, this remains a major challenge as the costs of storing electricity on a large scale are very high. Similarly, we also see in the district heating sector that renewable energy in the shape of biomass is gaining ground, just like the utilization of waste heat from the industry becomes increasingly important. In other district heating systems, electric heat pumps ensure that low value energy sources can be utilized in district heating systems. In many district heating systems, there are already today storage options in the form of heat accumulators, which are primarily used on a daily basis to ensure the balance between the district heating production and consumption. However, in recent years, we have seen more and more district heating systems where the heat storage capacity is much larger than to ensure balance on a daily basis. One example is the district heating system in Vojens, Denmark, where 70,000 m2 of solar collectors and a heat storage capacity of 200,000 m3 ensure that almost 50% of the annual heating consumption of Vojens District Heating Company’s customers can be met by renewable energy in the form of solar energy. Thus, we can see that already today the integration of not only the electricity and district heating systems, but also of the production of goods with utilization of waste heat, is taking place.

• In the article "The future of district heating and cooling networks - Intelligent controllers based on machine learning algorithms", we learn how waste heat from flooded mine shafts is used as energy storage for DHC networks. • "New roles of CHPs in the transition to a renewable energy system" - puts focus on the challenges that CHP plants will have in energy systems, in which a large part of the electricity production comes from wind power. • "The smart energy system integrates fluctuating renewable energy" focuses on how the district heating system can be utilized as storage for cheap electricity. • "System integration - Coordination on all levels" puts focus on the need to think across regional boundaries, municipal boundaries and borders between utilities, if we are to ensure an optimal system integration. • "A fairy tale of 100% efficient use of resources - the lifecycle of a citrus fruit from South America to Denmark" emphasizes the fact that a well-functioning district heating networks is a prerequisite for an effective resource utilization. If we are to succeed in the transition of our societies to more renewable energy, it is essential that we ensure well-functioning district heating systems. Without such systems, we will not be able to utilize waste heat from companies on a large scale; we will not be able to store solar heat from summer to winter and we will not be able to integrate the electricity system and the district heating system in the shape of large electric heat pumps, which utilize cheap wind-based power generation. I hope that these articles can be an inspiration to ensure an efficient use of our resources, with well-functioning district heating systems as part of the backbone of future energy systems – PLEASE ENJOY READING.


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By Paul Voss, Managing Director, Euroheat and Power

its application in practice would be to simply increase prices and decrease system reliability, neither of which is particularly compatible with the EU’s ambitions in this field. The inclination of policy-makers to apply a model which they feel has worked in the case of the gas and electricity markets is understandable in principle, but this kind of impulse needs to be tempered by an understanding of the practical realities and highly specific nature of DHC networks. Cutting and pasting models from other sectors simply won’t work. Other areas of potential concern include the proposal to revise downward the factor used to determine the relative efficiency of electricity generation, continued uncertainty regarding the distinction between the notions of ‘customer’ and ‘final user’ with respect to metering and billing obligations for DHC providers, and insufficient clarity as to the placing of waste heat and cold on an equal footing with their renewable counterparts. And we’re only just getting started! What happens next? The publication of these proposals marks the beginning of a new phase for EHP and for the European district energy sector. Taken together, the numerous provisions on heating and cooling networks can be understood as an offer from the European Commission to our industry. They are effectively proposing to encourage our growth and development in exchange for assurances about our ability to deliver the best version of DHC; one that is green, affordable and consumer-friendly. To use a term from the Brexit debate, to refuse this offer would be an astonishing act of self-harm. Equally though, it is our right and obligation to negotiate the terms. It is important to distinguish between Commission proposals (what we have now) and final legislation (what we’ll have in a couple of years when the EU decision-making process has run its course). Working with legislators during this process to establish proportionate regulatory safeguards without compromising the commercial or technical viability of DHC networks around Europe will be the defining challenge of 2017 (and 2018 in all likelihood!) for EHP. With this inmind, EHP, together with ourmembers, will work closely alongside the European Council and Parliament throughout the process of transforming these draft proposals into finished pieces of legislation. It is our job to make sure that the Clean Energy for All Package is remembered not as an avalanche, a tsunami or a Death Star but as a catalyst for the further development of DHC as a solution to Europe’s environmental, strategic and economic challenges. It will be a busy, challenging and exciting time but we will approach this work with confidence and from a position of increasing strength. We’re looking forward to the journey and are quietly optimistic about the final destination!

Though it’s only been two months, it feels as though a lifetime has passed since the European Commission published its ‘Clean Energy for all Packages’. In the weeks leading up to the release of the package, it was compared to many different things, none of them particularly flattering. Whether it was a ‘tsunami’ an ‘avalanche’ or, my personal favourite, ‘the Death Star’, the one thing nearly everyone in Brussels seemed to agree on was that it would be big and potentially dangerous. Now that the dust has settled, we can confirm that the package is indeed BIG! Comprising more or less 4500 pages of legislative proposals, impact assessments and technical annexes, this isn’t something you’re going to want to bring to the beach! Whether or not it’s ‘dangerous’ is a rather more complex question. As we at Euroheat and Power (EHP) go through the process of working our way through the package’s many constituent documents, the picture we see emerging is predictably mixed, with opportunities and challenges for DHC blended together in equal measure. The good news is we will have many opportunities to improve the balance and sweeten the final results over the next two years. Personally, I see plenty of reasons for optimism. What we like! While there are literally thousands of details to consider, some key points of interest are already quite apparent. First and foremost, the package provides definitive proof that the heating sector in general and DHC in particular are no longer stuck in the margins of the EU policy debate. Heating and cooling networks are very much in the spotlight. There is more and more recognition of DHC’s potential to contribute to key European goals such as cutting GHG emissions, enhancing supply security and facilitating the increased update of renewables into the energy system. Similarly, the proposal to establish a home for DHC in the future Renewable Energy Directive is a clear and highly visible political signal that our technology is now understood as a driver of the energy transition rather than an alternative. We recognise in the proposals significant efforts on the part of the Commission to address EHP’s most pressing policy concerns, notably the explicit promotion of waste heat and cold and the fair treatment of ‘nearby’ energy supply (i.e. via DHC networks) relative to its on-site (building level) equivalent. Collectively, all of these positive signs tell us that the advocacy work we’ve taken as an industry in recent years has been worth the effort. They tell us that our voice can be heard and that the views of our industry count for something. What we like a little less… While the increased awareness of DHC is of course welcome, some of the proposals on the table will likely need to be refined if they are to deliver their stated objectives. An important example is the provision calling for opening of thermal networks to 3rd parties wishing to sell heat directly to customers. Although this is an interesting concept in principle, the likely effect of

For further information please contact:

Euroheat and Power Att.: Paul Voss



By Brian Vad Mathiesen, Professor, Aalborg University

Magnus Dahl from AffaldVarme Aarhus and Aarhus University won for research proving that heat demand forecasting based on weather can help in high-risk situations where production and system operators have to be careful in their decision-making. His research also points into the future, as demand forecasting using weather patterns is able to lower supply temperatures at substation level and create better forecasting for purchase of electricity for electric boilers or heat pumps or heat from combined heat and power plants. I.e. it is possible to maintain a high security of supply while making the system more cost- effective by using more exact knowledge about short-term changes.

At the 2nd International Conference on Smart Energy Systems and 4th Generation District Heating we gathered in a venue that is an old power plant. Here at Nordkraft, both oil and coal have been the source of electricity and heating for year on end. While the plant is now closed, it has meant district heating has been spread throughout the city of Aalborg. Here, as in most other places in European cities, the challenge in decarbonizing the heating sector is in focus.

In the 4DH Research Centre (, we found large potentials for energy savings to go hand in hand with new heat source from industrial waste heat, heat pumps and renewable energy. The potential role of district heating is uniquely large on a global scale, illustrated by speakers from e.g. UNEP, Japan and Korea. At the conference, we had a unique gathering of both researchers and industry within smart energy and district heating with almost 200 participants and more than 100 speakers. The purpose of the conference is to build capacity and new knowledge for the transformation of our heating systems towards renewable energy. At the conference, awards are given from Kamstrup and Danfoss together with a prize of EUR 1000 to a PhD fellow and a senior researcher or industrial expert. The candidates are carefully chosen by the award committee, and the committee then selects the winners among many excellent candidates. This year, I am proud to present and congratulate the two winners, who both in their own fields have created and communicated innovative results for the heating and energy efficiency community. Martin Crane from Carbon Alternatives in the UK won for a unique approach in the UK context to test district heating performance and promote lowering temperatures to reduce costs. As an example, variations in local conditions meant that the typical UK specifications should change for substations. The results are that almost all manufacturers that were involved have made modifications to their substations. Also the research resulted in new testing procedures to be adopted by the British Building Engineering Services Association.

The winners, as well as all the other speakers at our conference, demonstrated that smart energy systems and district heating researchers, as well as industry, are innovative and creative in striving for lower costs, energy savings and using waste heat and renewables. On 12-13 September 2017, the 3rd International Conference on Smart Energy Systems and 4th Generation District Heating will take place at The National Museum of Denmark in Copenhagen. The Call for Abstracts is out now and I hope to see many of you there.

Brian Vad Mathiesen For further information please contact:

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By Magnus Dahl, industrial PhD fellow at AffaldVarme Aarhus and Aarhus University

I have applied this technique from meteorology to heat demand forecasting. I have obtained an ensemble forecast of the weather in Aarhus: 25 slightly different weather forecasts. This is a standard product sold by the Danish Meteorological Institute DMI as well as many other weather services around the world. The 25 forecasts are then fed through a model for predicting the heat demand based on the weather. The result is 25 slightly different heat demand forecasts that diverge and converge according to how uncertain we are on the weather forecast. Figure 1 illustrates this. Each grey curve represents the heat demand forecast in a different possible weather situation. The blue curve is the best prediction of the heat demand, based on the average weather forecast. With the ensemble heat demand forecasting tool in hand, we can begin to distinguish situations in which we are very certain of the heat demand and situations where our predictions could be far off.

It is possible to ensure security of supply while reducing economic risk. District heating production planners who are aware of the changing uncertainty in their forecasts make better decisions. In the following, I present a way to assess weather- related risks based on methods from weather forecasting. Any district heating production planner or system operator knows that heat demand forecasts are far from perfect. This is especially true for forecasts that reach more than a few hours into the future. When trading on the day-ahead electricity markets, production planners need forecasts for the following day. Forecasts on this time horizon often differ significantly from the realized heat demand. Therefore, creating realistic production plans and executing them is always a challenge. Both researchers and private companies are making efforts to improve heat demand forecasts. However, there is a limit as to how accurately it is possible to predict the heating demand of a city a few days into the future. This is why we at AffaldVarme Aarhus work actively with researchers from Aarhus University. Together, we assess the level of uncertainty that we are facing in the production planning and daily operation of the Aarhus district heating system. Since our knowledge of the future is never completely certain, we continuously estimate how uncertain our predictions are. When we are very certain of our predictions, it allows us to put more at stake in the decisions we make. When we are very uncertain, we need to exercise caution. Better knowledge of the operational risk we are facing leads to better decision making. Using more weather data The weather is hard to predict, and as a consequence tomorrow’s heat demand is hard to predict. Errors in weather forecast can carry over and produce erroneous heat demand forecasts. Therefore, I have developed a way to estimate the weather-based uncertainty in a heat demand forecast. I use a technique, adopted from weather forecasting, called ensemble forecasting. Meteorological institutions have used ensemble forecasting to estimate the uncertainty of weather forecasts since the early 1990s. The concept of ensemble forecasting is quite simple. Instead of creating a single weather forecast, meteorologists generate many slightly different forecasts. They generate these forecasts in such a way that their spread reflects the level of uncertainty. This means that when the forecasts are all very similar, we can be very sure of the predicted weather. Conversely, if the forecasts are far apart we are uncertain of the weather.

Proof of concept – lowering supply temperatures In a first proof of concept application, I have demonstrated how ensemble heat demand forecasting can be used to control the supply temperature from an area substation (figure 2). Ensemble heat demand forecasting makes it possible to adjust the temperature in a smart way depending on the weather- based uncertainty of the forecast. When the heat demand forecast is very uncertain, we regulate the temperature more conservatively. When our confidence in the forecast is high, we can lower the supply temperature without gambling with the security of supply. Reducing supply temperatures in a district Figure 1: Heat demand forecast predicting the total heat production in Aarhus. The spread of the 25 forecasts (in grey) indicates how certain the forecast is. In high-risk situations, production planners and system operators have to be careful in their decision-making. In low-risk situations, it is possible to maintain security of supply while making more economically favorable decisions.



heating network means reducing the amount of heat that is lost to the ground. Heat losses up to 20% of the total produced heat are common in district heating networks, and there is a substantial economic and environmental potential in reducing heat losses. With computer simulations, I have demonstrated that it is possible to achieve small supply temperature reductions at several area substations in the Aarhus area. I have also found that the benefit of using ensemble forecasting greatly increases in area substations that are often operating close to their maximum pumping capacity. Value Creation – the production planner’s dilemma Counting cards in blackjack gives the player an edge, because it is a way of estimating his risk profile and use it to make better decisions. In the same way, knowing your risk profile and the probability of various scenarios can help you make smarter decisions in the production planning and operation of a district heating system. Imagine the following situation a production planner may face: The heat demand forecast shows that she can cover tomorrow’s heat demand using only the cheaper CHP production units – but just barely. If the forecast is too low, it will be necessary to turn on an electric boiler to cover the peak of the demand. Here comes the production planner’s dilemma. Should she play it safe and buy electricity for the boiler on the day-ahead market? This cause of action is the cheapest if the forecast turns out to be too low. Alternatively, she could choose to trust the forecast and not buy electricity for the boiler on the day-ahead market. This is the cheapest if the forecast holds, but if it turns out to be wrong, then she might need to buy electricity on the intra-day market, potentially at a much higher price. In situations like this, knowledge of how much the forecast can be trusted is highly valuable. If the production planner had been equipped with an ensemble forecast that showed very little spread, she could have chosen not to buy the day ahead without running an unnecessary risk. On the other hand, if the ensemble forecast had indicated a highly uncertain forecast, she would know to play it safe.

Figure 3: PhD fellow Magnus Dahl (on the left) from AffaldVarme Aarhus and Assistant Professor Gorm B. Andresen (on the right) in the control room of AffaldVarme Aarhus. Photo: Lars Kruse, Aarhus University.

This may sound complex, but the technique of ensemble forecasting is simple and any district heating provider can use it to gauge their weather-based risk profile. A district heating provider that wishes to begin doing ensemble forecasting will need to upgrade their weather forecast subscription to include ensemble weather forecasts. Once a data feed with an ensemble weather forecast is in place, it is easy to pass it through any weather-based model for heat load prediction to create an ensemble heat load forecast. The technique is simple, the data is available and the potential value creation is significant for modern green district heating systems. A SMART CITY SHOWCASE: In READY we demonstrate new smart city energy infrastructure and low-energy building renovations in Aarhus, Denmark and Växjö, Sweden. Both cities host some of the worlds most advanced large-scale district heating systems.

The project is funded by EU under the FP7 framework under grant agreement no 609127

Thanks to the 4DH Research Centre

Figure 2: Large district heating systems often consist of a transmission system and a distribution system. The transmission system is the production side and the distribution system is the consumer side. The transmission system and the distribution system are connected at a number of area substations with heat exchangers. Knowledge of the forecast uncertainty can be used to control the supply temperature in a smart way and reduce heat losses to the ground.

For further information please contact:

AffaldVarme Aarhus Att.: Magnus Dahl Bautavej 1 DK- 8210 Aarhus V

Phone: +45 4185 8669

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By Martin Crane, owner and managing director, Carbon Alternatives

Substation performance: As per F103-7, the test explores the performance for DHW, space heat and standby separately. DH design consultants’ specifications rarely mention substation performance during standby; the UK HIU Testing Procedure now highlights this key area that many UK designers were unaware of. Some of the tests are done at typical DHW and space heat hot water demands, which test the substation under conditions that reflect real world operation. These typical demands were assessed from a large set of customer heat meter records. Unlike the Swedish test which is pass or fail, the UK HIU Testing Procedure takes measurements from which a volume weighted annual return temperature (VWART) can be calculated for the substation. This calculation reflects the substation performance during supply of typical space heating and DHW loads and while on standby (at all other times). VWART was chosen as the performance metric as return temperature is the dominant factor affecting the efficiency of DH systems, and also as this concept is relatively easy to understand. Assessing impacts of other DH variables: This element of the UK HIU Testing Procedure demonstrates the impact on the DH return temperatures of variables such as DHW temperature and the temperature of the space heating system flow and return. From the results produced by the Testing Procedure, designers should improve their understanding of the impacts of modifying variables such as primary and secondary flow temperatures. Highlight impacts of poor commissioning: In the UK it is rare to see requirements for pre-settable (flow controlled) valves on radiators supplied from DH networks. Many UK designers have little exposure to operating schemes and they design in the belief that if the radiators are sized for 70/40°C operation, that is what they will work at. Of course there are few complaints when the radiators actually work at, say, 70/62°C as the radiator pushes out lots of heat and the residents are happy. The householder is unaware of how high return temperatures increase the cost of DH.

From a low base of only a few percent of households being on district heating (DH), the UK is now developing more DH. In some areas, such as London, it is a requirement for new developments, but at times this can result in the DH being just another box to tick as part of getting permission to build. At these new built housing developments, it has taken some time to realise the importance of the long term operating costs of the DH. DH has often been poorly implemented, the designer’s focus is meeting a theoretical peak demand and the building contractors feel that if domestic hot water (DHW) flows and the radiators are hot, their job is done. There has been insufficient attention throughout the process to deliver lowest lifecycle cost in operation. Also, consideration of the environmental performance tends to stop once the high level design choices are made. The UK Government made available some research funding to improve DH systems. Using this funding, I developed a testing procedure for individual house / apartment substations with indirect connection for the space heat. This is known as the UK HIU Testing Procedure, and comprises a series of tests which are conducted in a testing facility. In the UK, individual apartment substations are called hydraulic (or heat) interface units, abbreviated to HIUs. The Swedish District Heating Association test standard F103- 7 was used as a starting point for the UK test. The substation configuration and capacity was chosen to best represent those currently being installed in the UK. The research project included testing 5 substations to gather data on their performance. The UK HIU Testing Procedure is much broader than just the performance of the plate heat exchangers at peak loads, which is the usual performance information a substation supplier will provide. The Test Procedure: 1) determines the performance of individual substations for heat loads seen in operation, 2) demonstrates the impact of other DH design variables on substation performance and, 3) highlights issues arising from poor commissioning.



The Test Procedure includes a test which is conducted with radiators without flow control to clearly demonstrate the impacts. This also demonstrates the importance of correct commissioning of the substation and the secondary heating systems. In the author’s experience, surveying of operating UK DH networks show, time and again, that better commissioning will lead to more efficient DH operation. When the system performance is poor, the tendency is to blame the installed equipment, but experience shows that the design or the commissioning are more frequently the source of problems. In the UK, design calculations and drawings only state return temperatures for peak load, and nothing is defined for other operating conditions. It is therefore difficult during commissioning to challenge high return temperatures from the system under all but peak loads. The VWART measurement indicates what the primary return temperature should be in operation; which gives a benchmark against which high return temperatures can be questioned. With the VWART representing real operation, the ambition is that maximum acceptable return temperatures at full and no load can be written into a specification and then demonstrated at commissioning.

The main substation suppliers in the UK were asked if they would like to offer a substation for testing free of charge. Five suppliers accepted and had one of their substations tested. The results show the range of performance of the different substations. Figure 1 shows the VWART for each of the substations’ functions. Figure 2 presents the calculated annual primary flow volumes. The three main observations are: 1) The variation in results – and yet they would all comply with a typical UK specification for a substation. 2) The high primary return temperatures during space heating – this is due to poor heat exchanger performance resulting from the heat exchangers being too large for the small heat loads used in the test. 3) The significance of standby operation and variation in standby performance between substations. The UK HIU Testing Procedure has promoted awareness of a range of DH performance issues and led to improvements in specifications and products. All the manufacturers attended the tests and all but one have made modifications to their substations as a result. The research funding has now ended and the UK HIU Testing Procedure has recently been adopted by the Building Engineering Services Association. A steering committee has been established which includes the representatives from the larger DH utilities. The steering committee seeks to ensure that the UK HIU Testing Procedure is maintained and developed such that it can help to deliver safe, efficient and cost effective substations that benefit operators and customers. One of the first steering committee tasks has been to develop Version 2 of the UK HIU Testing Procedure. Version 2 includes an option to test at typical underfloor heating temperatures and some of the pure research tests have been removed to keep the costs of the test down. There are a number of manufacturers planning to test their substations as soon as Version 2 is launched.

Results of research testing

The UK HIU Testing Procedure and results can be found at

Figure 1. Components of VWART and overall VWART

Thanks to the 4DH Research Centre

Carbon Alternatives Att.: Martin Crane For further information please contact:

Figure 2. Annual component primary DH flow volumes for an individual substations

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By Anders N. Andersen, Head of Energy Systems Department, EMD International A/S Poul Alberg Østergaard, Professor in Energy Planning, Aalborg University

The changing role is important to keep in mind when designing DHCP plants – while at the same time keeping in mind that the ongoing electrification of society requires that heating and cooling production at DHCP stations primarily will be served by electrical heat pumps using e.g. surplus, low-grade heat from industry, sewage systems or seawater. In Denmark, 16 central power plants providing district heating to big cities, 285 distributed CHPs providing heat for towns and villages and 380 industrial and private CHP plants proving heat for private and public DH grids have played an important role in providing an efficient energy system. The installed electrical capacity at the central power plants is 5,693 MW, 1,887 MW at the distributed CHP-plants and 574 MW at industrial and private CHP plants – however, they are currently threatened by decreasing spot market prices. This article argues that distributed DHCP CHP - representing 23 % of the total electrical capacity in Denmark - is quickly moving to the capacity-providing phase – perhaps even too quickly! As shown in figure 1, the electricity production at the distributed DHCP CHPs has been decreasing rapidly in recent years as a natural consequence of wind power developments. Wind power has come to cover a major part of the electricity demand, leaving less electricity to be produced by CHP. Until 2005 the Danish DHCP CHPs was paid under a fixed tariff system thus producing independent of wind production, but from year 2000 the wind turbines started to be curtailed from time to time - amplified by the situation that DHCP CHPs continued to produce because they were operating under the fixed tariff system. This also indicates the point in time where the energy system role of CHP changed from being a provider of electricity produced efficiently in cogeneration mode to being a provider of flexibility. As a consequence of the changed role, from 2005 to 2015, the fixed tariff system was phased out for progressively smaller DHCP CHP sizes, turning these over to be market-operated and most of these being traded on the Scandinavian day-ahead market.

District Heating and Cooling Plants (DHCP) will have both the opportunity to provide efficiency and flexibility through e.g. CHP, heat storages and heat pumps – while at the same time providing capacity when required. Fortunately, through investment decisions made a long time ago, Danish DHCP plants are already partially equipped for this role but to take on the role as capacity provider of the future, further incentives have to be established. Combined heat and power (CHP) units at DHCP have an important, but changing, role to play in the transition to a renewable energy system. Their initial role is merely to displace fossil fuelled condensing mode power generation, however, the development in Denmark shows that this role changed to providing flexibility for accommodating fluctuating renewable energy sources instead. Also, in the future, the role will be to provide electrical capacity during the hours where fluctuating renewable energy sources are unavailable. In the first phase, the aim is simply to cover the heat demand to the highest extent possible by DHCP CHP plants thus providing electricity where all coproduced heat is utilised. Generally, for each MWh of power thus replaced on a condensing mode power station by DHCP CHP, the same quantity of fuel is saved, often called the CHP benefit. With an increasing penetration of fluctuating renewable energy sources – mainly wind, solar, and wave power – it becomes increasingly important that the DHCP CHPs act with more flexibility and assist in the integration of these. One of the consequences is a decrease in the power generation from DHCP CHP in the next phase. As the energy systems progress towards fully renewable energy systems, based on fluctuating renewable energy sources, very little production is left on DHCP CHP and they have only to produce electricity in the relative few hours where fluctuating renewables are insufficient. At this stage, it is questionable whether there is any surviving condensing mode capacity, however multi-purpose DHCP CHPs may still present a business case, amongst others providing needed electrical capacity.



Figure 2: Aggregated electricity productions and consumptions in West Denmark together with day-ahead prices (Spot price) 6th December 2016. These productions and market data are shown online at

Figure 1: Annual electricity productions at distributed DHCP CHP in Denmark

An example of the flexible operations of Danish DHCP CHPs is shown in figure 2 and figure 3, showing respectively the aggregated electricity productions and consumptions in West Denmark together with day-ahead prices (Spot price) for the 6th December and 27th December 2016. The day-ahead prices rose at 7 o´clock on 6th December 2016 to the double compared to the prices in the night hours, which caused the DHCP CHPs (shown as local CHP units in the figures) to go from an electricity production of a little more than 300 MW to an electricity production of nearly three times bigger. Figure 3 shows a more extreme situation, where spot prices became negative until 7 o´clock on 27th December 2016 and the DHCP CHP production fell to approximately 100 MW. Comparing the two days (figure 2 and 3) shows a changed production from 100 MW to 900 MW, a flexibility in production of a factor 9. An important question could be why the DHCP CHP production was not reduced down to 0 MW when the day-ahead prices were negative – or another way to ask, which DHCP CHP is willing to pay around 400 DKK/MWh for being allowed to enter electricity into the grid. The simple answer is that it is the Danish Transmission System Operator (TSO) that is willing to pay so. These remaining 100 MW are mainly biogas CHP- plants, to which the TSO pays a feed-in tariff (FIT) independent of the hour in the day. The TSO is balancing responsible party (BRP) for these FIT-productions and sells the electricity from these plants as price independent production in the day-ahead market. In figure 3 it is further seen that a part of the wind production was curtailed until 7 o´clock. The wind production is as well offered in the day-ahead market, and some of the wind turbines use a bidding price around 0 protecting them from having to pay for producing electricity in certain hours. In fact, it is seen in figure 3 that the economic curtailments changed both at 6 o´clock and 7 o´clock, showing that wind turbine uses different bidding prices. Why, then, did not all wind turbines stop in these hours? The reason is probably that some of the wind turbines are old wind turbines that are not able to be operated/stopped remotely.

Figure 3: Aggregated electricity productions and consumptions in West Denmark together with day-ahead prices (Spot price) 27th December 2016. These productions and market data are shown online at

Wind power and PV with bidding prices around 0 lower the price in the day-ahead market, with negative consequences for CHP. Yearly average day-ahead prices in West Denmark 2011-2016 are shown in figure 4. By 2025, it is estimated that wind power and PV in Germany and Scandinavia will cover one quarter of the production there and thus depress power prices significantly with important consequences for DH and CHP. This side-effect of wind power development causes the Danish TSO to assess that 90 PJ of heat from CHP plants will be decimated to 5 PJ in 2050 when having 100% renewable energy.

Figure 4: Annual average day-ahead prices in West Denmark 2011-2016

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One of the advantages of the triple tariff system was the financial certainty and incentives it established, causing CHP plants that were decided by and operated by non-specialists to be given a design that was also appropriate for flexibility provision. Also, rather than reflecting the short-term marginal costs of the electricity market, price levels in the triple tariff reflected the long-term marginal value of CHP production. Owners of CHP plants are, however, not sufficiently financially robust to sustain the transition to providing capacity only. A Danish capacity payment scheme expires in 2018, beyond which point in time their economic feasibility is stressed. While CHPs may have a diminishing role to play in the future, DHCP DH still allows various heat sources to be exploited, and in effect, switching DHCPs to being electricity consumers. Being electricity consumers through e.g. heat pumps is a logical consequence of market price levels. What is infeasible for a producer will be beneficial for a consumer. However, as stated in the beginning, optimally, DHCP plants will have both the opportunity to provide efficiency and flexibility through e.g. CHP, heat storages and heat pumps – while at the same time providing capacity when required. Fortunately, through investment decisions made a long time ago, Danish DHCP plants are already partially equipped for this role but to take on the role as capacity provider of the future, further incentives have to be established.

For DHCP CHP to participate in the integration of fluctuating renewable energy, the plants need large electrical capacity and large thermal stores. In a normal situation, wind production is only curtailed in hours with low spot prices and DHCP CHP only produces in hours with high spot prices, which thus makes sure that DHCP CHP do not create unnecessary curtailment of wind. The large capacity and large thermal stores allow DHCP CHPs in the hours with high spot prices to produce excess heat being stored in the thermal stores, this heat being delivered from the thermal stores in hours with low spot prices where the DHCP CHPs are not producing. The effect of this is illustrated in Figure 5.

Figure 5: Simulated operation against the Scandinavian day-ahead market in one week in the autumn of 2015 of a CHP-plant equipped with large electrical capacity and large thermal store. The simulation is made in the energy systems analysis tool energyPRO.

For further information please contact:

EMD International A/S Att.: Anders N. Andersen Niels Jernes Vej 10 9220 Aalborg Ø Denmark

The fixed tariff initially applied for CHPs in Denmark was a triple-tariff with incentives for producing in certain periods of the day and week based on experience. This tariff made it attractive to equip CHPs with large electrical capacity and large thermal stores and in effect also prepared them for the role of providing flexibility. In general, all Danish DHCP CHPs are thus equipped with large thermal stores. As examples, Ringkøbing District Heating delivers app. 110,000 MWh heat to the district heating network and is equipped with a thermal store of 4,500 m3, Hvide Sande District Heating delivers app. 41,100 MWh heat to the district heating network and is equipped with a thermal store of 2,000 m3, and finally Sæby District Heating delivers app. 77,500 MWh heat to the district heating network and is equipped with a thermal store of 2,700 m3. The online operation of these plants are shown at system-consultancy/online-presentations

Direct phone: +45 9635 4456



By Lars Gullev, Managing Director, VEKS

For all of us, efficient use of the resources in the world is on top of the agenda. Only in this way can we ensure that our children and grandchildren can have the same opportunities in life that we have had. Therefore, it is important that we focus on how waste residues in one process can be a resource in another process. If we succeed, we can create a real life fairy tale!

An agreement, signed 2 December 2016 between CP Kelco and the district heating (DH) company VEKS ensures that as from Q4, 2017, a huge amount of the excess heat will be utilized in the local DH network, which VEKS is currently expanding. The recovered amount of excess heat is calculated to 150 TJ/year (42,000 MWh/year), which is 25 % of the total heat demand of Koege DH company. Extreme COP value As seen in figure 2, excess heat from the extraction process is supplied to the heat exchanger with a temperature of 75 o C (direct heating). Here, the DH return water is heated up from 47 o C to a flow temperature of 72 o C. In parts of the year, where a DH flow temperature of 85 o C is required, the additional temperature boost is done by using the heat pump which uses excess heat from the extraction process.

Such a fairy tale starts in South America where the citrus fruits grow.

Juice and oil The citrus is picked and the juice is squeezed out of the fruit flesh and citrus oil is pressed out of the peels. After juice and oil are extracted from the citrus fruits, the peels are dried and shipped to Denmark for the company CP Kelco, situated about 40 km south of Copenhagen. At CP Kelco, pectin is extracted from the peels. Pectin is a naturally occurring substance found in citrus fruits, apples and other fruit. At CP Kelco, the citrus peel goes through a comprehensive extraction process, after which the pectin is available in powder form. Pectin is used to improve texture and stability in a variety of products, especially within the food area. Pectin is e.g. the gelling agent that adds the right level of thickness to jams and jellies. Pectin is also used in e.g. dessert fillings, medicines, sweets, fruit juices and milk drinks. Excess heat The pectin extraction process requires large amounts of energy, and the excess heat has until today been lost in cooling towers (Fig. 1).

Fig. 2 - Principal diagram and construction boundary between CP Kelco and VEKS

Therefore, since it is only the last 13 o C which is boosted by the heat pump (72 o C to 85 o C), while the first 27 o C (from 45 o C to 72 o C) is heated directly with the excess heat, the overall COP (Coefficient Of Performance) of the system is about 18.5. So we are here talking about a very high system efficiency. After pectin is extracted from the peels, a by-product is left. Previously the by-product was used as feed for calves, but the farmers who produce calves have moved from the eastern to the western part of the Denmark, making transportation too expensive. Biogas plant wanted In 2008, the idea of constructing a biogas plant arose caused by the odour of decomposing seaweed at the beach of Koege Bay. The idea was to build a biogas plant that could utilise the seaweed, organic residual products, including citrus peels from CP Kelco, and animal manure, in order to produce green energy.

Fig. 1 – CP Kelco – Cooling towers

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The project couldmake it possible to produce biogas and utilize the biogas for producing combined heat and power (CHP), which is in line with both the national policy of promoting CHP and biogas, and the energy and climate policy objectives of the municipality of Solroed to convert the local heat supply to major CO2 neutrality. In 2011, the municipality of Solroed signed an agreement with the EU on financial contribution of € 480,000 to realise the Solroed Biogas project and in 2015 the biogas plant – owned by the municipality of Solroed – went into operation.

Fig. 5: Solroed gas engine – 3 MW electricity and 3.7 MJ/s heat

The CHP plant has a capacity of 3 MW electricity and 3.7 MJ/s heat, and the annual production is estimated to 100 TJ (28,000 MWh) green DH and 25 GWh green electricity. The CHP plant has now been in operation for approx. one year and the production of green electricity has passed 22 GWh. The biogas is primarily used in the gas engine because of an attractive feed-in tariff – 16 €cent - on electricity based on biogas (green electricity). If the gas engine is out of operation due to maintenance, the biogas is used in the boiler with combi-burner oil/biogas, and only heat is produced. The district heating from the gas engine – or boiler with combi burner for oil/biogas - is primarily supplied to the local DH network in Solroed and secondarily supplied into the VEKS transmission DH network in the Greater Copenhagen area.

Fig. 3 – Solroed Biogas Plant (Photo: Solroed Biogas A/S)

The annual amounts of raw material to the biogas plant and biogas production are shown in fig. 4. Further is shown how the different elements of raw material contributes to the project.

Raw material

To the biogas plant tonnes/year

Calculated methane production

Contribution to the project

1,000 m3/year 4,514.8 (75 %) 578.8 (9.5 %) 31.6 (0.5 %) 918.7 (15 %) 6,000 (100 %)

Citrus peels (CPK) Manure Seaweed Industrial residues Total

80,000 53,000 7,000 60,000 200,000

Gas production Gas production and process stability Nutrients and improved water quality Gas production and nutrients Benefits for the environment

Fig. 4 – Raw material to Solroed Biogas Plant

The biogas plant reduces greenhouse gas emissions in several ways: • By substitution of fossil fuels for energy production. • When removing seaweed from the beach (seaweed emits the greenhouse gas methane when it rots). • When replacing soil materials in the agriculture. DH and electricity VEKS – as a DH company - buys the biogas from Solroed Biogas plant and transports the biogas through a 3.5 km long underground gas pipeline to Solroed peak and reserve load boiler station. The boiler station is equipped with 2* 12 MJ/s boilers – one with oil burner and one with combi-burner for oil/ biogas - for heat production to the Greater Copenhagen DH system.

Fig. 6 - The Greater Copenhagen CHP system. Solroed biogas is marked with an orange circle.

Now the boiler station has been extended with a CHP plant for biogas, where the biogas is utilised in a Jenbacher gas engine.


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