HOT|COOL NO. 4/2017 "Technical Innovation and Optimization"

N0. 4 / 2017

INTERNATIONAL MAGAZINE ON DISTRICT HEATING AND COOLING

TECHNICAL INNOVATION AND OPTIMISATION

DBDH - direct access to district heating and cooling technology

www.dbdh.dk

CONTENTS

4 5

THE COLUMN : YOUR DIGITAL SUPPLY AND PERSONAL DATA METER

COUPLING OF ENERGY SECTORS IS A KEY TO AN EFFICIENT TRANSITION TO A RENEWABLE ENERGY SUPPLY

7 10 13 17

INTELLIGENT USE OF INTELLIGENT PUMPS

ENERGYLAB NORDHAVN, DENMARK – A FULL-SCALE SMART CITY ENERGY LAB

OPTIMAL OPERATION OF A MULTI-VECTOR DISTRICT ENERGY SYSTEM IN THE UK

HEAT EXCHANGERS WITH INCREASED THERMAL LENGTH ARE ESSENTIAL GOING TOWARDS THE NEXT GENERATION OF DH SYSTEMS

20

DATA-DRIVEN DISRUPTION – UNLOCKING THE DISTRIBUTION NETWORK BLACK BOX WITH SMART METER DATA

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DISTRICT HEATING: IS IT DELIVERING AFFORDABLE AND SUSTAINABLE HEAT FOR UK SOCIAL HOUSING?

27 28 30

NEW MEMBERS

MEMBER COMPANY PROFILE: MOE

LIST OF MEMBERS

TECHNICAL INNOVATION AND OPTIMISATION

HOT|COOL is published four times a year by:

DBDH Stæhr Johansens Vej 38 DK-2000 Frederiksberg Phone +45 8893 9150

Total circulation: 5,000 copies in 50 countries

info@dbdh.dk www.dbdh.dk

ISSN 0904 9681 Layout: DBDH/galla-form.dk

Editor-in-Chief: Lars Gullev, VEKS

Pre-press and printing: Kailow Graphic A/S

Coordinating Editor: Kathrine Windahl, DBDH

Overview of Copenhagen’s Nordhavn. Photo: By & Havn / Ole Malling

E N E R G Y A N D E N V I R O N M E N T

DISTRICT HEATING FROM A-Z RELY ON 50 YEARS OF EXPERIENCE IN ALL DISTRICT HEATING APPLICATIONS

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CHP POWER PLANT

BOILER HOUSE

SUB-STATION

CONSUMER CONNECTIONS

PLATE HEAT EXCHANGE

MAIN PUMPS

BOILER SHUNT PUMPS

DISTRIBUTION PUMPS

MIXING LOOPS

FLOW FILTER PUMPS

LULL HEAT PUMPS

PRESSURE HOLDING SYSTEM

FLUE GAS ECONOMISER

WATER TREATMENT PUMPS

FROM POWER PLANT TO CONSUMER CONNECTION Grundfos is one of the world’s leading suppliers of solutions across the full range of pump applications. In Grundfos District Heating, we think beyond the pump. We look at the entire system – from power plant to end user – to

provide you with the most intelligent, reliable and adaptable solutions possible. This approach has made us a preferred partner for district heating companies across the globe, and we look forward to helping you as well. To learn more go to www.grundfos.com/districtenergy

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By Bent Ole Gram Mortensen, Professor, Juridisk Institut, Syddansk Universitet THE COLUMN

YOUR DIGITAL SUPPLY AND PERSONAL DATA METER

DIGITAL CONCERNS The digitization is upon us. Yes, you get the impression when you leaf through the daily press - digitally as well as analogously. It is not something that has happened overnight, but something that affects us broadly. The utilities are inextricably linked to data. They handle both more traditional customer data such as name, address etc. and an increasing amount of supply data from the utility meters, all in an increasingly digital way. Digital data troubles the European population. According to the Eurobarometer 2015, 81 % of Europeans feel that they do not have fully control over their personal data online, and 69 % of Europeans would like to be able to submit their express confirmation before their personal data can be collected and processed. The risks of digital data are primarily related to privacy. If consumption data is detailed/frequent enough, it provides opportunities for profiling the residents. Data about the daily life and the energy consumption, and possible changes in this, compared with information about the buildings and residents can be used by authorities for control for e.g. social fraud and to identify efficiency potential, for example poor insulation. There are many applications – for better or for worse. Digital systems are also vulnerable to hacker attacks and carelessness with personal data. In principle, each supply meter becomes a target for attack. Regarding the latter, attempts with remote digital reading meters have demonstrated that it is possible to hack into a subnet with multiple meters, even in a setup where the electricity meters communicated via the electricity grid and thus somewhat different/more difficult than nets connected to the Internet. This could also happen with district heating (DH) meters. The EU has responded to extensive data leak by replacing the 20-year-old Data Protection Directive with the Data Protection Regulation, which will take effect from May 2018. It is a comprehensive legislation with 173 recitals and 99 articles. PERSONAL DATA IN THE SUPPLY SECTORS That customer data is personal information does not rule much doubt. Data Protection Regulation article 4 defines it as “any information relating to an identified or identifiable natural person”. Among traditional personal data are name, address, social security number, telephone number, bank details, civil status and economic conditions.

If consumption data can be linked to an identifiable natural person, such as a household consumer, it is personal data. Measurements of a household’s consumption are presumably also personal data, even if it is a family of five who consume from the same meter. Personal data must have a legal basis, or consent must have been given to process the data according to the Regulation. The legal basis can be consent, contractual obligation, social interest or perhaps the special collective provision on legitimate interests. The latter may come into play if you want to use the supply data for other purposes than what the data was originally collected for. BIG DATA In coming years, DH suppliers will among others replace the old analogue supply meters at the end user with new digital meters. As a result, the supply sectors will swim in “big data”. These big data can truly be a gift. Tele-metering, digital cut-off, and the ability to detect leaks quickly, will produce savings, even if resources are needed for the operation and maintenance of IT. The frequent readings also allow optimization of the network – both in terms of operations and investments. Within the district heating sector, one can imagine scenarios, where the optimization options will be able to repay the investment in digital meters within a few years. Altogether there are a lot of good, maybe even legitimated, interests related to measuring supply data. Utilities must both be able to settle and handle their primary supply task effectively. Authorities should be able to operate supply policies (e.g. efficiency, security of supply and environment). POLITICAL PANIC Data leak has been the biggest problem and supposedly the reason why we now get a regulation. DH companies contain both customer data and supply data, and these personal data must be treated properly. The supply companies must put their shoulders to the wheel to avoid bad cases of personal data leaks. Nor can it be recommended to peddle that kind of data to any mercenary soul who will sell everything under the sun. Otherwise one can expect rigid restrictions. The worst-case scenario is that politicians and authorities in ‘panic’ over the new regulation will pull in the emergency brake. That communities, sectors and end-users will be prevented from exploiting the beneficial potential of the big supply data, for example because authorities are in doubt or are too strict at what should be legitimate interests. Everyone must help so we do not end up in that kind of situation.

E N E R G Y A N D E N V I R O N M E N T

plant

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By Rasmus Lund, Ph.D., Assistant Professor, Department of Planning, Aalborg University

Heat pump

Heat pump

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demands will cut the total need for energy input and reduce costs for the energy systems and further improve the benefit of the sector coupling. Hence, the discussion in this article will be equal or more valid also in this situation. CHP Fuel 71 Heat 40 Transport (30) 38 15 CHP Fuel synthesis Fuel 39 27 8 11

Heat 40

In order to reach an energy system based on renewable and sustainable resources in an efficient way, we need to transform our energy systems to allow fluctuating renewables to replace fuel consumption. This can be done through a coupling of the main energy consuming sectors via supply and conversion technology that links the production from fluctuating renewables to demands across sectors to reduce the need for fuel. Here we take a look at the effect on the whole energy system as 25%, 50% and 100% renewable electricity is introduced.

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Figure’s legend and explanation

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The figures illustrate energy systems as primary energy input on the left side, conversion units in the middle and demands on the right side. The demands are the same in all the four figures, and the differences illustrate different ways of covering the same demands. The numbers for the “Transport” sector do not add up to 30 because these include efficiencies of different vehicle types to cover the transport demand. The difference is mainly between internal combustion engines and battery electric vehicles.

THE NEED TO TRANSFORM THE ENERGY SECTORS

Electricity 30

W

Today, electricity, heating and transport demands are generally, on the global scale, covered through combustion of fuels and are generally seen as independent. These fuels have a number of environmental, social and economic consequences, such as climate change, pollution of water, soil and air, resource depletion etc., and it seems obvious that this is not a sustainable path to continue on. The reduction of fuel consumption is important whether it is fossil or bio fuels. Fossil fuels have their issues, where carbon emissions is the biggest, but there are also issues in relation to bioenergy consumption. Bioenergy is a limited resource, and even though there is some discussion on how much of this potential can be used for energy purposes in a sustainable way, there is a general consensus on the fact that the resources are not enough to replace today’s consumption of fossil fuels one- to-one. So on the long term we should strive to reduce the fuel consumption of all energy sectors. Fuel 133 40 33 60 Power plant

Figure 1. A traditional energy system where sectors are divided and al l demands covered through the use of fuel.

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Electricity 30 Figure 2. A combined heat and power (CHP) system that couples the heat and electricity sectors, where 25% of the total electricity demand can be covered by fluctuating renewables.

Electricity 30

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DEMONSTRATING ONE POSSIBLE TRANSFORMATION PATH

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Conversion unit

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Heat 40 Figure 3. An integrated energy system where the heat and electricity sectors are coupled through both CHP and heat pumps, and where 50% of the total electr ici ty demand can be covered by fluctuating renewables. Electricity 30 40 Heat 40 Electricity 30 Heat pump 8 25 15

Wind (50%) 19 Wind (25%) 8 Wind (75%) 39

Electricity 30

Win

Electricity 30

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Wind (50%) 19

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In this article, I would like to demonstrate the idea of how a gradual replacement of the energy conversion infrastructure, from the traditional single-sector technology to a multi-sector focus, can help the coupling of sectors and significantly improve the system’s ability to integrate fluctuating renewables reducing fuel consumption. I use four simple illustrations of energy systems, each with the same demands but with different supply systems and primary energy input. Even though the figures are simple, the different efficiencies and the systems’ abilities to integrate fluctuating renewables are based on thorough investigations, and the systems have been analysed using real demand and production profiles in the hourly simulation model EnergyPLAN. Fuel 133 40 33 60 Power plant Wind (50%) 19 19 CHP Fuel 71 38 19 Conversion unit

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Heat 40 Figure 4. A smart ene gy system where the transport sector is coupled to the el ctricity sector through electric vehicles and synthetic fuels, and where 75% of the total electricity demand can be covered by fluctuating renewables. Electricity 30 Heat pump 8 25 15 Supply / demand Electricity

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Energy efficiency measures in buildings, industry and vehicles are not discussed in this article, but are important to consider in the planning of this transformation. Essentially, reducing the

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Heating

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COUPLING OF THE TRANSPORT SECTOR IN A 100% RENEWABLE ENERGY SYSTEM The last step here is to couple the transport sector with the other sectors. This is achievable in a smart energy system, illustrated in Figure 4. This includes direct electrification (plug-in electric vehicles or electrified rail) of vehicles and fuel synthesis for production of liquid or gaseous fuel for combustion engines. The direct electrification of transport is important to expand as much as possible because this has a much higher energy efficiency than transport based on combustion engines. Not all transport can be covered with direct electrification though, so aviation, heavy ship and land freight may also in the future need some fuel. This need for fuel may be covered with electrofuels, which is a synthesis of 1) a carbon source, such as gasified biomass or CO2 emissions from CHP plants and 2) hydrogen from electrolysis using fluctuating electricity as the energy source. The fuel synthesis is not yet a well proven technology in large scale, so there are some uncertainties related to this still. However, it looks like a promising alternative for the transport sector to integrate fluctuating renewables, up to around 75% of the total electricity demand. In this system, it is possible to cover the demands with little fuel, and potentially cover all demands with 100% renewable energy within sustainable limits of bioenergy. SUMMARY AND CONCLUSIONS The three steps, from the traditional to the smart energy system, are able to reduce the need for fuel from 133 units to only 39 units, integrating additional 39 units of wind, in this particular case covering 100 units of demand. This can be achieved through an effort to couple the different energy sectors using flexible and efficient conversion units. The transition illustrated through the figures requires large changes, not only on the technological level but also in the regulatory frameworks and organisation of the energy sector to support such a transition. The core of this is that the current organisations and institutions are designed for (and by) a centralised energy system based on fuel consumption, whereas a smart energy system is much more decentralised in its components and organisations and its economy is based more on investments rather than consumption of fuel. ACKNOWLEDGEMENTS The work presented in this article is a result of the research activities carried out in the EU Horizon 2020 project Heat Roadmap Europe 4 (www.heatroadmap.eu) and the Strategic Research Centre for 4th Generation District Heating (www.4dh.dk), which has received funding fromThe Innovation Fund Denmark.

FIRST STEPS TOWARDS SECTOR COUPLING Traditionally, the different energy consuming sectors have been completely isolated from each other, which has led to the traditional energy system structure (see Figure 1). Here, fuel is used to cover all energy demands through single-sector conversion units, and the system consumes 133 units of fuel to cover the total demand of 100 units. The power plants producing the electricity may have a high efficiency when only looking at the electricity sector, but when considering that the excess heat from the process could have been used for other purposes, reducing the consumption of fuel elsewhere in the system, the efficiency doesn’t seem that high any more.

SOME FLUCTUATION ELECTRICITY FROM WIND AND SOLAR

Figure 2 shows a system where combined heat and power (CHP) is implemented to improve the overall system efficiency through supplying the excess heat from the power production to cover heat demands. In some cases, this excess heat can cover heat demands in industrial processes, but in many cases, it will also require a district heating (DH) network to be in place. In systems with DH networks and CHP units, an investment in a relatively cheap thermal storage can support integration of fluctuating electricity up to about 25% of the demand in a cost- effective way. The thermal storage provides a flexibility for the CHP units to operate more independent of the heat demand, and more according to electricity demands, thereby being able to balance out some of the fluctuations from wind, solar PV, etc. INCREASING ELECTRICITY PRODUCTION FROM FLUCTUATING SOURCES REQUIRES NEW DEMANDS To reduce the fuel consumption further, integration of more fluctuation renewables is needed. However, this can be hard to do in a feasible way with only the conventional electricity demands. Therefore, an option can be to introduce electricity- to-heat through heat pumps or electric boilers for production of heat (see Figure 3). This can be relevant in buildings with individual heating systems, but particularly in areas covered with DH. In DH networks, heat pumps can be operated more flexibly, for example by turning off the heat pump in times with very low production of wind power and instead supplying the heat from a centralised thermal storage. DH also enables utilisation of large- scale low temperature heat sources that would otherwise be lost, e.g. excess from industry, waste water treatment or hospitals. In individual buildings, the potential for operating a heat pump in a flexible way is lower because it has to deliver the heat when needed. But a heat pump is still more efficient than a fuel-based heat-only boiler if there is no DH network available. Through all the steps, the power and CHP plants are producing gradually less electricity. In the transformation, their role is changing from being simply to deliver electricity to the electricity system to balancing the fluctuations of the renewable production. This will increase the requirements for the power and CHP plant’s ability to regulate their production up and down.

For further information please contact:

Aalborg University Att.: Rasmus Lund

A. C. Meyers Vænge 15 DK-2450 Copenhagen

Phone: +45 99402421 rlund@plan.aau.dk

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By Anders Nielsen, Application Manager, CBS HVAC Solutions, Grundfos

How new pumps can be a tool to increased system efficiency

Traditionally, we use pumps in hydronic systems to deliver the needed flow and pressure; that’s it, nothing more. Pumps including frequency drive have been around for years, but do we utilize their full potential? The author is confident we do not!! One area where we see challenges in district heating (DH) systems is when we want to introduce low temperature DH. Let’s look at a small and simple example:

In this case, we increase the flow from 491 m3/h to 688 m3/h. This leads to a (688/491)2 = 1.96 factor increase in pressure resistance. If we assume the distance from production to final residential consumer is 4,000m originally, we have a design pressure loss of 150 Pa/m, which leads to a total original pressure loss of 4,000*150 = 600,000 Pa = 600 kPa equal to 6.0 Bar. If we then increase the flow to the mentioned 688 m3/h, the pressure losses increase to 1.96*6.0 = 11.8 Bar. In other words, the pressure per meter will be: 150*1.96= 294 Pa/m.

Here, we have a traditional system with design flow temperature at 90°C and a return temperature at 55°C giving a delta T of 35°C.

If we decide to add this needed additional pressure at the same point as before, the pressure profile will look like this:

In this case, we set the DH plant to deliver a maximum capacity at 20 MW leading to a needed flow of: 20 * 860/35= 491,4 m3/h.

Now, if we want to operate the system by another temperature set like 65°C/40°C, the consequence would be a delta T drop from 35°C to 25°C as distribution of heat is expressed by:

Ф = Q* ∆ t, Power is equal to flow multiplied by delta T.

This leads to the following new flow: 20 * 860/25 = 688 m3/h; in other words, we need a 40 % increase in the flow demand to deliver the same heat capacity. Based on affinity laws, we know the relation between flow and pressure is so that if we want to double the flow, the pressure resistance increases by a factor 4. See below example, where the pressure increases from factor 1 to factor 4 (even though the flow only doubles):

Well, it might be possible to add the pressure, but in this case the maximum pressure grade for the pipes is only 10 bar, so as the needed pressure will be 11.8 bar, this maximum is clearly exceeded. The 10 bar can be illustrated as above red dotted line.

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THE SOLUTION TO THE CHALLENGE Instead of adding all the pressure right at the beginning, it is possible to add the pressure when we need it. This can be illustrated as below:

to the system generally is reduced. With more manageable differential pressure in front of customer installations, the risk of by-pass is also reduced. It will be a challenge to prove that distributed pumps will lead to lower return water temperatures, but it might be a possibility. OTHER POSSIBILITIES A general reduction of flow temperature right from production, might not be optimum in all cases. Some customers might need a higher temperature than more modern new-build houses. In these cases, we could consider dynamic flow temperature adjustments in the network, where this is possible. Let’s take one example:

The series’ connected pumps will deliver only the required pressure until the next pump in line takes over. The traditional approach with one spot for adding pressure, to now a dynamic add of pressure, is possible when we utilize new modern pumps with speed and thereby pressure control. So in this way, modern pumps can be an enabler for introducing low temperature DH. The positive side effect will be that differential pressure exposed

The future is green – just like Fjernvarme Fyn Every day we work to develop production and supplies for tomorrow’s society. We have come a long way in the transition to sustainable, renewable energy production. Recently, we announced an ag- reement with Facebook to utilise surplus heat from their forthcoming data centre in Odense for district heating. At the same time, we are converting Fjernvarme Fyn’s waste energy plant at a cost of DKK 250 mil- lion. Following the conversion, the plant’s capacity and the energy from waste will be utilised better and more efficiently. That’s why the future’s green for Fjernvarme Fyn, and for generations to come. Read more about Fjernvarme Fyn at www.fjernvar- mefyn.dk.

Fjernvarme Fyn is one of Denmark’s largest district heating companies. We supply heating to more than 90,000 households through more than 2,100 km of district heating pipes. The vast majority of the heat is produced at Fjern- varme Fyn’s three CHP plants on Havnegade, fuelled by waste, straw and coal.

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For section 1-2, we run the system by 90°C until the two first branches. Where the arrows are pointing, we install two mixing loops in pits, enabling us to reduce the flow temperature from 90°C to 70°C. The positive effect is that the pressure loss in this part of the network is reduced from 287.5 to 80 kPa. This is the main reason why the total cost for operating the pumps is reduced to 508,358 kWh/year. This is still an increase, but what’s more important is that the associated heat losses are reduced from 1,252,700 kWh/year to 549,300 kWh/year. This is a stunning 703,400 kWh/saving every year. On top, total CO2 will be reduced further, as the boilers will not have to produce this heat.

We have a traditional tree-structured network, where calculations have shown that flow temperatures can be reduced to 70°C. This is just an example, as each network has its own unique conditions for what is possible. First let’s see what the current heat losses as well as pump operating cost are.

To sum up the comparison, please see below:

With a delta T at 50°C, the flow rates are relatively modest, which is also reflected in the pump operating cost of 113,690 kWh/year. But with the high flow temperature the heat losses are considerable, in this case 1,252,700 kWh/year.

If we, just for the experiment, lower the overall flow temperature to 70°C, the scenario will look like below:

CONCLUSION By introducing the concepts of dynamic DH we can add speed controlled pumps when we need to boost pressure. As these pumps typically will be connected to an overall monitoring system, like SCADA, we can get information like temperature, flow and delivered heat energy (This information is readily available in at least some new pumps). The increased knowledge can lead to increased system efficiency. Where system design requires an “in network” approach, we can adjust network temperature to the lowest possible levels. This dynamic approach is possible due to use of pits with prefab mixing loops, including pumps and all needed components.

Now the heat losses will be reduced dramatically, but on the other hand the pump operating cost increases to 818,180 kWh/ year for the original 113,690 kWh/year, quite dramatically.

The alternative to this could be to change flow temperatures where this is possible, as in below example:

For further information please contact:

Grundfos Att.: Anders Nielsen Grundfos Poul Due Jensens Vej 7 8850 Bjerringbro

Direct: +4587504601 anders@grundfos.com

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By Kristian Honoré, Energy Planner, Hofor

The future district heating system will include more fluctuating renewables and low temperature heat sources, and this requires technical innovation, optimization and integration with other energy infrastructures for optimum utilization.

A FULL-SCALE SMART CITY ENERGY LAB Project “EnergyLabNordhavn –Newurbanenergy infrastructures” is developing and demonstrating future energy solutions. The project demonstrates how electricity and heating, energy- efficient buildings and electric transport can be integrated into an intelligent, flexible and optimized energy system. The objective of the EnergyLab Nordhavn project is to develop new methods and solutions for design and dimensioning of the future cost-effective integrated energy system. The project partners are: Municipality of Copenhagen, City Port & Harbour, HOFOR, Radius, CleanCharge, ABB, Danfoss, MetroTherm, GlenDimplex, Balslev, DTU & PowerLabDK. The project started in April 2015 and runs until March 2019. It has a total budget of DKK 143 m (€ 19 m); of this, DKK 84 m (€ 11 m) is in two rounds funded by the Danish Energy Technology Development and Demonstration Programme (EUDP).

The EnergyLab Nordhavn project in Copenhagen, Denmark, demonstrates that optimization and innovation in existing and new district heating (DH) systems will enable further integration of the energy systems. The DH system can offer both storage and flexibility services as well as an opportunity for integration of low temperature excess heat. The EnergyLab Nordhavn project is using Copenhagen’s Nordhavn as a full-scale smart city energy lab - the largest city development area in Scandinavia - supporting the vision of Copenhagen becoming the world´s first CO2-neutral capital in 2025. HOFOR – GREATER COPENHAGEN UTILITY COMPANY HOFOR is the largest utility company in Denmark and offers services within DH, district cooling, combined heat and power (CHP) production, water, sewage, city gas and renewables. HOFOR District Heating is delivering green, safe and affordable DH to approx. 600,000 citizens of Copenhagen and aims to be 100 % CO2-neutral in 2025.

The project is divided into 10 work packages as illustrated below:

The DH is supplied via the integrated DH system of Greater Copenhagen and total supplies are 35 PJ/year or equivalent to 20 % of all heat demand in Denmark. HOFOR district heating pipes have a total length of 2,900 km. NORDHAVN - THE AREA Copenhagen´s Nordhavn district is a partly existing peninsula that over the next 40 years is being developed into a new sustainable city district with 40,000 new residents and 40,000 new jobs. Nordhavn will be a very dense area and consist of mainly apartment and office buildings to secure an attractive and vibrant new community.

WP9

Showroom and visualisation

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Integrated markets and control centers

Flexibility from heat and cooling grids

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Photo: By & Havn/Ole Malling

Fig. 1. Work Package (WP) illustration of the EnergyLab Nordhavn Project Photo: By & Havn / Ole Malling

A range of innovative DH solutions for optimizing and developing the existing system into a vital part of the integrated energy system are demonstrated. As results materialize, more articles will follow.

The whole area is developed according to the German DGNB standard (Deutsche Gesellschaft für Nachhaltiges Bauen) for sustainable cities and buildings. All the buildings are built in accordance with the latest building codes in Denmark and designed for low energy demands.

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STORAGE AND FLEXIBILITY IN THE DISTRICT HEATING SYSTEM

Locally at the customers Another type of heat storage is demonstrated in around 15 buildings in Nordhavn, where the DH supply for shorter periods is reduced, closed or increased to the buildings. The different supply strategies will utilize the thermal capacity of the buildings and are implemented as an instrument for reduction of peak load production without compromising the comfort level of the customers. To secure the comfort level of the customers a number of room temperature sensors are installed to measure and detect changes in the room temperature during demonstration periods. Preliminary results from two different buildings show that the thermal capacity allows for several hours with reduced or even closed supply, without compromising the indoor temperatures. However, the preliminary results also show that there are complexity challenges to be considered, especially in buildings having ventilation systems, large window areas and low thermal mass. Fig. 3 is an example of a typical DH substation in a multi- family building in Nordhavn, as well as an illustration of the demonstration, where peak load hours are load shifted away from 06.00-09.00 and 17.00-20.00 and into base load hours.

Heat storage and flexibility are very important measures for optimizing production and operation of the DH system to reduce the production from expensive and fossil-fueled peak- load boilers. Flexibility in the DH system can also support and utilize the fluctuating electricity coming from renewables in the future integrated energy system.

Areas for storage and flexibility in the DH system: 1. Centrally at the production sites 2. In the distribution networks 3. Locally at the customers

Centrally at the production sites It is investigated and demonstrated what added value the integrated energy system will have from running an existing central heat storage as a typically “security of supply” driven storage to a more smart and integrated oriented approach. In the distribution networks Heat storage in the DH network is also an applicable flexibility asset for reducing the use of expensive and fossil-fueled peak load boilers during peak load hours. In two different demonstrations, the supply temperatures were significantly raised in the DH network supplying Nordhavn, during nighttime, to pre-heat (charge) the network, prior to the morning peak. The first two demonstrations carried out have shown significant decreased peak load demand at each of the customers, as well as at the group area substation (production site) during morning peak-load hours. An example of the lowered peak demand at a customer is illustrated in fig. 2. The blue line represents the flow demand in a reference period with normal DH temperatures and the red line represents the flow demand in a demonstration period with increased DH temperatures. The vertical lines illustrate the demonstration period of 24 hours.

Fig. 3. Load shifting from peak load hours to base load hours

An additional flexibility and storage capacity is to be found in the domestic hot water tanks in the multi-family buildings, as they typically hold between 500 to 2,000 liters of domestic hot water that can be utilized and optimized for lowering the impact of domestic hot water demand in the morning peaks.

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So far this has only been tested in a single building, but the results are promising and therefore further tests and analyzes will be initiated in the current heating season. Again, this demonstration will be realized without compromising the comfort level of the customers. During the heating season of 2017-2018, the flexibility of the 15 buildings in and around Nordhavn, will be demonstrated to analyze the potential impact of a possible rollout in Copenhagen.

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0

Fig. 2. Lowered peak flow demand at customer level at charged district heating network

1

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MEASURED HEAT LABELLING SYSTEM OF BUILDINGS FOR BETTER DESIGN AND OPERATION A heat labelling system based on measured heat consumption and heat profiles of existing buildings has been developed as an alternative to the existing heat labelling system. The proposed evaluation method deviates radically from the theoretical calculation of the mandatory energy labelling system and focused on the four below mentioned parameters: 1. The building`s unit consumption in kWh/m2 per year, and the development from previous years 2. The return temperature from the building`s heating central on a summer and winter day respectively 3. The building`s physical condition (insulation conditions), and the condition of the technical installations (system solutions) 4. The building`s heat profile and capacity demand during peak load hours (~06-09.00, and ~17-20.00) on a summer and winter day respectively Preliminary results indicate that there is a +10 % energy saving potential in better design and operation of the installed DH substations. This is also of significant importance for the operation of the DH network and thereby the overall business of the utility company. Fig. 4 shows an example of the developed heat label providing new and valuable input for better design and operation of buildings and their district heating substations.

Other interesting and innovative DH demonstrations in the EnergyLab Nordhavn project are:

- A flexible heat pump system supplying DH to four large buildings outside the central DH network - Fuel shift operation of a domestic hot water tank – in up to 10 row houses, where the tank can be heated by either DH or electricity depending on i.e. energy prices and/or CO2- content - Heat pump booster for domestic hot water in combination with ultra-low temperature DH (<45 o C) in one of the new floor-heated, multi-family buildings - Heat pump for DH return temperature optimization while maintaining a stable temperature of the domestic hot water circulation - Integration of excess heat from a local supermarket in Nordhavn into the DH system. The supermarket will deliver excess heat from the refrigeration system into the DH network via the existing DH connection

For further information please contact:

Kristian Honoré Energy Planner Energy Planning Department

Phone: +45 2795 4726 krih@hofor.dk

2. RETURN TEMPERATURES

1. HEAT CONSUMPTION AND TENDENCY

ENHEDSFORBRUG

2

62W/m2

RETUR

2 39 o C

PROFILVARIO

4

100%

FLEXFAKTOR

3. BUILDING DESIGN AND INSTALLATIONS

CUSTOMER IDEAL

4. HEAT PROFILE AND CAPACITY VARIATION

1

2

2,2

3

4

Fig. 4. New heat labelling concept and performance indicators

E N E R G Y A N D E N V I R O N M E N T

P13

By Michele Tunzi, Miaomiao He, David Allinson and Kevin Lomas - Loughborough University, UK. Mark Gillott and Lucelia Taranto Rodrigues - University of Nottingham, UK. Svend Svendsen, Technical University of

Denmark Kgs. Lyngby, Denmark, Charles Bradshaw-Smith, SmartKlub Ltd, Oxon, UK. Nick Ebbs, Blueprint, Nottingham, UK. John Lindup, A.T. Kearney Limited, London, UK.

The large price drop in solar PV and electrical batteries offers new opportunities for optimizing district energy plants, but requires a more complex daily operation of these plants. Solar PV production used locally by a ground source heat pump (GSHP) with a minimal use of the national grid is one opportunity. Even if, for the benefit of the GSHP, the share of electricity for boosting the temperatures of district heating water goes up when lowering forward temperatures in the network down to as low as 45 °C, the overall operational income is improved.

TRENT BASIN AND PROJECT SCENE The work presented in this article illustrates the optimal operation of a multi-vector district energy system, assessing the main techno-economic parameters and different scenarios for a community energy system. It is based on a new housing development in Nottinghamwhich is part of a large regeneration of the ex-industrial areas alongside the River Trent. Project SCENe (Sustainable Communities Energy Networks) is an initiative supported by Innovate UK and the Energy Research Accelerator (ERA). It looks to accelerate the adoption of Community Energy Systems (CES). This approach represents a different way of generating and supplying heat and electricity to homes and commercial buildings where locally produced energy is used locally with minimal use of the national grid. The benefits are, potentially, reduced cost and more efficient use of distributed renewables to reduce the overall carbon emissions from the energy system. The investigation described here focused on 33 new low-energy buildings assuming their connection to a low temperature district heating (LTDH) network, fuelled by a ground source heat pump (GSHP) with a maximum heat capacity of 350 kW. The energy system will also embed 20 m3 of thermal storage, 450 kWp of solar PV and a battery bank of 2.1 MWh, representing the largest domestic application in North Europe and the first of its kind in the UK. As presented in the schematic view of Figure 1, a local Energy Service Company (ESCO) will manage and operate the multi- vector district energy system, supplying heat to the end-users, whereas the electricity demand will be covered through a typical domestic contract with the local energy supplier. As this will not affect the operation of the CES, the domestic electricity demand was disregarded in the analysis presented. The multi-vector energy system was simulated using energyPRO, an advanced energy software that allows for the simulation and optimisation of complex energy systems.

Despite its actual share of less than 2 % of the entire UK heat market, district heating (DH), due to its flexibility and capacity to integrate low-grade heat sources, has been recognised as a key technology in the transition towards a low carbon society. In fact, heat networks will play an important role in the future UK energy market to help securing energy supply and reducing CO2 emissions. It was estimated by the Department of Energy and Climate Change (DECC) – now restructured as the Department of Business, Energy and Industrial Strategy (BEIS) – that DH could supply in a cost-effective way up to 14 % and 43 % of the total UK heat demand in buildings by 2030 and 2050 respectively. This would be quite significant in the decarbonisation of the UK economy as heating and cooling consume nearly half of national primary energy. In a mature DH market such as Denmark’s, typical yearly average supply/return temperatures experienced in the network are 80/40 °C and real-time operations of four existing DH networks in Denmark can be found at www.emd.dk/energy- system-consultancy/online-presentations. Aiming to integrate alternative low-grade heat sources and reduce the distribution losses, their current efforts are seeking to achieve a load dependent supply/return temperatures of 50/20 °C, defined in literature as the 4th generation DH (4GDH) concept. The challenge is to ensure the same levels of space heating (SH) and domestic hot water (DHW) in existing buildings, as well as for new low-energy ones, with these lower operating temperatures. The design conditions used to size heating systems rarely occur during normal winters; hence, lower operating temperatures, even in existing heating systems, can be adequate to maintain the same indoor comfort for the majority of the time. In low- energy buildings, with low temperature, heat emitters such as underfloor heating (UFH) or low temperature radiators (LTR), inlet temperatures in the range of 35/45 °C can be appropriate to guarantee indoor comfort. In practice, regulations on legionella bacterium limit the lower temperature for DHW. In the UK, water must be heated to 60 °C in storage tanks or 50 °C if heated instantaneously.

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OPERATION STRATEGY AND ENERGY PRICES The dynamic demand profiles for each end-user were obtained using a stochastic approach and the results were validated by comparing these to typical UK profiles available in literature for similar buildings, occupancy and use. The strategy implemented to optimally operate the CES was focused on a cost optimisation to maximise the local use of the generated electricity both for direct use and storage/export, and as a consequence to minimise the import of electricity from the main grid. Three main scenarios were evaluated, considering the system operation under different operating temperatures: 55/25 °C, 50/25 °C and 45/25 °C. Yearly simulations were performed with energyPRO assuming the UK retail electricity price for 2016. This is composed of the day- ahead price (spot market) (47 % of total cost) and the remaining 53% of grid costs, taxes and commodities. When exporting electricity, the ESCO receives only the day ahead electricity price, hence it is important to carefully identify when the system should import or export electricity. The heat tariffs associated with DH networks are site-dependent and vary within the UK heat market. This was set to 95 £/MWh for this investigation by assuming that this is the average price an end-user would pay in the UK for useful MWh of heat using a typical individual gas combi boiler. The tariff includes the average gas price, the cost of the boiler and its efficiency and maintenance.

Figure 1: Schematic of the multi-vector energy system

Heat is supplied to each end-user through de-centralised heat interface units (HIU). Two dedicated plate heat exchangers (PEXs) will be installed for SH and DHW, and a ∆ T of 5 °C was assumed between the heat network and the secondary loops. UFH and LTRs are the chosen heat emitters for the SH systems, so supply temperatures in the range of 35-45 °C would be adequate to guarantee indoor comfort. For the instantaneous DHW preparation, a 32 kW PEX will be installed and an electric heater will also be placed on the secondary side of the DHW loop to boost the temperature if below the required limit of 50 °C. This will add more flexibility in the system operation, as supply temperatures even lower than 50 °C could be possible in the heat network, without any risks associated with Legionnaires' disease.

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Figure 2: CES optimal summer operation

The reduction of flow temperatures in the network was predicted to have a positive effect on the operation of the GSHP and reduced distribution losses, and this is also emphasised by the relative higher coefficient of performance (COP) values as illustrated in Table 1. Therefore, the choice to circulate supply water at temperatures as high as 55 °C could only be justified for the new housing development in question, if the HIU was not equipped with electric heaters or other devices necessary to boost the DHW temperature to the required level of 50 °C.

An extract of a weekly summer operations for the scenario with forward temperature of 55 °C, simulated hourly with energyPRO, is presented in Figure 2, highlighting the optimal operation for the CES analysed. The battery and thermal store are key components optimised to reduce the intermittency of the electricity generated by the PV and ensure that the heat demand is always met. In particular, the thermal store allows to run the GSHP using mainly the electricity locally generated; whereas, the battery to trade with the main grid, exporting the electricity generated on-site when the prices of the spot market are higher. SCENARIOS COMPARISON The comparison between the three scenarios is summarised in Figure 3, where the total heat generated, GSHP electricity consumption and distribution losses were calculated. The three scenarios, SCENe_55, 50 and 45, differ for the average forward temperatures in the network and highlighted the impact of temperature variation in the operation of the system.

Table 1: Summary of main CES operation results

Scenarios

Net Operational income (£)

COP

GSHP from renewable energy

Share of booster heater electricity for heated DHW (%)

SCENe_55

55,440

4.1

52

-

SCENe_50

56,512

4.5

50

19.0

SCENe_45

57,681

4.9

47

30.9

However, as expected, the reduction of the supply temperatures in the network would affect the operation of the system by increasing the share of electricity needed to achieve the DHW temperature of 50 °C, as summarised in Table 1. The installation of electric heaters in the HIUs offers larger operation flexibility, giving the ESCO the opportunity to operate the heat network with flow temperatures even below the limit of 50 °C. This is particularly valuable to reduce distribution losses and to increase efficiency in systems where heat generation is sensitive to low supply temperatures, as for heat pumps.

Figure 3: Heat network operation at different temperatures

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