European Solar Engineering School

Master Level Thesis

A case study of Swedish DH system

Master thesis 30 credits, 2021 Solar Energy Engineering

Author: Lucrezia Giorgio

Supervisors: Martin Andersen Puneet Kumar Saini Examiner: Ewa Wäckelgård Course Code: EG4001

Examination date: 2021-06-03

Dalarna University

Solar Energy Engineering

European Solar Engineering School

No. 278, June 2021

Hybrid solar district heating:combinations of high and lowtemperature solar technologies

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Abstract

In Sweden, the residential and industrial energy demand is provided by a significant part of district heating. In a decarbonization plan to reduce the CO2 emissions, the integration of a large-scale solar system in the district heating can be a suitable option. The most used types of collectors are flat plate collectors (FPC), for which efficiency drops at high temperature levels. Parabolic through collectors (PTC) have seen increased interest in later years, due to their higher efficiency at higher temperature levels, which could improve system performance both energetically and economically. A hybrid concept using a combination of FPC and PTC for a solar thermal system has previously been studied for a solar district heating system in Denmark, with the aim to maximize the solar production by operating the solar collectors in the temperature ranges where they excel. The first aim of this thesis was to adapt the hybrid solar system in a district heating system for a Swedish case study and to evaluate if the hybrid optimization studied has similar positive effects in the overall thermal production of the system in Sweden, as it did in Denmark. The second aim of this thesis was to investigate the use of photovoltaic thermal collectors (PVT) instead of FPC for parts of the solar thermal system. With PVT, a single solar collector module allows for simultaneous production of heat and electricity and integration of photovoltaic thermal collectors in the solar assisted district heating could improve the overall performance of the system, both in terms of energy production and economical gain. The study was performed using the simulation tool TRNSYS based on a model developed in a danish case study. It was performed a parametric analysis on the percentage of share of the different types of solar collectors in the total area. The results given from the simulations have been used to carry out an economic evaluation based on the levelized cost of substituted energy, the annual operation and maintenance costs, and the marginal operational cost difference between a conventional district heating system supplied by a boiler only and a solar assisted district heating system. Based on the results found, it has been proved that a greater proportion of parabolic trough collectors in the solar field contribute to a greater production of thermal energy but also to higher expenses in the economy of the project. The best configuration which balanced these two factors was composed by 70 % of flat plate collectors and 30 % of parabolic trough collectors, based on the total area. The integration of photovoltaic thermal has been demonstrated to be not cost-effective for the studied location compared to the optimized ratio of FPC to PTC, mainly due to the high and uncertain price of the new technology. The use of photovoltaic thermal system is not yet widely developed in projects and there are only a few existing projects in operation today. In the future, the development of photovoltaic thermal in solar assisted district heating projects might have a higher realizable economic potential due to the industry learning curve, but more studies will need to be performed on this. Keywords: District heating; Solar assisted district heating; Hybrid solar system; Flat plate collector; Parabolic trough collector; Photovoltaic thermal collector.

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Acknowledgment

The realization of this thesis work would have not been possible for me without all the support that I have received from several individuals that I have met and have been by my side during my master at Dalarna University, which I would like to thank. I would like to thank Benjamin Ahlgren and Absolicon for sharing the model on TRNSYS and other support for the work. I would like to thank my supervisors Martin Andersen and Puneet Kumar Saini who accepted to work with me for my thesis work. They have always been available for giving me support, help and advice from the first to the last day of my work. They provided me the appropriate knowledge to succeed in my end purpose. I am grateful to my course coordinators Désirée Kroner and Satvasheel Powar, that guided me and my class over the two years of this master at Dalarna University. I would like to thank the team of professors that gave me the proper knowledges to complete this work, but also to be prepared to my professional future. Also, many thanks to all the DU team, that gave me a great support in time of need. Last but not the least, a huge thank you to my family and my boyfriend, that also in this current COVID situation, with the distance that divided us, and all the issues related, has always supported me, and never stopped to believe in me, even when I didn’t believe on it myself. And a warm thank you to all the special people that I have met in my stay at Borlänge, from the “Italian crews” to all the international people that I met and make me realize how different and various and big is the world. I think that without all of them, I never would have got where I am today.

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Contents

1 Introduction .............................................................................................................................. 1 Aims ................................................................................................................................... 5 Overall method ................................................................................................................. 5

2 Background ............................................................................................................................... 7 Solar Energy ...................................................................................................................... 7 Flat Plate Collector – FPC ............................................................................................... 8 Parabolic Trough Collectors – PTC .............................................................................. 10 Photovoltaic Thermal – PVT ......................................................................................... 11 Solar District Heating – SDH ........................................................................................ 12 Thermal energy storage - TES ....................................................................................... 14 Boiler turndown ratio ..................................................................................................... 15

3 Methodology ........................................................................................................................... 16 System boundary conditions .......................................................................................... 17 3.1.1. Economic boundary conditions ............................................................................ 19 Plant configuration.......................................................................................................... 20 3.2.1. System layout .......................................................................................................... 20 3.2.2. Control strategies .................................................................................................... 21 Sizing and specifications ................................................................................................. 22 3.3.1. Size of the plant and Key Performance Indicators (KPI) ................................... 22 3.3.2. Storage tank size ..................................................................................................... 23 3.3.3. Component specifications...................................................................................... 24 3.3.4. Pumps’ sizing .......................................................................................................... 25 Economic analysis ........................................................................................................... 27 3.4.1. Cost of solar plant .................................................................................................. 27 3.4.2. Levelized Cost of substituted Heat (LCOHsubst) .................................................. 27 3.4.3. Sensitivity analysis on collector’s costs ................................................................. 28 3.4.4. Sensitivity analysis on annual boiler maintenance ................................................ 30 3.4.5. Operation and maintenance marginal cost ........................................................... 30 3.4.6. Sensitivity analysis of PVT ratio added into the system ...................................... 31 Delimitations ................................................................................................................... 33

4 Results and discussion............................................................................................................ 35 FPC/PTC parametric analysis ....................................................................................... 35 4.1.1. Economic evaluation on FPC/PTC parametric study ........................................ 37 Optimized solution ......................................................................................................... 41 PVT parametric study ..................................................................................................... 42 4.3.1. Economic evaluation on PVT parametric study .................................................. 44 4.3.2. Combination giving the wanted thermal energy production .............................. 45 4.3.3. Combination giving the electricity consumption ................................................. 46

5 Conclusions ............................................................................................................................. 49

6 Future work ............................................................................................................................ 51

7 References ............................................................................................................................... 52

8 Appendices.............................................................................................................................. 55 Appendix A1 ................................................................................................................... 55 Appendix A2 ................................................................................................................... 57 Appendix A3 ................................................................................................................... 59 Appendix A4 ................................................................................................................... 60 Appendix A5 ................................................................................................................... 61 Appendix A6 ................................................................................................................... 63

Appendix A Checklist before submitting your first draft .................................................. 65

Appendix B Summary of your thesis for the examiner ..................................................... 67

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Abbreviations

Abbreviation Description

DH District Heating

DHW Domestic Hot Water

ETC Evacuated Tube Collector

FPC Flat Plate Collector

HEX Heat Exchanger

IRENA International Renewable Energy Agency

KPI Key Performance Indicators

LFC Linear Fresnel Collectors

LCOE Levelized Cost of Energy

LCOHsubst Levelized Cost of Substituted Heat

MC Marginal Cost

O&M Operation and Maintenance

PF Package Factor

PTC Parabolic Trough Collector

PV Photovoltaic

PVT Photovoltaic/Thermal

ROI Return on Investment

RR From return to return pipe

RS From return to supply pipe

SDH Solar District Heating

SE Solar Energy Yield

SF Solar Fraction

SR From supply to return pipe

SS From supply to supply pipe

TES Thermal Energy Storage

TRNSYS Transient System Simulation Tool

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Nomenclature

Symbol Description Unit

a1 First order heat loss coefficient W/m2K

a2 Second order heat loss coefficient W/m2K2

AFPC Area of flat plate collectors m2

APTC Area of parabolic trough collectors m2

APVT Area of photovoltaic thermal collectors m2

Acoll,HEMSE Estimated total collector area in Hemse plant m2

Acoll,TAARS Total collector area in Taars plant m2

Atot Total collector area m2

𝛽 Collector slope °

Cn Cost for operation and maintenance €

CFPC Specific cost of FPC €/m2

CPTC Specific cost of PTC €/m2

CPVT Specific cost of PVT €/m2

Cstorage Cost for storage including installation €

d Discount rate %

DEPn Asset depreciation €

En Saved final energy Wh

elprice Electricity price €/Wh

elpump Annual pumps electricity consumption Wh

elPVT,t Production of electricity from PVT in the year t Wh

fprice Fuel price €/Wh

𝛾 Collector azimuth angle °

I Incident solar radiation W/m2

I0 Initial investment cost for solar collector system €

Kd Incidence angle modifier for diffuse solar radiation -

Lannual Annual total load Wh

Mboiler Annual cost for maintenance of the boiler on the total operation and maintenance cost

%

MFPC+PTC Annual cost for maintenance of the system with FPC and PTC

€

MFPC+PTC+PVT Annual cost for maintenance of the system with FPC, PTC and PVT

€

�̇�𝑠𝑜𝑙,𝑚𝑎𝑥 Maximum flow rate in solar circuit kg/s

𝜂 Overall efficiency of an energy system %

𝜂𝑏𝑜𝑖𝑙 Boiler efficiency %

𝜂0 Collector efficiency %

Pload,HEMSE Peak power of Hemse plant load W

Pload,TAARS Peak power of Taars plant load W

�̇�𝑎𝑏𝑠 Absorbed power W

�̇�𝑖 Incident solar power W

�̇�𝑙𝑜𝑠𝑠 Overall heat losses W

�̇�𝑡ℎ,𝑙𝑜𝑠𝑠 Thermal heat losses W

�̇�𝑠𝑜𝑙 Useful solar power W

�̇�𝑢 Useful power gain W Rt Revenue from electricity production in the year t €

RV Residual value €

S0 Subsidies and incentives €

Specificel,PVT Specific electricity production from PVT Wh/m2

t Lifetime of the project -

Tamb Ambient temperature °C

Tboil,set Set-point temperature in the boiler °C

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Tcoll Collector temperature °C TFPC,out Outlet temperature from the FPC field °C TPTC,out Outlet temperature from the PTC field °C

Treturn Return temperature °C

Tstore,average Average temperature in the storage tank °C

Tstore,return Temperature to the solar HEX from the load side °C

Tsupply Supply temperature °C

totel Annual electricity consumption of the system Wh

Total_elPVT,t Cumulative sum of the production of electricity from PVT in the year t

Wh

TR Corporate tax rate %

𝜏𝛼 Transmittance-absorptivity factor -

UAloss Overall heat loss coefficient W/K

Vstorage Volume of the storage tank L

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1 Introduction

The climatic change question is today a significant issue that is affecting the global development. In order to slow down the increasing climate change of our planet, renewable energies and energy efficient systems are taking the first place in the energy transition, that, as suggested by the International Renewable Energy Agency (IRENA), it is defined as a process that aims to replace systems “from fossil-based to zero-carbon”, by 2050 [1]. The energy transition has a goal to reduce the CO2 emissions, in this way mitigating the global warming, by delivering at the same time the adequate amount of energy for growth and development. A recent study by IRENA created a decarbonization scenario with the aim to reduce CO2 emissions by 2050 [2]. In the study, a Reference Case and a REmap Case are

compared, as shown in Figure 1-1. The Reference Case takes into account the 75 % of the global energy demand; the REmap case instead is a scenario created by the energy transitions that uses renewable energy and energy efficient systems. As shown in the figure, the yellow line indicates how the energy related CO2 emissions would be if no changes are actuated in the today’s energy system, including energy demand in buildings, transport, district heat, power and industry categories. The green line indicates the same results by reducing the energy use of the various sectors, by energy efficiency measures and technological development. In the results from this study, it has been proven that in a scenario with renewables and energy efficient systems there is a potential reduction of 25.3 Gt per year in CO2 emissions by 2050, of which the 94 % is because of the use of renewable and efficient

systems. Figure 1-1 shows the potential that renewable energies have to reduce more than 90 % the energy related CO2 emission by 2050.

Figure 1-1: Potential reduction of annual energy-related of CO2 emissions by 2050 with permission from

IRENA and described in [2];[3].

Renewable energy is distinguished from conventional sources of energy in that it comes from a sustainable source of energy, but it is intermittent in nature, which means that the source is not available to be used in every moment and there is no human control on that. Among the most popular types of renewable energy sources, - solar, wind energy, geothermal, biomass, hydropower, and biogas are the most well-known. Bringing attention to the solar energy, this kind of energy source currently is widely used due to its availability. As stated in [4], solar technologies have a good competitive costs compared to other systems, they can be adapted in different types of climates around the world and its efficiency continues to increase, due to the fact that its technology is already developed [4].

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The use of solar systems in large-scale project combined with solar district heating (SDH) is now being rapidly developed and common in Europe, particularly in northern countries [5]. District heating (DH), by means of insulated pipe networks and a central generation plant, provides space heating and domestic heat water (DHW) demand for either parts, or all, of a city. [6]. There are two main categories served by DH, according to the International Energy Agency (IEA) reported by [7]: industries and buildings. In the European context, the IEA highlights that the countries that have SDH systems in operation are mainly Denmark, Sweden, Germany and Austria. Furthermore, the “newcomer SDH activities developing” in Europe are Italy, France, Spain and Norway [8]. In a global context, in June 2020 the “top SDH countries” reported were Denmark, China, Germany

and Austria [9], as shown in Figure 1-2. Figure 1-2 shows an analysis of the last decade on leadership in solar district heating in the European context.

Figure 1-2: Global leaders in SDH [9] (open data website)

In the Swedish context, the district heating systems were first installed in 1948, and are today present in almost all urban areas [10]. For this reason, the expertise in such a systems is really widespread, and following the national statistics around 500 systems are counted in the whole country. Thanks to this large growth, in Sweden the use of fossil fuel is becoming more and more uncommon, replaced in large proportion by renewable and recycled heat. As it can be

seen in Figure 1-3, where the trend of market share for the heat supply in Sweden from 1960 to 2014 is illustrated, the black line of fuel oil heat source had a considerable reduction that started around 1970. A different evolution instead has been followed in district heating, indicated with the red line. From the 1960s, its development had a quasi-linear growth, achieving the leader position in the few last years, with a market share of 55 % in 2014 (this value is slightly lower in reality because the energy used as backup in DH is not taken into

account in this figure). Figure 1-3 shows the evolution from 1960s to 2014 in the energy market share for the residential heat distribution in Sweden.

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Figure 1-3: Market share for heat supply in Sweden from 1960 to 2014, that highlights the rapid growth

of district heating systems [10] (open access article under the CC BY license)

The operating temperature ranges of district heating systems are usually high. For district heating in Sweden, the average temperatures of supply and return are 86°C for supply and 47°C for return [10]. The high temperatures levels generate some disadvantages in the system, as more distribution losses in the network pipelines, expensive materials needed to withstand the high temperature and more insulation to reduce losses. The results of the disadvantages due to the high temperature implies a reduction in the overall efficiency of district heating. Due to this, future DH systems aim to increase energy efficiency and integration of renewable energy by reducing the operating temperatures in the DH network [11]. In future, there will be another standard for low temperature DH which will enable more renewables usage by solar systems, but until this point is still not reached, there will be a transition period where the current systems will be used with higher temperatures. By integration of renewable energy, the dependence from fossil-fuel based sources as oil, coal or natural gas in the district heating supply can be greatly reduced. A potential renewable source is the solar radiation, which introduces solar thermal energy system. Furthermore, in solar thermal system configuration, it is usually necessary to integrate a thermal energy storage due to the mismatch between heating demand and available solar radiation. In that way, it is possible to store the surplus, using it for example during the peak periods, when the cost of energy is higher or during periods when no solar radiation in available. The most common type of thermal storage is an insulated tank, and it is often place inside the heating plant [12]. Standard solar district heating systems are usually coupled with ground-mounted flat plate collectors [12]. The flat plate collectors (FPC) can be a suitable solar technology in district heating applications because they work in the low-temperature ranges (<100°C), However, a drawback of flat plate collectors is related to the reduced efficiency with increasing temperature. As already mentioned, district heating systems have high temperature ranges, which results as an issue for solar energy systems. The efficiency of flat plate collectors drops significantly with the rise of temperature in a district heating system (>70°C), and for this reason, much research has been focused on finding a way to resolve this disadvantage. One possible answer to the problem could be the double glazed FPC collector, but with this solution the cost of the collector increases due to the additional glass, and one consequence is that the optical efficiency will be reduced. Another way to solve this problem could be to couple the low temperature operation system together with a solar technology that keeps its efficiency at higher temperature levels, thus forming a hybrid system. A suitable example of hybrid solar systems is FPC with parabolic trough collector (PTC). One study [13] found

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that the focal line or the absorber tube of PTC can work in normal conditions up to high temperatures, as 350-400°C. PTC collectors can achieve relatively higher temperatures without significant drop in the efficiency compared to FPC and therefore, combining FPC and PTC in a hybrid system allows the FPC to reduce the mean operational temperature in FPC collector, which reduce the heat losses, and thus increase the specific collector production. For this reason, hybrid systems in solar district heating have the opportunity to give better overall performance than systems using purely FPC. One hybrid system, consisting of both FPC and PTC has been built in Taars, Denmark and it is in operation since 2015, shown in Figure 1-4. The solar plant system is a hybrid system, that consists of FPCs and PTCs in series. The hybrid solutions have been chosen in order to improve the efficiency of the plant and to use the two different solar collectors both in their maximum efficiency temperature ranges. This system has been used as a basis for the research work presented in the following chapters. Figure 1-4 shows the system layout for the solar district heating plant studied in Taars, Denmark.

Figure 1-4: Simplified layout of SDH plant in Taars, Denmark (by permission of Elsevier Copyright

Clearance Center) [5]

This thesis is based on a previous work done on a solar district heating [14], in which the Taars SDH plant (see Figure 1-4) was modelled in TRNSYS (Transient System Simulation Tool) [15]. The subject of the research was to find out if, in a solar district heating system, a hybrid combination of solar flat plate collectors (FPC) and parabolic trough collectors (PTC) could give a better result instead of using only FPC. FPC is used because it is a standard solar thermal collector, it is a predominant technology in Europe, and PTC is a widely used solar concentrating technology [16]. In the past work, it was found that a higher overall system efficiency can be achieved by combining FPC and PTC such that each technology work in the temperature range it excels. Using a series combination, the FPC can work in a lower temperature range, where it has a higher efficiency, whereas the PTC can work in a higher temperature range and still maintain a high efficiency [14]. It was demonstrated by the study that it is possible to get a better solution in terms of production, efficiency and costs in a systems configuration when using a specific proportion of the two types of collectors. In the optimization study of the system in Taars, the final optimum configuration found was with 74 % FPC and 26 % PTC [5].

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In the east coast of Sweden, in Hemse, on the Swedish island Gotland, a district heating was studied to evaluate the feasibility of the integration of solar heating. The existent district heating is using for residential purpose, to serve the heating in the city. The current district heating delivers yearly 11.5 GWh. This system was used as a Swedish case study to verify if the plant in Taars could be applicable in other location. In section 1.1, the aims of the project are explained.

Aims

The primary aim of this thesis was to evaluate if the same positive effects and economic feasibility obtained in the Taars SDH plant could be achieved when changing the boundary conditions of the system to represent those in Sweden, in Hemse, a town in Gotland, a Swedish island. The work focused on the achievement of the best combination in ratio of FPC and PTC in a Swedish case study, as previously done in the Danish case, compared to a reference case system with only FPC integrated. The objective of the work was to perform simulations by means of TRNSYS tool, using one of the models previously built for the hybrid plant. The model provided is the hybrid coupling of the two different solar collectors in the solar district heating: FPC (single-glazed in series) and PTC. From the model, it was possible to select the desired areas of the different collectors [14]. Integration and control strategies were studied and implemented in the system. The secondary aim of this thesis was to determine if another type of hybrid combination could lead to improved performance of the heating plant, by substituting a share of the FPC by photovoltaic thermal (PVT) collectors. PVT is an emerging solar technology that produces both thermal and electrical energy and its integration could have advantages related to added production of electricity and reduction of operational costs. Nowadays, there are no previous study which evaluate a PVT integrated in a SDH system. The third aim of this thesis was to combine the results from working on the primary and secondary aims, to decide what proportions of FPC, PTC and PVT is the best option for the particular case study from a techno-economic point of view.

Overall method

In this section, the different steps of methodology are explained.

In Figure 1-5, the main steps for the overall process are outlined in a diagram, which are following described more in specific. A literature review was conducted to establish an analysis of DH, various system technologies, storage types, with a focus on the novelty of PVT collector. Simulations were conducted based on a previously built TRNSYS model for the hybrid solar thermal system in Taars, Denmark [14]. A TRNSYS model of a boiler central was made for the Swedish case study of Hemse. Parametric simulations on the specific ratio of FPC/PTC were performed, as well as parametric simulations of replacement of FPC by PVT and additions of PVT to the FPC/PTC hybrid system by increasing total collector area. At the end of each part of simulation assessment, an economic sensitivity analysis of the final solution was modelled, based on simulation results. The sensitivity analysis was based on the levelized cost of substituted heat (LCOHsubs). When the electrical component (the PVT) was

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added to the system, the new levelized cost of substituted energy was calculated and, in this case, the economical revenue due to the added production of electricity from PVT was calculated. The economic evaluation was modelled on the Swedish economic conditions that will be more deeply explained in a next section dedicated in Chapter 3. For the simulation, the software TRNSYS was used. This tool is suitable for this work because it performs dynamic simulations for the evaluation of the performance of thermal and electrical energy systems.

Figure 1-5: Figure showing the overall process followed in the project work

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2 Background

In this section, the basic knowledge of the solar energy systems will be explained. The technologies that are present in the project will be analysed. In particular, the operations conditions, the pros and cons by using them, how they can be combined one to each other in order to have better performance of the system.

Solar Energy

In this section will be described the main characteristics of sun and solar radiation and how solar energy systems work. The energy that reaches the earth is defined by the solar constant, which is described as the energy of sun per unit time on a unit area perpendicular to the direction of the radiation outside the atmosphere. This number has been demonstrated to be around 1367 W/m2 [17]. The intensity of the sun radiation at ground level is smaller than the solar constant and it is variable due to attenuations in the atmosphere. During a year, there are variation of extra-terrestrial solar radiation depending on the time of the year and the earth-sun distance. At ground level, the solar radiation could be described as the sum of two different parts: direct and diffuse radiation that form the global radiation. The direct (or beam) radiation is the part of solar radiation received by the sun that has not been scattered by the atmosphere. The diffuse radiation is the part of solar radiation given by the result of the scattering effect happening into the air. The scattering of solar radiation occurs when there is a deviation of the radiation in other directions. Another important factor to consider is the turbidity of the atmosphere. The turbidity is a quantitative factor that indicates how much the atmosphere is reduced in clearness of air resulting from the scattering of light by particles in the air as water droplets, dust, pollution and from absorption of light by water vapor. The higher this factor is, the higher is the scattering of solar radiation and by consequence the lower is the direct solar radiation. This means that the turbidity factor increases the diffuse solar radiation.

Figure 2-1 shows a geometrical framework for definition of the sun’s radiation in three dimensions. To calculate the total beam radiation coming to a particular surface, a set of angles are

defined: the latitude 𝜙, which indicates the location north or south of the equator; the

declination 𝛿, which is the sun position at solar noon; the slope 𝛽, which is the angle formed

by the plane of the surface and the horizontal; the angle of incidence 𝜃, which is the angle

formed by the sun radiation and the normal to the surface; the surface azimuth angle 𝛾, which is the horizontal angle between the projection of the normal to the horizontal surface and the north-south direction [17].

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Figure 2-1: Figure describing the direction of the beam radiation [17]

There are some differences on how the FPC, PTC and PVT interact and utilize the solar radiation to produce energy. FPC and PVT both work with beam and diffuse radiation, known as global radiation. The difference between these two is that, in PVT, the part of PV that produce electricity has a different spectral sensitivity which aims to reach the photons in the specific band gap where the electricity conversion takes place to achieve a high number of electron-hole pairs. Instead, the other part of PVT aims to the maximum absorption. Differently, PTC is a concentrating solar thermal system that uses only beam radiation. For this reason, to maximize the solar energy production, PTCs need to have low values of diffuse radiation and of turbidity factor. Solar collectors can have a tracking system to monitor the sun movements and increase the total incident beam radiation. The tracking can be on a single axis (usually E-W or N-S) or on two axes. Concentrating solar thermal systems can only concentrate the direct beam radiation. Due to this, concentrating collectors have significant reductions in output when share of diffuse radiation is high. When designing a solar system, it is also important to take into account the shading losses. There are three different types of losses due to the shading: shading from near obstructions, as trees, buildings; shading from a near row of collectors; and shading by overhangs and wingwalls [17]. Big projects that are developed in large lands usually don’t have the first type of shading. In order to reduce the shading caused by the near rows, the pitch distance is calculated in order to optimize the configuration. The pitch distance is the distance between rows calculated in order to avoid the shading between near rows of collector and it defines the optimum array spacing in the solar plant.

Flat Plate Collector – FPC

Solar district heating systems generally use flat plate collectors (more than 90 %) [18]. FPC are used because they give high efficiency and reliability, they have low installations costs and long lifetime. The installation of FPCs in district heating plants is cost effective and faster due to the fact that FPCs have a relatively high aperture areas [19]. In district heating applications, flat plate collectors have a larger area (10 to 15 m2) compared to small scale projects [20]. FPCs use both beam and diffuse radiation and they don’t need tracking. Domestic hot water, space heating and air conditioning and industrial process heat are the most widely applications of FPCs [17].

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Flat plate collector consists of a insulated metal box, covered by the glazing (usually glass or plastic) and an absorber plate, dark-colored to enhance the absorption of solar radiation [21]. Aluminum is commonly used as absorber material, because it is relatively cheap and easier to deal with [20]. The absorber plate, that is heated up when solar radiation is available, transfer the absorbed energy to the fluid entered in the inlet pipe. When the fluid which flows in the pipes has gained the energy, the liquid outlet subsequently brings energy to the final systems.

The overall performance of a flat plate collector is defined as the ratio between the useful

gain (�̇�𝑢) and the incident solar power (�̇�𝑖) in the given total area of the collectors. The incidence solar radiation and the absorbed energy on the absorber plate are not the same

because a part of the radiation is reflected to the sky and a part is reflected by the glazing. 𝐼 defines the incident solar radiation. The useful heat is obtained by the difference between the heat absorbed by the absorber

(�̇�𝑎𝑏𝑠) and the rate of heat losses (�̇�𝑙𝑜𝑠𝑠). The heat losses are dependent on the collector overall heat loss coefficient Uloss and the temperature difference between the air temperature Tamb and the collector temperature Tcoll. The heat absorbed by the collector is obtained using the (𝜏𝛼) factor, that takes into account the transmittance of the cover and the absorptivity of the absorber. The following Equation 2.1-2.5 show the process to calculate the useful heat of a flat plate collector, as described:

�̇�𝑖 = 𝐼 𝐴𝑡𝑜𝑡 Equation 2.1

�̇�𝑎𝑏𝑠 = 𝐼 (𝜏𝛼) 𝐴𝑡𝑜𝑡 Equation 2.2

�̇�𝑙𝑜𝑠𝑠 = 𝑈𝑙𝑜𝑠𝑠 𝐴𝑡𝑜𝑡 (𝑇𝑐𝑜𝑙𝑙−𝑇𝑎𝑚𝑏) Equation 2.3

�̇�𝑢 = �̇�𝑎𝑏𝑠 − �̇�𝑙𝑜𝑠𝑠 Equation 2.4

𝜂 =�̇�𝑢𝐼 𝐴𝑡𝑜𝑡⁄ Equation 2.5

The efficiency of flat plate collectors depends mainly on two factors: the heat transfer between the absorber plate and the water, and the overall top heat transfer loss coefficient, on the top side of the collector. It was found that the losses on the top of the collector account for about 75 % on the total heat losses [22]. In order to reduce the losses on the top of the collector, double-glazed collectors are used rather than single-glazed collectors. At the same mean operation temperature (75°C in this case), collector with double-glazing have about 20 % higher yield [14]. In a study carried out in [22], the different performances between single- and double-glaze flat plate collectors were compared. Some important results were found out, as following. In same conditions (same areas and same solar radiation), the efficiency obtained were 12 % and 55 % for single- and double-glazing collector respectively. The top heat loss coefficient was reduced in case of double-glazing. Furthermore, the temperature difference of the outlet temperature of double-glazing system is around 10-15°C higher compared to the single-glazing system. The overall result of these result could significantly improve the efficiency of the solar collectors, giving a better energy output.

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Parabolic Trough Collectors – PTC

It is proven that FPCs and PTCs get better efficiencies at different ranges of temperature. In particular, the FPC has its best performance in an indicative temperature range of 30-80°C and its efficiency starts to drop at high temperatures. Instead, the PTC gives the best performance at high temperature ranges, indicative temperature range 60-300°C [23]. In this way, a smart hybrid system can be set up in order to run the collectors in the temperature range where they excel, putting them in series. PTC belongs to the class of concentrating collectors. Concentrating collectors can deliver energy at higher temperature ranges compared to flat plate collectors. In this type of solar systems an optical device is placed between the solar radiation and an absorber surface where the solar energy is concentrated and transferred to the working fluid. The efficiency of a

concentrator system (𝜂) depends on temperature (T) and geometrical concentration of solar radiation (C), as shown in Equation 2.6. The geometrical concentration ratio C is defined as the ratio between the aperture area (area defined by the aperture plane) and the absorber area. The concentrator solar systems have a main limitation: only direct solar radiation can be concentrated [24].

𝜂 = 𝑓(𝑇, 𝐶) Equation 2.6 There are two categories of concentrating collectors: point-focus concentrators and line-focus concentrators. In line-focus solar concentrators, the direct solar radiation is concentrated and collected onto a linear-receiver. In this category there are PTC and Linear Fresnel Collectors (LFC). In point-focus concentrators, the directed solar radiation is concentrated and collected onto a focal point. Heliostats plants and Dish-Stirling technology fall into this last category. PTCs concentrate solar radiation in the focal line through a parabolic collector. PTC analysed in this study consists of three main components: a receiver, a concentrator, and a cover. The receiver, also called the absorber, is a tube located in the focal line which absorbs the concentrated solar energy and transfers it to the working fluid. This part of the system is fixed permanently in the focus of the concentrator. The cover is used as protection for the absorber tube, aiming to reduce at minimum the heat losses through the ambient [13]. The concentrator is a reflector with proper shape and proper geometry (a parabola) that must reflect the solar radiation onto the receiver tube. The concentrator has some specific properties related in order to give the best efficiency: the proper shape to achieve the proper concentration intercept factor; a high solar specular reflectance; soiling level at minimum possible, that means that cleaning it is a very important factor to get high efficiency of the systems; and high durability, meaning that a reflective surface resistant to environmental

stresses is requested. In Figure 2-2, the schematic layout of a parabolic trough collector is shown.

11

Figure 2-2: Schematic drawing of PTC (by permission of Elsevier Copyright Clearance Center) [25]

The parabola is moved during the full day with a tracking system, by means of a drive unit. The system tracks the sun movement along the day, from sunrise to sunset. The sun tracking system is needed because the concentrator has to be oriented in the right direction at every sun movement in order to concentrate all the solar radiation possible.

The overall efficiency of a parabolic trough collector (𝜂) is given by the ratio of the useful

thermal power transferred in the receiver to the fluid and the useful solar power in the aperture area. There are two categories of losses that can reduce the overall efficiency: the optical losses and the thermal losses. In fact, the useful thermal power is derived by the optical and thermal influences, as shown in Equation 2.7:

𝜂 =�̇�𝑢

�̇�𝑠𝑜𝑙

⁄ = 𝜂𝑜𝑝𝑡 −�̇�𝑡ℎ,𝑙𝑜𝑠𝑠

�̇�𝑠𝑜𝑙

⁄ Equation 2.7

Where �̇�𝑢 is the useful gain, �̇�𝑠𝑜𝑙 is the useful solar power, �̇�𝑡ℎ,𝑙𝑜𝑠𝑠 are the thermal losses and

𝜂𝑜𝑝𝑡 is the optical efficiency of the collector. The optical efficiency depends on the properties

of the reflector, as reflectance, intercept factor, transmittance and absorptance. The parameter that has to be maximized in this system is the reflectance and the factors that can reduce this parameter are high absorptance values and the phenomena of dispersion (or scattering) of solar radiation, due to atmospheric attenuations. The scattering of light occurs when the solar rays “get deviated from its straight path on striking an obstacle like dust or gas molecules, water vapours” [26]. The thermal losses in PTC are driven by the mechanisms of irradiation, convection, and conduction. In the absorber there are losses by radiation and convection transferred in the glass cover in the mode of conduction and losses by conduction trough the receiver support. And finally, through the ambient there are losses of radiation and convection. Solutions to reduce at minimum possible thermal losses could be to use a proper insulation to reduce conduction; to use noble gases and proper vacuum conditions to reduce convection; to use low emittance coating to reduce radiation.

Photovoltaic Thermal – PVT

The photovoltaic thermal system (PVT) is a (novel, compared to FPC and PTC) collector technology that allows a simultaneous production of heat and electricity using a single module. PVT is introduced in this project in order to make a techno-economic feasibility

12

study of a different hybrid solar system (with PTC and/or FPC) for the solar district heating system studied in this thesis. The electricity produced by PVT can be an added benefit for the DH system, as it can be sent directly to the grid, or it can be used locally by electrical equipment. The key principle of the PVT collectors is based on the re-use of the dissipated heat from a solar photovoltaic (PV) cell for thermal heating production. A PVT collector is a combination of a solar PV cell and a solar thermal component that results in a mixed production of electricity and heat. Today, photovoltaic cells available on the market have efficiency in the range from 14 % to 17 %, depending on the working conditions [27]. That means that the majority of the incident solar energy is not utilized, but instead dissipated. A significant problem when working with photovoltaic cells are the high temperatures. When high temperatures are reached, the photons that reach the cell have a longer wavelength that doesn’t fall in the specific energy band gap where the electricity conversion takes place. Thus, the energy not converted into electricity is dissipated as excess heat [28]. That causes a significant reduction on the efficiency of the system due to the reduction on power output and an acceleration on the degradation of the cell. One possible way in order to reduce this issue, could be cooling down the cell with a fluid, as water, and re-using the heat extracted by the cooling. Indeed, this is the principle of combining a thermal system in the cell, by obtaining a PVT cell. A PVT collector basically consists of an encapsulated PV cell, a glass cover, an absorber plate

and tube exchanger, as displayed in Figure 2-3. The PV cell is fixed on the metallic part of the absorber plate, and it is used as the absorber part of the collector [29]. The excess heat from the PV is dissipated to the absorber plate. The energy absorbed by the absorber plate is then transferred to the fluid into the tubes, as in a liquid flat plate collector. The designs of PVTs are various, depending on the type of fluid used (air-type or water-type) and on the type of design of channel used in the cross-longitudinal section. Water-type systems can have a sheet and tube design, a box channel design, a channel above or below the PV [28].

Figure 2-3: Figure showing the Cross section of a PVT collector (by permission of Elsevier Copyright

Clearance Center) [29]

In several studies, the performance of PVT collector was analysed. The efficiency of PVT collector depends on design and climatic factors, but also on the PV module characteristics, as packing factor (PF), ohmic losses between near cells and temperature of the module. It was proven that the thermal efficiency achieved by the working fluid can reach around the 42 % [29]. The combined thermal and electrical efficiency of the collector was found by Bergene et al. [30] by developing a physical model that made prediction of the efficiency of the hybrid collector. The total efficiency of the systems is in the range of 60 % to 80 %, the lowest when a low-quality collector is used.

Solar District Heating – SDH

District heating is a system that, by means of insulated pipe networks, distributes heating that has been generated in a central plant in a significant part of a town or in an entire town for

13

residential or commercial heating demand such as space heating and DHW usage. In Europe, the heating request is fulfilled around 9 % by DH systems [20]. DH networks combined with solar thermal energy systems have been very successfully proved. Solar district heating is therefore defined: district heating systems with solar energy as “a vital energy source”. The state-of-art of district heating started between 1930s and 1970s in USA, Germany, and Russia, due to oil crises in these years, with significant increasing in fuel prices. The interest in district heating was therefore born due to its high advantage to have lower heating costs in moments when the international costs for fuels were high. Moreover, the interest in using renewable energy in district heating developed. Today, the main district heating operating in the world are in Russia, China, USA and more specifically in Europe the majors are in Germany, Nordic countries as Denmark, Sweden and Finland, and Poland. The total number of plants in operations today is around 80 000, of which around 6 000 are in Europe. The main user categories of district heating are for industries and residential buildings in major part, and a small proportion for the service sector. In 2014, the proportion registered for the utilisation of district heating were of 51 % for the residential sector, 45 % for the industries sector and the remaining 4 % for service sector and other applications [31]. Solar assisted district heating (SDH) can be combined with a thermal energy storage to produce several advantages compared to the conventional DH system, as reducing the operating costs, prioritizing the usage of renewable and local sources, and consequently reducing the greenhouse emissions. The three following major advantages of SDH were highlighted in a study: high efficiency, high flexibility, and management convenience. It has been proved that seasonal COP of the integrated solar thermal space heating system compared to use of conventional heat sources was much higher. The higher flexibility can be achieved when the energy storage is integrated, by shifting the use of energy in a certain period, for example during peak periods when the electricity prices are high. The management of DH plants follows the “community-based management approach”, that aims to distribute the heating in a “unified manner” [18]. In a study, different four combinations for the connections between the solar collector field and the district heating network have been identified: from supply to supply (SS); from return to return (RR); from supply to return (SR) and from return to supply (RS). The solution that was found to be the more efficiency in terms of energy was with RR connection; but the less invasive, easier and cheaper solution was found to be the RS connection [32]. Different typologies of integration of solar system into a district heating are present today. The main difference is between centralized, decentralized, and distributed systems. All the options may or may not include a storage capability [33]. A centralized SDH plant usually uses a central storage and a central solar collector field, placed near the heating plant. In the heating plant is placed also an auxiliary heating system to act as a backup system when solar energy is not enough or is not available to fulfil the load. The supply and the return pipes create the district heating network, connected directly to the building’s loads [20]. Instead, in a decentralized SDH plant, the solar collector field is distributed, meaning that the solar system is placed near the consumer in the building or in the block of buildings. The main difference is that in this last case, the collector field is not located in a single location supplying the heating to the district heating system, but it is distributed [33]. The most type of collectors used in solar district heating are mainly FPC and evacuated tube collectors (ETC). Also concentrating collectors as PTC or Linear Fresnel collectors (LFC) are used, but they are less used because the large part of annual diffuse radiation cannot be used. In some cases it is chosen to use ETC since they have a lower price [34].

14

Compared to the conventional DH, the solar assisted DH have a great potential. Starting from the environmental benefits, SDH can reduce harmful emission and it can be considered as an appropriate replacement for the fossil fuels [35]. Moreover, it can be as well beneficial for the ecological wellbeing. By using SDH, the quality of air at local level is enhanced. Another important benefit that SDH can give is a potential savings in the energy costs, as well as a development at a local level. Local jobs are created for manufacturing, installation, commercialisation, maintenance [36]. The whole thing can thus help in the development of local economies.

Thermal energy storage - TES

Thermal energy storages are introduced in projects in order to improve the thermal energy management in energy production systems. In solar thermal energy systems, the energy storage can improve the economics, the strategy, and the environment. It can improve the economy of the project because it permits to use the surplus of solar energy produced, by giving revenues to the system; it can improve the energy usage strategy when there is the load demand to fulfil by using the stored energy; and it can enhance the environment impact because the stored renewable energy is used instead of a conventional energy system. The main goal of heat storages in solar energy systems is to accumulate the energy surplus produced when there is solar radiation, use it during night or winter months when the solar radiation is not available or not enough to fulfil the load, avoiding the mismatch between production and the demand. In that way, the usage of backup system is reduced to the absolute minimum. In large scale system as district heating systems, TES are largely used. They are classified into short-term (or diurnal), mid-term and long-term (or seasonal) storages [37]. The main parameter between the different types of TES is the cycle length. With a diurnal storage a cycle length is of one day up to maximum two days. It means that the thermal energy demand and the discontinuous solar energy production could be matched by the storage for several hours up to few days. Otherwise in long-term seasonal storages it is possible to store the energy for several weeks or months, in order to provide the energy needed in autumn and winter, provided and stored during summer. Seasonal storages are used primarily to achieve high shares of solar fractions in the systems. In district heating systems with seasonal storages 45% - 55 % of SF can be achieved [38]. In systems with diurnal storages, the SF that can be

reached is in the 5% - 20 % range. In Figure 2-4, a SDH heating by using a short-term TES is displayed.

Figure 2-4: Figure showing the schematic of SDH with short-term storage by International Energy Agency

- Task 55 [37] (open access data)

15

A significant difference between small diurnal storages and large seasonal storages is that the first one can work at the same pressure of the network, and that allows to reach temperatures above 100°C. Differently, the large storages needs to work at atmospheric pressure [37]. The solar yield (SE) of the entire system between using diurnal or seasonal storage varies due to the higher losses in seasonal storages. In seasonal storages, the thermal losses increase, and the SE compared to a system with diurnal storages is reduced by 10% - 30 %, depending on the size of the storage [38]. One of the main difficult points in solar heating systems is the mismatch of demand and availability. During cold seasons, when there is the great part of heating demand, there is not enough solar energy availability. In contrast, during summer when the heating demand is almost zero, there is a high solar resource availability. The seasonal storage aims to overcome

this issue. As shown in Figure 2-5, the excess radiation (or energy surplus) is accumulated and stored during the warm season and used during cold season in the part of consumption not covered by the irradiation line, the called excess consumption.

Figure 2-5: Figure showing a typical seasonal storage operation [39] (ESES course compendium)

Boiler turndown ratio

The meaning of the turndown ratio of the boiler is introduced in this chapter because it is a factor considered later in the project. The boiler turndown is the ratio between the boiler’s maximum and minimum output. In systems where the boilers are required to operate at large range of capacities, it is really important to set a turndown ratio. When a turndown ratio is set, the boiler can handle better the potential fluctuations of the load. The turndown ratio indicates the minimum value of output that the boiler can have before turning off. For example, depending on the design of the burner a boiler can have a turndown ratio of 5:1, which means that the full capacity of 100 % is divided by 5 and then the minimum operating load is of 20 %. In the same way, a boiler that has a turndown ratio of 10:1 has a minimum operating load of 10 % (full capacity divided by 10), and so on [40].

16

3 Methodology

In this chapter, the overall process followed in the project research is described in detail for

each part of the system. In Figure 3-1, the diagram shows the main steps of the work. There are two main different approaches used in the work: the simulation part on the model on TRNSYS and the elaboration of data on Excel. In the initial part of the project the simulations were focused on the system with FPC and PTC. Once the model is adapted to the case study, by reducing the system according to the load and by using the weather data of the location, a parametric analysis on the ratio of FPC and PTC was carried on TRNSYS, where collector area ratio was changed based on specific FPC/PTC ratio and optimized with considering the specific collector production. In the diagram, “combinations with best results” indicates the step in which the best ratio (called combination in this case) was identified to proceed in the following steps. The “best” combination was decided based on

economic analysis and iterations in the simulations. When the data were extrapolated from the simulations, the elaboration of the results in Excel, including the economic calculations, enabled to find the optimal configuration for FPC and PTC. Starting from the optimal solution found, the second part including PVT was carried on. In this case too, a parametric analysis on the ratio of PVT added in the system was done explained in more detail in section 3.5.6. Including the economic analysis in Excel, the final optimal configuration was found. The final best configuration found was based both on the energy savings and the overall economical savings.

17

Figure 3-1: Figure showing the process for the methodology of the project

System boundary conditions

The simulations were conducted using climate data from Meteonorm [41] for the Swedish island of Gotland, located on the east coast of Sweden. The load profile used as input to the simulation model is taken from the Hemse district heating system for the year 2015. The annual heat demand according to this load profile was 11.5 GWh and the temporal resolution was approximately 2.5-hours. For the purpose of this project, the data values were processed in Excel to construct a profile with higher temporal resolution of 3 min and used for the TRNSYS input data.

In Figure 3-2, the load profile is displayed with 1-hour time resolution. The peak power demand in the system is roughly of 3 MW. As expected, in the summer period from June to September the load profile has low values, with values ranging from 0.4 to 1.5 MW. During the coldest periods instead, the load profile varies between 2 MW and 3 MW.

in

in

18

Figure 3-2: Annual load profile for DH in Hemse, Gotland

During the coldest period, the temperature range varies between 80° C to 85° C in the supply line and between 45° C to 50° C in the return line. During the summer period, more elevated temperatures are reached, around 95° C (with peak values over 100° C) for the supply line

and 60° C average temperatures for the return line. In Figure 3-3, the supply and return temperature for the heating plant in Hemse is shown. The reason for the elevated flow supply temperature during summer (and consequently also higher return temperature) is due to the minimum turndown ratio of the oversized boiler.

0

0.5

1

1.5

2

2.5

3

3.5

Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15

PO

WE

R [M

W]

TIME

19

Figure 3-3: Load supply-return temperature from load data in Hemse, Gotland

3.1.1. Economic boundary conditions

The economic evaluation is done for a short-term system lifetime (15 years) and for long-term system lifetime (30 years). The short timeframe of 15 years is done because it is widely used in the industry field for systems evaluations. The warranty of a solar collector is usually set to 25 years, but if the collector is well maintained, the life time can be extended of some years. It is assumed that the solar plant is well maintained in the project, which means that a routine maintenance check is provided, and the collectors are kept cleaned from dust, sand, debris, snow, and any kind of factor that could decrease the energy output. Furthermore, the warranty of 25 years doesn’t mean that they stop producing after that timeframe, but after that timeframe the efficiency could start to drop. For this reason, a long timeframe of 30 years is chosen.

The fuel price and the electricity prices used in the economic analysis are listed on Table 3-1, based on current value for Sweden.

Table 3-1: Energy prices in Sweden

Fuel price [42] 30.20 €/MWh

Electricity price [43] 21.19 €/MWh

In Table 3-2, the calculation for maintenance of the solar system with FPC and PTC, and FPC, PTC, PVT respectively are shown.

Table 3-2: Maintenance costs for solar collectors

FPC 0.27 × 𝐴𝐹𝑃𝐶 €

PTC 𝐶𝑃𝑇𝐶 × 𝐴𝑃𝑇𝐶 × 0.008 €

PVT 𝐶𝑃𝑉𝑇 × 𝐴𝑃𝑉𝑇 × 0.005 €

0

20

40

60

80

100

120

140

Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15

TE

MP

EA

RT

UR

E[°

C]

TIME

Supply temperature Return Temperature

20

Where AFPC, APTC, APVT indicate the collectors area respectively for FPC, PTC and PVT in m2; CPTC, CPVT indicate the specific cost respectively for PTC and PVT in €/m2. In Equation 3.1-3.2, the calculation done for the maintenance of the solar system with FPC/PTC and FPC/PTC/PVT respectively is shown.

𝑀𝐹𝑃𝐶+𝑃𝑇𝐶 = (0.27 𝐴𝐹𝑃𝐶) + (𝐶𝑃𝑇𝐶 𝐴𝑃𝑇𝐶 0.008) Equation 3.1

𝑀𝐹𝑃𝐶+𝑃𝑇𝐶+𝑃𝑉𝑇 = (0.27 𝐴𝐹𝑃𝐶) + (𝐶𝑃𝑇𝐶 𝐴𝑃𝑇𝐶 0.008) + (𝐶𝑃𝑉𝑇 𝐴𝑃𝑉𝑇 0.005) Equation 3.2

Plant configuration

In this section, the plant’s configuration is described, as the system layout and the control strategies included in the system.

3.2.1. System layout

As explained in the introduction of the thesis, the aim in this project is to simulate the already built model on TRNSYS [14], adapting it for a Swedish case study in Hemse.

Figure 3-4 shows the finalized layout for the system. The model is composed by two main parts: solar part and boiler part. The solar side includes the solar circuit within the solar collectors and the solar heat exchanger that transfers the solar heat production to the storage tank and later to the load. In the solar circuit the flowing fluid is glycol mixture water. In the first part of the work, the solar collector included are FPC and PTC. In further steps of the work PVT collectors will also be included in the solar circuit. The boiler side includes the circuit to the load, the thermal energy storage, the boiler and the boiler side heat exchanger. The storage used is a mixed vertical tank. The boiler circuit heat transfer medium is water.

In Table 3-3, the properties of the glycol mixture and water used for the calculations are

shown. In the first column, 𝜌 refers to the density of the fluid and cp refers to the specific heat capacity. The values refer to conditions at 25°C. This reference conditions are used for the sizing of the system because they are in the average values for temperature in the system throughout the year.

Table 3-3: Properties for heat transfer medium used in the circuits of the system

𝜌 [kg/m3] cp [kJ/kg K]

Glycol mixture 1015 3.94

Water 997 4.19

21

Figure 3-4: Finalized hybrid system layout

In Table 3-4, the number of each component indicated in the system layout are specified.

Table 3-4: Name of each numerated component in the system layout in Figure 3-4

N° Component’s name

1. FPCs

2. PTCs

3. Bypass PTC valve

4. Pre-heat valve

5. Solar heat exchanger

6. Solar side pump

7. Bypass FPC valve

8. Charge side pump

9. Thermal energy storage

10. Boiler

11. Boiler side heat exchanger

12. Boiler side pump

13. Bypass TES valve

3.2.2. Control strategies

In the solar side, four valves’ signals are used. In Table 3-5, the control strategies used in the system are summarized and successively described. The number of components refers to the

schematic layout in Figure 3-4.

cSolar out

Solar in

Supply

Return

SOLAR SIDE BOILER SIDE

c

1

2

3

4

6

7

8

9 10

11

1213

5

22

Table 3-5: Description of the control strategies used in the system

Component IF THEN OTHERWISE

n.4 Thybrid,out > Tstore,return Fluid to solar HEX By-pass solar HEX

n.3 Condition 1: Ebalance, PTC > (Tm,PTC – Tamb) Condition 2: TPTC,out > Tstore,return

Fluid to PTC field By-pass PTC field

n.7 Condition 1: Ebalance,FPC > (Tm,FPC – Tamb) Condition 2: TFPC,out > Tstore,return

Fluid to FPC field By-pass FPC field

n.13 Tstore,average < Tboil,set = Tsupply + 5°C Fluid to TES By-pass TES

The component n°4 (pre-heat valve) is used to allow the preheating of the pipes before sending the flow from the solar to the solar heat exchanger. This valve is controlled as follow: if the outlet temperature from the hybrid solar collector field is greater than the inlet temperature to the solar HEX from the load side, the fluid is sent to the solar HEX. Otherwise, the solar HEX is by-passed. The component n°3 (by-pass PTC) and the component n°7 (by-pass FPC) are used to by-pass the collectors’ fields individually when the following conditions are not met:

- the energy balance in the collectors must be positive. The energy balance is positive when it is greater than the difference between the operating temperature in the collector and the ambient temperature (𝑇𝑚 − 𝑇𝑎𝑚𝑏);

- the collector outlet temperature must be greater than the inlet temperature to the solar HEX from the load side, so that the pump can start to operate.

If the collector field (FPC or PTC) doesn’t meet both conditions, it is by-passed. In the boiler side, one valve’s control function is used. The component n°13 (by-pass TES) valve is used in order to allow the usage of the solar energy accumulated in the storage tank. The setpoint temperature Tboil,set is set to: Tsupply + 5 °C. If the average temperature in the tank is lower than the setpoint temperature, the TES is by-passed, and the load demand is given by the backup system. That means that the control strategy allows the storage to discharge when the average temperature is above the set temperature.

Sizing and specifications

In this section, the design of the plant and the component’s specifications are described, starting from the size of the plant. The storage tank size and the design for the pumps in the system are described.

3.3.1. Size of the plant and Key Performance Indicators (KPI)

The simulation model of [14] was adapted to the Swedish case study of Hemse (described in section 3.1), by scaling the collector area according to the ratio of peak power demand of Hemse to that of Taars, according to formula in Equation 3.3:

𝐴𝑐𝑜𝑙𝑙,𝐻𝐸𝑀𝑆𝐸 =𝑃𝑙𝑜𝑎𝑑,𝐻𝐸𝑀𝑆𝐸

𝑃𝑙𝑜𝑎𝑑,𝑇𝐴𝐴𝑅𝑆 𝐴𝑐𝑜𝑙𝑙,𝑇𝐴𝐴𝑅𝑆 Equation 3.3

The peak loads in the Taars [5] and Hemse system were 9.1 MW and 3.0 MW, respectively. Therefore, the total collector area calculated for the district heating in Hemse is done by using scaling the collector area in Taars by a factor of 0.33. The area of 3270 m2 calculated is

23

used as a reference value. The storage volume linearly depends on the total collector area, explained in section 3.3.2. The key figures for the solar heating system (key performance indicators, KPI) were obtained from the preliminary simulations in order to decide the optimal size of the solar field. The production from solar, the energy from the storage, the storage losses, the boiler consumption and the solar fraction were analyzed for the study. With the KPI it was possible to control if the storage tank is operating properly. The storage tank has two ports, each one with an input and an output. Port 1 of the storage is linked to the solar side, port 2 of the storage is linked to the boiler side. Therefore, the check of the tank is made by doing an energy balance with the output from the simulations, as follow in Equation 3.4:

𝐸𝑠𝑡𝑜𝑟𝑒,𝑝1 + 𝐸𝑠𝑡𝑜𝑟𝑒,𝑝2 + 𝐸𝑠𝑡𝑜𝑟𝑒,𝑙𝑜𝑠𝑠 = 𝐸𝑠𝑡𝑜𝑟𝑒,𝑡𝑜𝑡 Equation 3.4

where Estore,p1 is the energy delivered via port 1, Estore,p2 is the energy delivered via port 2, Estore,loss is the sum of top, edge and bottom losses of the tank and Estore,tot indicates the tank energy storage rate. The solar fraction for the preliminary size calculation was done by using the output data of solar production and boiler consumption. The SF was calculated as in the follow Equation 3.5:

𝑆𝐹 = 𝑄𝑠𝑜𝑙

𝑄𝑠𝑜𝑙+𝑄𝑏𝑜𝑖𝑙 Equation 3.5

This type of solar fraction calculated gives middle values and the store losses are assigned to both solar and auxiliary [39], in this case the boiler. The SF is evaluated following the values given within the IEA Solar Heating & Cooling (SHC) Task 52 - Classification and benchmarking of solar thermal systems in urban environments for solar assisted district

heating (see Table 3-6). For solar district heating with diurnal storage, the values for solar fraction are acceptable in the range of 5 % - 20 %. The higher is SF, the better is for the system performance.

3.3.2. Storage tank size

An important design parameter to set is the volume storage, that strongly depends on the area of the collector field. It is followed the value suggested by TASK 52 from IEA (SHC).

As shown in Table 3-6, the specific storage per volume unit depends on the m2 gross of solar collectors. In this study the specific storage volume is set to 120 L/m2 gross solar area. In the software simulations, the value Vstorage varies depending on the equation: 120*Atot (L).

Table 3-6 shows the benchmark for ground-mounted solar system in the district heating networks.

24

Table 3-6: Reference values for solar assisted district heating, taken by IEA (SHC) TASK 52 - Classification and benchmark of solar thermal system in urban environment [44] (open access data)

3.3.3. Component specifications

In the modelling, the FPC used is the GREENone TEC single glazed GK3133 S by Aalborg CSP [45], the PTC used is T160 by Absolicon [46] and the PVT used is aH72SK by Abora

[47]. In Table 3-7, the parameters used for the collectors are listed. The parameters refer to the gross area. The PTC orientation used for this study is E-W. It has been demonstrated in [5] that by using N-S orientation for PTC field may cause a reduction in cost-effectiveness of the plant because the collectors need to be defocused a lot from May to August. The N-S configuration may produce a lot of excess heat during summer. It has also been proved by this study that the PTC plant with E-W orientation can produce more energy than N-S orientation during the seasons where the heat demand is higher, as winter, autumn and spring season. For that reason, the orientation E-W is used for the PTC field. It has been demonstrated in that using FPC collectors is achieved with a tilt of 30°, concerning the annual output, this configuration is close to the optimal. It also has been proved that the annual output is more sensitive to variation of azimuth angle. The highest monthly output is given when the azimuth is towards south, except for the month of July [14]. For this reason, the tilt of FPC is assumed to be 30°.

In Table 3-8, specifications for boiler and thermal energy storage are listed. The boiler used is a wood chip boiler. The heat transfer medium used is water. The flow rate set in the boiler is calculated from the maximum value in the load data. The thermal energy storage used is a mixed vertical tank. The tank volume depends on the total area of the collector and the sizing

25

is described in detail in section 3.3.2 for the design of the plant as it varies according to the collector area. The pump sizing is described in detail in section 3.3.3. When the sizing of the pump is described, the length of the pipes assumed is outlined. The internal diameter of the pipes in the system is assumed to be 150 mm in the solar side and 100 mm in the boiler side. In Appendix A1, it is possible to find the detailed parameters for each of the collector used in their datasheets.

Table 3-7: Collector parameters, taken from datasheets of components (Appendix A1) and Solar Keymark database [48]

FPC PTC PVT

𝜂0 [-] 0.857 0.766 0.667

a1 [W/m2K] 3.083 0.368 5.70

a2 [W/m2K2] 0.0013 0.00322 0.004

Kd [-] 0.918 0.120 0.95

𝛽, tilt [°] 30 Single-axis tracking E-W 30

𝛾, azimuth [°]* 0 0 0 * 0°=south; -90°=east; 90°=west

Table 3-8: Boiler and tank specifications

Boiler rated capacity 3.0 MW

Boiler rated flow rate 100 000 kg/h

Height of the tank 20 m

Number of tank nodes 10

3.3.4. Pumps’ sizing

The electricity consumption in the systems serves to evaluate the cost for operations in the system and the electricity saved when PVT is integrated in the system. When PVT is added in the solar system, additional electricity is produced. In order to evaluate the monetary savings resulting from the electricity production, the electricity consumption of the pumps operating in the system is simulated in the model. For this reason, the pumps’ sizing has been developed in the project. There are three pumps in the system: the solar pump (in the solar circuit), the solar charge pump and the boiler side pump (in the boiler circuit). For each sizing, the flow rate and the total pressure drop are first calculated, then a suitable pump is chosen by using a size product calculation from Grundfos’s size page [49].

In Table 3-9, the specifications for the three pumps used for the sizing are shown, as the components considered for the pressure drops in the solar circuit and the flow rate used in the model. For the solar collectors, the pressure drop is derived by the datasheets of the two different solar collectors. The main part of the total pressure drop is given by the solar collectors, but it must be taken into account other terms contribution as pipes, bends, valves, T-pieces, heat exchanger. It is assumed that for 1000 m2 of gross area of collectors, 100 m of pipes is needed (one way, then it is doubled to include also the return pipes). The flow rate in the model is set as in Equation 3.6:

�̇�𝑠𝑜𝑙,𝑚𝑎𝑥 = 120 (𝐿

ℎ) 𝐴𝑡𝑜𝑡 Equation 3.6

where �̇�𝑠𝑜𝑙,𝑚𝑎𝑥 is the maximum flow rate in the solar circuit and Atot is the total collector area.

26

In order to calculate the pressure drop in the other components, the dynamic pressure is

calculated as follow: 𝑝𝑑 =𝜌 𝑢2

2, where 𝜌 is the density of the fluid circulating in the circuit

and 𝑢 is the velocity of the fluid. In the solar circuit glycol mixture is used, with a density of 1015 kg/m3. The velocity of the fluid is derived by the graph in [39], (“APPENDIX A, pressure drop in pipes”). To calculate the pressure drop in the components, the dynamic pressure is multiplied with the “resistance value” coefficient for each component (from section 7.4 in [39]). It is assumed a pressure drop of 10 kPa for each heat exchanger. The total pressure drop is obtained by the sum of the solar collectors, pipes circuit and the other components. Note that the same calculation method will be used also for the sizing of the other two pumps in the system, with the exception that there is no solar collectors’ pressure drop. The pipe’s length in the other two circuit loops, solar charge circuit and boiler circuit, it is assumed to be 25 m (one way). The collector area used in the sizing is as the reference value calculated in section 3.3.1 of 3270 m2. The flow rate in the solar circuit is then calculated by using Equation 3.4, and a value of 110 L/s in obtained. In the solar charge circuit, the flow rate is calculated by doing the energy balance on the solar HEX. To maintain the balance of the heat exchanger, it is used the following formula in Equation 3.7:

𝜌1�̇�1𝑐𝑝1∆𝑇1 = 𝜌2�̇�2𝑐𝑝2∆𝑇2

∆𝑇1 = ∆𝑇2 Equation 3.7

�̇�2 =𝜌1�̇�1𝑐𝑝1

𝜌2𝑐𝑝2,

where 1 refers to the solar circuit with glycol mixture, and 2 refers to the water circuit in the solar charge loop. The maximum flow rate in the boiler side circuit is taken from the maximum flow rate in the load profile data and was set to 100000 kg/h. In Appendix A2 the pump curves and the load profiles for the three pumps are reported.

Table 3-9: Specifications for pumps sizing

Solar pump Charge pump Boiler side pump

Flow rate [kg/s] 110 87 28

Total pipes’ length (supply-return) [m] 655 50 50

N° of bends [-] 10 4 8

N° of T-pieces [-] 2 - 1

N° of valves [-] 3 - 1

N° of heat exchangers [-] 1 1 1

Total pressure drop [kPa] 343 33 26

The pump model used in TRNSYS models power consumption using a 3rd degree polynomial relation between pump power and pump flow. Therefore, using the data from the pump curves (reported in Appendix A2), these coefficients were found with Excel by plotting a 3rd degree polynomial scatter of relative power vs relative flow rate, giving a total of 4

coefficients to be used as input in the TRNSYS pump model. Table 3-10 shows the 4 coefficients found for each of the pumps in the system.

27

Table 3-10: Pumps' coefficients of 3rd degree polynomial

Coefficients for TRNSYS C_0 C_1 C_2 C_3

Solar side pump 0.1046 0.534 -0.0071 0.3692

Solar charge pump 0.002 1.2318 -1.4171 1.1851

Boiler side pump 0.0882 0.6968 -0.4231 0.6377

In Table 3-11 the product names of the pumps used in the system are listed.

Table 3-11: Pump models selected

Solar side pump model name LS 150-125-381F

Solar charge pump model name NBG 200-150-200/224

Boiler side pump model name NB 100-160/176 EUP

Economic analysis

In this section, the assumptions made, and the data used for the economic evaluation are explained, as well how the most important economic cost index for thermal and electrical energy are calculated in the study will be shown. When the final solutions have been found, a sensitivity analysis on the different cost of solar collectors and on annual maintenance for the boiler system has been done.

3.4.1. Cost of solar plant

For the total cost of the solar plant, two categories of costs are considered: the installation costs and the annual operation and maintenance costs. The installation costs include the cost for the different type of collectors and the cost of the storage including installation. Since the price of collectors are really variables today on the market, a sensitivity analysis is made in order to have results for three different range of prices for the collectors: low, medium and high. In a following section the sensitivity analysis of collector is more deeply described, and the values used are shown. The storage cost is calculated using the formula in Equation 3.8 [5]:

𝐶𝑠𝑡𝑜𝑟𝑎𝑔𝑒 = (11680 𝑉𝑠𝑡𝑜𝑟𝑎𝑔𝑒−0.5545 + 130)7.44 0.1344 Equation 3.8

The maintenance and operation cost for the solar systems includes the maintenance costs for each type of collectors, the electricity costs for running the pumps in the system, the fuel cost for running the boiler.

3.4.2. Levelized Cost of substituted Heat (LCOHsubst)

The levelized cost of substituted heat is a measure of unit heat production cost for a solar assisted district heating system, based on the amount of boiler energy replaced by solar energy. The substituted levelized cost of heat indirectly measures system performance, as more efficient system configurations lead to lower values of substituted levelized cost of heat.

28

The LCOHsubst of the system is calculated using the formula in Equation 3.9 [50]:

𝐿𝐶𝑂𝐻𝑠𝑢𝑏𝑠𝑡 = 𝐼0− 𝑆0+ ∑

𝐶𝑛(1−𝑇𝑅)−𝐷𝐸𝑃𝑛 ∙ 𝑇𝑅

(1+𝑑)𝑛−

𝑅𝑉

(1+𝑑)𝑡𝑡𝑛=1

∑𝐸𝑛

(1+𝑑)𝑛𝑡𝑛=1

Equation 3.9

where t is the lifetime of the system; I0 is the initial investment cost for the solar collector system including the installation in €; S0 are any potential subsidies and incentives in €; Cn is the annual cost for annual operation and maintenance for the solar system in the year n in €; TR is the corporate tax rate in %; DEPn is the asset depreciation of the solar system in the year n in €; RV is the residual value in €; En is the annual quantity of energy saved by using the solar system in the year n in MWh; d is the discount rate in %.

In Table 3-12, all the values used, and the assumptions made are listed. For the depreciation of the solar system, a degradation of 0.5 % per year was assumed and the yearly energy production was reduced of this factor every year. It was assumed that there weren’t any potential incentives, and the residual values was assumed to be zero.

Table 3-12: Economic values

Lifetime, t 15 (short-term)/30 (long-term) y

Discount rate, d 2.0 %

System degradation 0.5 %/y

Corporate Rate Tax, TR 20.6 [51] %

Subsidies & Incentives, S0 0.00 €

Residual value, RV 0.00 €

3.4.3. Sensitivity analysis on collector’s costs

A sensitivity analysis based on the solar collectors’ cost has been performed. Both FPC and

PTC costs are divided in three ranges: low, medium and high. In Table 3-13, the ranges of values used for both type of collectors are shown. For the FPC, the lowest value is used as explained in [5], following the values in Equation 3.10:

𝐶𝐹𝑃𝐶

{

322

€

𝑚2 𝑓𝑜𝑟 500 𝑚2 < 𝐴𝐹𝑃𝐶 ≤ 1000 𝑚

2

310€

𝑚2 𝑓𝑜𝑟 1000 𝑚2 < 𝐴𝐹𝑃𝐶 ≤ 3000 𝑚

2

293€

𝑚2 𝑓𝑜𝑟 3000 𝑚2 < 𝐴𝐹𝑃𝐶 ≤ 10000 𝑚

2

Equation 3.10

The value indicated in Table 3-13 for FPC-low is the average obtained from the calculation of price in Equation 3.10. For the medium and the higher price, values suggested from IEA (SHC) TASK 52 are used [38]. For PTC, prices from collector manufacturer Absolicon [46], in Equation 3.11 and Aalborg CSP [45] in Equation 3.12, are compared. Prices for PTC of Aalborg CSP are used as

29

explained in [5]. Since there is a large range between the two values, an average price in between has been used as a medium price.

𝐶𝑃𝑇𝐶,𝐴𝑏𝑠𝑜𝑙𝑖𝑐𝑜𝑛 {500

€

𝑚2 𝑓𝑜𝑟 1 𝑚2 < 𝐴𝑃𝑇𝐶 ≤ 1000 𝑚

2

250€

𝑚2𝑓𝑜𝑟 1000 𝑚2 < 𝐴𝑃𝑇𝐶 ≤ 10000 𝑚2

Equation 3.11

𝐶𝑃𝑇𝐶,𝐴𝑎𝑙𝑏𝑜𝑟𝑔 𝐶𝑆𝑃 = 13925 𝐴𝑃𝑇𝐶−0.17 0.1344 (€ 𝑚2⁄ ) Equation 3.12

The value indicated in Table 3-13 for FPC-low, PTC-low and PTC-high are the averages obtained from the calculation of price in Equation 3.10-3.11 and 3.12.

Table 3-13: Range of prices used for solar collectors

Low [€/m2] Medium [€/m2] High [€/m2]

FPC 310 € 420 € 540 €

PTC 375 € 460 € 545 €

For each parametric combination, the total cost for solar collectors is calculated. For each ratio of collector area, the low, medium, and high values of a combination price range is

obtained by calculation according to Figure 3-5. The price ranges obtained for all the ratios of FPC/PTC are compared to reveal the optimal combination with regard to the purchase price. The purchase price will vary according to the manufacturer and market conditions, making a comparison of price ranges better suited to display how optimum ratio can shift depending on available prices. In Appendix A3, the values from the detailed calculation for investment, annual operation and maintenance are reported.

Figure 3-5: Approach on calculation of total cost for solar collectors for three different ranges of prices

30

3.4.4. Sensitivity analysis on annual boiler maintenance

In the calculation for the system without solar, the operation costs are obtained by the sum of the cost for the boiler fuel consumption and the cost for the pumps electricity consumption, using the same prices of energy mentioned before. The boiler efficiency is assumed to be 90 %. The total operation and maintenance cost for the conventional system without solar integration is calculated as follow, in Equation 3.13: 𝑂&𝑀 𝑐𝑜𝑠𝑡 𝑐𝑜𝑛𝑣𝑒𝑛𝑡𝑖𝑜𝑛𝑎𝑙 𝑠𝑦𝑠𝑡𝑒𝑚 = [(𝐿

𝑎𝑛𝑛𝑢𝑎𝑙 𝜂𝑏𝑜𝑖𝑙 𝑓𝑝𝑟𝑖𝑐𝑒

) + (𝑒𝑙𝑝𝑢𝑚𝑝 𝑒𝑙𝑝𝑟𝑖𝑐𝑒)] 𝑀𝑏𝑜𝑖𝑙 Equation 3.13

where Lannual indicated the total annual load in MWh; 𝜂𝑏𝑜𝑖𝑙 indicates the efficiency of the

boiler in %; 𝑓𝑝𝑟𝑖𝑐𝑒 indicates the fuel price in €/MWh; elpump indicates the annual electricity

comsumption of the pumps in the system in kWh; elprice inidicates the electricity price in €/kWh; Mboil indicates the cost for the maintenance on the total cost in %. A sensitivity analysis for the cost for maintenance of the boiler is done. The first case is the scenario assumed with no maintenance of the boiler. This is an unreal condition, but it is useful to do as a base condition to analyze how much impact has the maintenance on the total costs. The cost of maintenance for the boiler are today in the range of 2 % - 5 % of the operation costs [52]. The sensitivity analysis uses the limit values of this range. A higher maintenance for the boiler makes it clear that designing a solar assisted system could appear more convenient. In the next chapter, it will be found that the variation of the marginal cost depends strongly by the variation of the maintenance in the boiler.

3.4.5. Operation and maintenance marginal cost

Another important factor that is analyzed in the economical evaluation is a sort of a marginal cost, that wants to determine the added cost for the annual operation and maintenance of the system when the solar part is introduced in the system. This marginal cost (MC) defines the operation cost of production of an additional unit of the good, which is the solar production in this specific project. In other terms, it indicates if it is convenient or not to invest in the additional unit of solar system. To calculate this type of marginal cost, the annual operation and maintenance costs for the system with only boiler, and the annual operation and maintenance cost for the system with solar are included. The annual operation and maintenance cost for the system with no solar is as described in the previous section in Equation 3.13. The annual operation and maintenance cost for the solar system is obtained by the sum of the boiler energy cost, the pump electricity cost, as done for the conventional, by adding the cost of substituted energy to the boiler from solar previously calculated. The factor of the substituted energy is calculated as the following formula in the Equation 3.14:

𝐶𝑜𝑠𝑡 𝑜𝑓 𝑠𝑢𝑏𝑠𝑡𝑖𝑡𝑢𝑡𝑒𝑑 𝑒𝑛𝑒𝑟𝑔𝑦 = 𝐸𝑡 𝐿𝐶𝑂𝐻 Equation 3.14 The total annual operation and maintenance cost for the system with solar integration is calculated as follow, in Equation 3.15: 𝑂&𝑀 𝑐𝑜𝑠𝑡 𝑠𝑜𝑙𝑎𝑟 𝑠𝑦𝑠𝑡𝑒𝑚 = (𝐿𝑎𝑛𝑛𝑢𝑎𝑙 𝜂𝑏𝑜𝑖𝑙 𝑓𝑝𝑟𝑖𝑐𝑒) + (𝑒𝑙𝑝𝑢𝑚𝑝 𝑒𝑙𝑝𝑟𝑖𝑐𝑒) + (𝐸𝑡 𝐿𝐶𝑂𝐻𝑠𝑢𝑏𝑠𝑡) Equation 3.15 Where LCOHsubst refers to the substituted levelized cost of heat, Et refers to the substituted energy and the other symbols are explained previously in section 3.4.4. Then, the marginal cost is calculated as the formula in Equation 3.16:

31

𝑀𝐶 = 𝑂&𝑀 𝑐𝑜𝑠𝑡 𝑠𝑜𝑙𝑎𝑟 𝑠𝑦𝑠𝑡𝑒𝑚 − 𝑂&𝑀 𝑐𝑜𝑠𝑡 𝑐𝑜𝑛𝑣𝑒𝑛𝑡𝑖𝑜𝑛𝑎𝑙 𝑠𝑦𝑠𝑡𝑒𝑚 Equation 3.16 Note that if the marginal cost is negative, it means that the costs are higher for the conventional system rather than the solar system. Then, this indicator suggests that in this case it is more convenient to install the solar system and it will have a financial return in the future. When there is a positive value, it means that the value represents the additional cost to invest to add the solar system. In the calculation of the annual operation and maintenance cost for the different scenarios, the boiler investment cost is not included, since the marginal cost calculated is an evaluation based on the retrofitting of adding the solar part into the system. This means that the boiler is already present in the system at the time that the solar system is added.

3.4.6. Sensitivity analysis of PVT ratio added into the system

When the best configuration was found in the parametric analysis for the ratio of FPC and PTC, a sensitivity analysis based on the percentage added of PVT into the system has been

performed, as shown in Figure 3-6. For each of the better configurations (maximum the top three) found in the previous step, four combinations are done as follow: from 5 % to 20 % of PVT in the FPC total fraction. For each of the combinations obtained, the new levelized cost of substituted energy was calculated, including the investment cost and the maintenance cost for the added part of PVT respectively in the initial investment and the operational costs for the solar system. Furthermore, in this case the economical savings due to the added production of electricity from the photovoltaic part of the component has been calculated.

Figure 3-6: Approach on the calculations for the parametric analysis on the percentage of PVT

The annual financial gain to the production of electricity from PVT was calculated taking into account a degradation factor for the PVT of 0.5 %/year. The first step was to calculate the amount of electricity produced every year, as indicated in Equation 3.17:

𝑒𝑙𝑃𝑉𝑇,𝑡 =𝑒𝑙𝑃𝑉𝑇,0

(1+0.005)𝑡 Equation 3.17

where elPVT,t indicates the quantity of electricity produced by PVT in the year t; and elPVT,0

indicates the quantity of electricity produced by PVT at the year 0. When the electricity production is calculated with the discount factor for every year, it is possible to calculate the total production for the time frame wanted for the investment, called total_elPVT,t. In Equation 3.18, the electricity production at year t is calculated:

𝑡𝑜𝑡𝑎𝑙_𝑒𝑙𝑃𝑉𝑇,𝑡 = ∑ 𝑒𝑙𝑃𝑉𝑇,𝑛𝑡𝑛=1 Equation 3.18

32

The financial gain Rt after year t is calculated as follow, in Equation 3.19:

𝑅𝑡 = 𝑡𝑜𝑡𝑎𝑙_𝑒𝑙𝑃𝑉𝑇,𝑡 𝑒𝑙𝑝𝑟𝑖𝑐𝑒 Equation 3.19

where elprice indicates the electricity price in €/Wh. In this calculation, it is assumed that the electricity price remains constant in the future. This indirectly assumes that the evolution of market price for electricity will be equal to that of the inflation rate. Given that the market price is highly variable and uncertain, this assumption is a conservative one. However, any economic benefit displayed from using PVT in this economic analysis will also be valid with a market price increase above that of the inflation rate. Hence, the assumption that the price will remain constant at today’s (low) rate is a worst-case scenario. As done previously, the marginal cost for the annual operation and maintenance of the system when the solar part is introduced in the system has been calculated in the same way as explained in section 3.4.5. However, in this occasion the financial gain has been subtracted to the differences calculated in the marginal cost in order to take into account the annual benefit gave by the electricity production. The PVT parametric study was done to assess how much the integration of the technology affects the production of energy and the costs. From the results obtained, the study was focused in two main points:

o How much of PVT area should be added to the system to get the same amount of heat as in the optimum configuration of FPC/PTC found, and how this affects the electricity production and the economy of the project;

o How much of PVT area should be replaced in the collector’s area to cover the pump consumption of the optimum configuration of FPC/PTC found, and how this affects the economy of the project.

For the first point mentioned, the goal was to compare the best final combinations obtained with PVT in terms of thermal production with the optimum solution found without PVT. For this reason, the first parameter that has been compared was the change in thermal energy production, and thus the thermal energy production found in the optimum solution with FPC/PTC. Since the specific hybrid thermal production in the system was obtained from the weighted average of the specific thermal production of the different types of collectors in the system, it was possible to calculate the amount of area of PVT needed to get a total amount of thermal production, obtained by the contribution FPC, PTC and PVT. By using the same thermal specific energy production for FPC, PTC and PVT (in kWh/m2) obtained from simulations, the areas of FPC and PTC (in m2) and the final annual thermal energy production wanted (kWh), the amount of area of PVT needed was derived. For the second point mentioned, the goal was to reach the total electricity consumption in the best solution found with FPC/PTC, by adding area of PVT to reach the total annual electricity. To do the calculation, the specific electricity production of PVT was used. By using the same specific electricity production from PVT (in kWh/m2) and annual electricity consumption of the system desired (in kWh), a calculation has been done to keep all the listed parameters fixed, and varying the total area of PVT, as shown in Equation 3.20:

𝐴𝑃𝑉𝑇 =𝑡𝑜𝑡𝑒𝑙

𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐𝑒𝑙,𝑃𝑉𝑇 Equation 3.20

33

Where APVT refers to the area of PVT in m2; totel refers to the annual electricity consumption in kWh; specificel,PVT refers to the specific electricity production of PVT in kWh/m2.

Delimitations

This section is useful to explain to the reader the main assumptions and delimitations that have been made during this study. The delimitations of the study are the main factors that have not been investigated in the research work due to several reasons. The following main delimitations are present in the research work:

o In the total annual operation and maintenance costs, the cost for the investment of

the boiler is not included. This is done because the economic evaluation is based on the operational marginal cost which is based on the retrofitting on adding the solar part into the system, which means that in the moment the solar part is added to the system, the boiler is already present in the system.

o The solar radiation data used in the model are from Meteonorm and they describe the weather conditions in Hemse, Gotland for a typical year. These data are used because the weather data given by the weather station in Hemse by the Swedish Meteorological and Hydrological Institute (SMHI, [53]) have a manual station and only measure the data twice a day. For this reason, they are not complete, and they should have been interpolated to get the wanted time resolution for the simulations. The assumption made is that the weather in Gotland is almost constant over the years since it is an island, therefore the data for a typical year are used.

o The boiler used in the model is assumed to be ideal, as it starts and stops immediately,

and its heat rate is fully controlled.

o There is a delimitation on the collectors’ prices, due to the fast change and the wide variations on the market every day. For this reason, range of prices are used in the economical evaluation, so that the project can be adapted to the prices of collectors that one wants to use.

o Concerning the production of the electricity in the second part of the project, it is not used the levelized cost of energy (LCOE) in this case, but the economic evaluation is assessed through the levelized cost of substituted heat. The LCOE is a measure of the price of electricity delivered by the plant that would equalize the discounted cash flow over the lifetime of the project. That choice is made to be consistent with the first part of the project, where the levelized cost of substituted heat is evaluated. In that way, it is possible to compare the results each other. Indeed, the contribution of the electricity production is considered into the total annual operation and maintenance cost and the operation marginal cost, which are the end parameters for the comparison.

o The assumption made for the cost of fuel is that it is constant over the year. This is an unreal condition, but since the cost of fuel will always increase in the future, the economic evaluation done is a sort of “pessimistic” situation which will always move towards into a better situation than the one studied. This means that the addition of the solar part in the system will be more convenient in the future rather than today.

34

o As regards to the cost of electricity, it is done the assumption that the electricity price increase as much as the inflation rate increases. Only a discount factor is assumed due to the depreciation of the technology over the years. The detailed analysis and study regarding the variation of the price of electricity over the years is not done to its complexity depending on the several variables that need to be considered and due to the limitation of the time of this work. This can be a starting point for a future work.

35

4 Results and discussion

In this chapter, the results from the simulations are presented. The presentation of findings is divided in two main parts. The first part analyses the configuration of the system with the collectors as in the base case: with FPC and PTC. It is observed in which configuration the solar thermal production is enhanced and as well how the changes in ratio of collectors in the total area affect the cost of the overall system. The second part of the chapter analyses how the integration of another type of hybrid collector in the system affects the results. The integration of PVT is investigated in terms of variation in thermal energy production and added electricity production. In this part as well, an economic evaluation is conducted to notice if the addition of a new technology in the system is convenient or not.

FPC/PTC parametric analysis

The starting point of the thesis research is to find how the solar production varies depending on the ratio used of FPC and PTC. In this way, it is possible to understand where the solar output is enhanced, and which could be the best configuration for the case study considered. The ratio for FPC and PTC has been studied from the configuration with 100 % FPC and 0 % PTC, to the configuration with 0 % FPC and 100 % PTC. In Figure 4-1, the annual output from the boiler and from the solar hybrid system in shown, as well as the solar fraction obtained in every combination. As it can be seen, the total annual output (MWh/year) from the hybrid solar system gives a better production with the increase of PTC share in the system. The total specific collector production in hybrid system, in fact, varies from a value of 419 kWh/m2 in the configuration 1/0 (100 % FPC and 0 % PTC) to a value of 502 kWh/m2 in the configuration 0/1 (0 % FPC and 100 % PTC). In the other configurations, it is possible to state that there is a quasi-linear increasing in production. If there is more solar production, that means that also the solar fraction increases, and the energy demand from the boiler is reduced. The solar fraction stays in the range 11 % - 13 %, which is considered quite in alignment with the typical value of 12 % for solar fraction given by IEA

(SHC) TASK 52 for solar district heating with diurnal storage (Table 3-6). These first results indicate that a bigger ratio of PTC enhance in the energy output. Figure 4-1 shows the annual output and solar fraction (SF) for various ratios of installed FPC to PTC areas for a solar thermal system of 3270 m2 total collector area.

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Figure 4-1: Annual output and solar fraction (SF) for various ratios of installed FPC to PTC areas for a solar thermal system of 3270 m2 total collector area.

It is not possible to state which is the best configuration only based on the solar energy output from the hybrid system, but also the changes in electricity consumptions are considered in the following graph. An economic evaluation is done based on the annual operation and maintenance marginal cost (the added cost for the solar unit), the levelized cost of substituted energy of the boiler and the energy saved. On the point of view of solar production only, it is possible to assert that the configuration with only PTC it is the best solution. When there is a bigger ratio of PTC and thus of solar production, the electricity consumption in the system increases. The electricity consumption is given by the electricity usage of the

pumps in the system. In Figure 4-2, it is shown the electricity consumption of the pumps in the solar side circuit (yellow color) and the electricity consumption of pumps in the boiler side circuit (green color). In the boiler side circuit, the electricity consumption is given by the sum of the charge pump and the boiler pump consumptions. The solar pump consumption varies from 13.6 MWh/year in the configuration 1/0 (100 % FPC and 0 % PTC) to a value of 14.6 MWh/year in the configuration 0/1 (0 % FPC and 100 % PTC). At the same way, the boiler side electricity consumption varies from 14.3 MWh/year in the configuration 1/0 (100 % FPC and 0 % PTC) to a value of 15.3 MWh/year in the configuration 0/1 (0 % FPC and 100 % PTC). In the Appendix A4, it is possible to find the detailed table of consumption for all the pumps in the systems for the 11 different scenarios. The electricity consumption for the system with the boiler only, not solar assisted, is of 2.7 MWh/year. The pumps energy

consumptions have been used in the economic analysis. Figure 4-2 shows the annual electricity consumption for the system in all the different scenarios studied, referring to the boiler loop consumption and the solar loop consumption.

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[%]

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37

Figure 4-2: Annual pumps electricity consumption for all the different scenarios studied in the FPC/PTC parametric analysis.

4.1.1. Economic evaluation on FPC/PTC parametric study

In the economic study, two main factors are taken into account: the annual operation and maintenance cost of the system and the marginal cost. The annual operation and maintenance cost for the different scenarios with solar is compared to that obtained by using the “boiler-only” system, called the “conventional system”. The marginal cost indicates where the project starts giving economical returns. The annual operation and maintenance costs calculated for the conventional system are

indicated in Table 4-1. It is assumed the same annual operation and maintenance cost for the boiler-only system for the short- and long-term investment.

Table 4-1: Annual operation and maintenance cost for the conventional system

Annual operation and maintenance cost for the conventional system

0 % Maintenance boiler 2 % Maintenance boiler 5 % Maintenance boiler € 387 k € 395 k € 407 k

In the short-term investment evaluation, the annual operation cost is compared with the one

of the conventional with boiler-only system in Figure 4-3. The minimum value reached by the solar combinations for operation costs in the medium range is of € 441 k with a configuration of 80 % FPC and 20 % PTC. If it is compared to the value of the conventional

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system, as it can be seen in the chart, there is no point to state that it is convenient to install the solar system for an investment of 15 years. At the same way, also with the low range and high range of prices, it is possible to state that it is not convenient to install the solar system for a short-term investment. The maximum value for the annual operation and maintenance costs obtained by using the maximum proportion of boiler’s maintenance of 5 % is of € 407 k.

Figure 4-3 shows the annual operation and maintenance costs for the scenarios with FPC/PTC combinations compared to the boiler-only system with different cases of maintenance, for a 15-year investment timeframe. The value in the medium range of price is indicated with the cross in each box, and the lower and higher range of price are indicated by the horizontal dash in the bottom and in the top of the box respectively.

Figure 4-3: Annual O&M costs: conventional system vs solar assisted system parametric configuration – 15 years analysis.

In accordance with that, also the annual marginal cost doesn’t give any return for all the

cases. In Figure 4-4, the marginal cost is calculated for the medium price range as displayed. In the range of medium cost of collectors, the minimum value for the marginal cost reached is € 54 k if the maintenance of the boiler is not assumed, € 46 k if the maintenance of the boiler is assumed to be 2 % and € 34 k if the maintenance of the boiler is assumed to be 5 %, highlighted with the red circle in the chart. That means that after the 15 years of the investment, the return on investment (ROI) is still negative, which means that the project is not economically preferable.

Figure 4-4 shows the annual marginal cost for the operations compared with the boiler-only system with different cases of maintenance, for a 15-year investment timeframe.

39

Figure 4-4: Annual marginal operation cost for the medium price range - 15 years analysis.

More interesting results are obtained in the long-term investment evaluation. That is expected because in a longer timeframe, the total investment cost is more depreciated. The levelized cost of substituted energy is expected to be lower in a longer investment because, as shown in Equation 3.3, the total energy saved through the years is expected to be much higher since the economic lifetime is double. The annual operation and maintenance costs are compared with the one of the system with only the boiler in Figure

4-5. In this case, the minimum value reached for in the medium range is of € 394 k with a configuration of 70 % FPC and 30 % PTC. Very similar results are found in the two combinations with 60 % FPC – 40 % PTC and 80 % FPC – 20 % PTC, with a value of € 395 k. If it is compared to the value of the conventional system, the solar investment results convenient both in cases if the boiler has maintenance of 2 % and 5 %, with values of € 395 k and € 407 k respectively as shown previously. When the maintenance of the boiler is not considered, the operation cost of the solar system is higher, but the condition with no maintenance is unrealistic. In the lower range, the minimum value of operation costs reached is of € 379 k with a configuration of 80 % FPC and 20 % PTC. In this case, when it is compared to the value of the conventional system, this value is also convenient compared to the case assumed with no maintenance. In the case of long-term investment, it is possible to state that if the prices of collectors are both in a low range, all the different combinations of FPC/PTC ratio would pay off the initial costs. On the other hand, when both prices are in the high range, there are no combinations that could be convenient compared to the values for the conventional system. The configuration of 70 % FPC and 30 % PTC in the medium range closely approximates the final solution optimized for the plant in Taars in [5], where the ratio found for the optimization is of 74 % FPC and 26 % PTC.

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ginal

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FPC/PTC ratio

0 % Maintenance boiler 2 % Maintenance boiler 5 % Maintenance boiler

40

Figure 4-5 shows the annual operation and maintenance costs for the scenarios with FPC/PTC combinations compared to the boiler-only system with different cases of maintenance, for a 30-year investment timeframe.

Figure 4-5: Annual O&M costs: conventional system vs solar assisted system parametric configuration – 30 years analysis.

In accordance with the annual operation and maintenance cost, the annual marginal operation cost for the medium range gives better results in the best configuration found. In

Figure 4-6, the marginal costs calculated for the medium price range as displayed. If maintenance of boiler is assumed, in both cases of 2 % and 5 %, the marginal cost has the lower value for the configuration 70 % FPC and 30 % PTC in the medium range of prices. The annual marginal operation cost is negative with value of - € 607 and - € 12 k respectively, highlighted with the red circle in the chart. That means that the ROI is positive, and the project is economically preferable. The marginal costs for operations obtained in the lower range of prices gives revenues compared to all the three scenarios of maintenance of the boiler. In the lower range of prices, the highest revenue is fulfilled in the configuration 80 % FPC and 20 % PTC. In Appendix A5, the different annual marginal cost for the short-term and long-term investment in each ratio of FPC/PTC and in each range of prices used are reported.

Figure 4-6 shows the annual marginal cost for the operations compared with the boiler-only system with different cases of maintenance, for a 30-year investment timeframe.

41

Figure 4-6: Annual marginal operation cost for the medium price range - 30 years analysis.

When the best configurations were found, it was possible to evaluate if some combinations of prices were as well convenient for the investment. For the configuration with 60 % FPC – 40 % PTC, 70 % FPC – 30 % PTC and 80 % FPC – 20 % PTC (which were found to be the bests), two combinations of prices were calculated as follow: FPC low price with PTC

medium price and FPC medium price with PTC low price. As reported in Table 4-2, it is possible to state that the values of these last combinations are between the values of “low FPC – low PTC” and “medium FPC – medium PTC”, between results of operation costs in the range of € 380 k and € 390 k. If included the maintenance of the boiler, in all cases there are profitable results that could pay off the project. As a result, it is possible to say that as long as collector’s costs are 420 €/m2 for FPC and 460 €/m2 for PTC, or lower, then it pays off to install a solar thermal system. Table 4-2: Results of operation costs from different combinations of price for the collectors (derived from the

best combinations found previously)

30 years investment 60 % FPC 40 % PTC

70 % FPC 30 %PTC

80 % FPC 20 % PTC

LOW price FPC - MEDIUM price PTC € 385 k € 383 k € 382 k MEDIUM price FPC - LOW price PTC € 390 k € 391 k € 392 k

Optimized solution

In the first step of the work, the best solutions found have been identified and used as a start point for the next main step, when PVT is added to the system.

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42

It was possible to state that an investment of 15 years is a long way far from bringing a real profit to a system with such size. For this reason, in the next step of economic evaluation it has been only considered a long-term investment of 30 years. The best configuration found was the one with 70 % of FPC and 30 % of PTC in the medium range of prices, followed by the two configurations: 80 % of FPC – 20 % PTC and 60 % FPC – 40 % PTC. As long as it has been demonstrated that with the high range of prices there is no point to get a profitable project and with low range of prices there is always a profitable project, the medium range of prices has been used in the following parametric analysis.

In table Table 4-3, the three best configurations found are listed. Only the best configuration has been used as a starting point for the following step of the project.

Table 4-3: Best configurations founded in the first step of the work

Range of price FPC share PTC share

MEDIUM

60 % 40 %

70 % 30 %

80 % 20 %

PVT parametric study

The PVT parametric analysis, as explained in section 3.4.6, started with the replacement of a certain proportion of FPC by PVT. In the following presentation of results, the parametric analysis of PVT is divided in four cases: CASE A refers to a replacement of 5 % of FPC by PVT; CASE B refers to a replacement of 10 % of FPC by PVT; CASE C refers to a replacement of 15 % of FPC by PVT; CASE D refers to a replacement of 20 % of FPC by PVT. In all the following results presented, the cases are named as explained.

In Table 4-4, the overall ratio of area and the value of areas used for FPC, PTC, and PVT in each case are stated.

Table 4-4: Distribution of collectors in PVT parametric study

FPC share

[%] PVT share

[%] PTC share

[%] FPC area

[m2] PVT area

[m2] PTC area

[m2]

CASE A 66.5% 3.5% 30% 2175 114 981

CASE B 63.0% 7.0% 30% 2060 229 981

CASE C 59.5% 10.5% 30% 1946 343 981

CASE D 56.0% 14.0% 30% 1831 458 981

The parametric study started from the best configuration. In this new combination, there is a new parameter to look at, which is the amount of electricity produced by the hybrid

component. In Table 4-5, the annual electricity produced yearly by the PVT in each combination is shown. The specific electrical output of the PVT is of 91.2 kWh/m2 in all cases. As expected, the more the percentage of PVT is added, the more the electricity production is. The PVT specific electrical output has a value of 91 kWh/m2 in every case. The annual production of electricity from PVT varies from a value roughly of 11 MWh/year in CASE A, to a value of 42 MWh/year in CASE D. That is a parameter to look at when the economic evaluation has been carried on, to get the total revenues given using the electricity

43

produced in the system to fulfill the electricity consumptions of the system, instead of buying it from the grid. In section 4.3.3, the area of PVT needed to cover all the electrical consumption for the optimal solution FPC/PTC has been calculated.

Table 4-5: PVT electrical output

Annual electrical output [MWh/year]

CASE A 10.4

CASE B 20.9

CASE C 31.3

CASE D 41.7

On the other hand, the higher the percentage of PVT in the system is, the lower is the thermal energy production in the overall system. That happens because a part of FPC that was used for the thermal production is replaced by a PVT share, which has lower specific thermal energy production than FPC.

In Figure 4-7, the variation of the thermal energy production is shown. As it can be seen, there is a linear decreasing of the thermal production with the increasing of the PVT share in the system. The production of electrical energy increases linearly together with the decreasing of the production of thermal energy. The specific collector production in hybrid system, in fact, varies from a value of 402 kWh/m2 in the CASE A to a value of 385 kWh/m2 in the CASE D. If this value is compared to the specific hybrid production in the best solution found previously of 451 kWh/m2, there is a reduction of specific thermal energy in the system that is in the range of 10 % to 15 % from the CASE A to D. In section 4.3.2, the area of PVT needed to get the same total amount of thermal energy as in the optimal solution found has been calculated.

44

Figure 4-7: Annual hybrid thermal energy production – parametric analysis of PVT with the best

configuration 30 % PTC/70 % FPC+PVT.

4.3.1. Economic evaluation on PVT parametric study

As in the previous economic study, the two factors that are considered are the total cost for the annual operation and maintenance and the marginal cost defined in section 3.4.5. As previously, they are compared to the value for the conventional system in the three conditions of maintenance of the boiler described. In this case, the annual operation and maintenance costs take account of the revenue given by the electricity production, by subtracting the financial revenue obtained by the electricity produced, as explained in section 3.5.6. The annual operation and maintenance costs are compared with the optimum found with

FPC/PTC and with the one of the system with only the boiler. In Table 4-1 the boiler-only annual operation and maintenance cost are shown.

Figure 4-8 shows the annual operation and maintenance cost variation obtained of the four cases with PVT, compared to the optimum solution FPC/PTC found. The minimum value of annual O&M costs got for the configurations studied has been found to be with CASE D, with a value of € 407 k, higher than both cases for the optimum solution and the boiler-only system. This result suggests that, even if the addition of more area of PVT lead to an increase of the total investment cost for the solar system, the revenue provided by the production of electricity outperforms the initial costs.

In accordance with the annual operation and maintenance cost, also the marginal costs give negative ROI in the scenarios studied, except for CASE D, where the ROI is positive. Indeed, the operation marginal in this case is negative, with a value of - € 2 k (which means that is a revenue) in the case by using the highest value for the maintenance of the boiler.

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Therefore, also from the marginal cost it is possible to state that such an integration of PVT in the system in not economically convenient for the project. In Appendix A6, the different marginal cost calculated for the combinations studied with PVT are reported.

Figure 4-8: Annual operation and maintenance costs – parametric analysis of PVT with the best configuration 30 % PTC/ 70 % FPC+PVT.

4.3.2. Combination giving the wanted thermal energy production

As has been pointed out in the previous analysis, the addition of PVT makes a reduction in production of thermal energy, because the new addition of electricity production is enhanced. Thus, the area of PVT needed to get the same amount of thermal energy production as when using an optimum combination of only FPC and PTC has been investigated, as explained in section 3.4.6. The start point value is thereby the total annual production of thermal energy production in the optimum solution with 70 % of FPC share and 30 % of PTC share. The total thermal hybrid production of this solution is of 1484 MWh/year. The case compared from the PVT parametric analysis was CASE A, since it gave the best results in terms of thermal energy

production. In Figure 4-9, the different scenarios are compared, pointing out how the annual thermal production varies. In the optimum case FPC/PTC the total collector area was of 3270 m2. In the parametric analysis with PVT the total collector area was kept to the same value of 3270 m2. The new area of PVT area to get the same amount of heat as in the optimum case was of 885 m2, which means an addition of 770 m2 in the total area. The addition of the area has an impact in 24 % in increase.

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Figure 4-9 shows the comparison of different scenarios in terms of thermal production. In particular, the optimum case of FPC/PTC, the case of PVT parametric analysis and the new case with the amount of PVT area added are compared.

Figure 4-9: Comparison of thermal production based on different collectors’ area, from the optimum FPC/PTC scenario to the cases with PVT added area in the system.

In the economic analysis, the new configuration gave different results, which are summarized

in Table 4-6. The electricity production varies from 10 MWh/year to 80 MWh/year. The addition of electricity in the system has a good impact in the overall economy of the project. In fact, both the annual operation and maintenance cost and the operation marginal costs are improved. If compared to the valued from the optimized solution, the addition of area of PVT gave better results compared to the optimized solution found. The ROI for the project is positive when the maintenance of the boiler is assumed. For that, the operational marginal cost has a negative value.

Table 4-6: Main results from the addition of PVT area to get the amount of thermal production

Annual electricity production [MWh/y] 80.7

Annual O&M costs [k€] € 388 k

O&M marginal cost – 0 % boiler maintenance [k€] € 0.7 k

O&M marginal cost – 2 % boiler maintenance [k€] - € 7 k

O&M marginal cost – 5 % boiler maintenance [k€] - € 18.7 k

4.3.3. Combination giving the electricity consumption

The other parameter to look at PVT is the electricity consumption in the optimum case found. In this case, the goal was to find out the area of PVT needed to cover all the electricity consumptions in the optimum FPC/PTC solution due to the operation of the pumps.

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The start point in this case is then the total electricity consumption given by the contribution of the solar pump side consumption and the boiler side pump consumption in the optimum

solution of 70 % FPC and 30 % PTC. In Table 4-7, the area and the electricity consumption in the optimum case FPC/PTC are summarized.

Table 4-7: Optimum configuration FPC/PTC details

Area FPC [m2] 2289

Area PTC [m2] 981

Annual electricity consumption [MWh/y] 29.1

In Figure 4-10, the result from the calculation for the added amount of PVT area is shown. As it can be seen, the area of PVT to be replaced to get the electricity consumption desired is of 319 m2. This alteration of the total collector area distribution led to a decrease in thermal energy production (yellow line in the graph), as expected. The reduction in the annual thermal energy production is of 14 %.

Figure 4-10: Effect from addition of PVT area on the thermal production, comparison of the optimum case with FPC/PTC and the case with added PVT area.

In this case, in the economic analysis, the new configuration didn’t give better results than

the optimum solution FPC/PTC. In Table 4-8, the results from the economic analysis are summarized. The ROI was negative in all the scenarios of maintenance of boiler. For this reason, the operational marginal cost had positive values. The annual operation and maintenance cost is 6 % increase compared to the case in the optimum solution FPC/PTC.

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Table 4-8: Main results from the addition of PVT area to cover the electrical consumption

Annual electricity production [MWh/y] 29.1

Annual O&M costs [k€] € 419 k

O&M marginal cost – 0 % boiler maintenance [k€] € 31 k

O&M marginal cost – 2 % boiler maintenance [k€] € 24 k

O&M marginal cost – 5 % boiler maintenance [k€] € 12 k

In the next chapter, the main conclusion of the results is outlined. In particular, the comments on the results found are developed by different points of view. In other terms, a combination can be considered more convenient or not, depending on the different targets of the client which manages the system. One could focus more on the overall savings of the system and on the thermal energy production only; another instead could be more interested on the production of thermal and electric energy combined, trying to enhance more the production of electricity and sell the surplus generated to the grid.

49

5 Conclusions

The aim of the research work was at first to evaluate if the solar assisted district heating previously studied in Taars, Denmark could give similar results if adapted to a case study in Sweden in Hemse, Gotland. The second main aim of the research work was to do a techno-economic evaluation by adding to the system a recently emerging hybrid technology, the PVT, which only using a single module can produce both electricity and thermal energy. In this chapter, discussion and reflections on the results from simulations and economic calculations are presented.

In the first part of the work, where only FPC and PTC were present in the system, the more considerable results achieved were the following:

o It has been found that the more percentage of PTCs were present, the higher the efficiency in terms of annual thermal energy production was. The variation of the annual specific production of the reference cases (only FPC and only PTC respectively) has been compared to the previously study done for the Danish case study. In the Swedish case study, the variation in annual specific thermal production varies from 419 kWh/m2 for the FPC reference case to 502 kWh/m2 for the PTC reference case. The increase in thermal energy in the PTC reference case is of 20 %. If these values are compared to the study in [14], there is the same trend in annual specific thermal energy production, which has a variation of 19 % in increase in the PTC reference case.

o It has been found that in terms of economy, the PTC reference solution has negative

effect on the system due to two main factors. The first is due to the higher electricity consumption in the overall system compared to the reference case with only FPC. The second is due to the higher costs of PTC on the market today. It is important to know that there is always an uncertainty on the exact price of the collectors, their installation, and their maintenance. This limitation is due to the rapid and continuous change of the price of solar collectors on the market.

o The annual O&M for the system with boiler only were the following: € 387 k when no maintenance was included; € 395 k when 2 % of maintenance of the boiler was included; and € 407 k when 5 % of maintenance of the boiler was included.

o The final optimal solution achieved in the first part of this work consisted of a share of 70 % of FPC and a share of 30 % of PTC. The annual O&M cost obtained in a long-term investment with this solution was of € 394 k using medium range price and of € 379 k using low range price, which is lower compared to the values for boiler-only system, when maintenance of the boiler is included. That outcome was found to be a reasonable result when compared to the thermo-economic optimization of the Danish hybrid plant study in [5]. In the mentioned study, the optimal solar collector area considering the economic evaluation was found to be of a share of 74 % of FPC and a share of 26 % of PTC.

In the second part of the work, when PVT was introduced in the system, the more considerable results achieved were the following:

o For the studied climate, when the area of the field is kept at the same value, the addition of PVT in the system did not appeared a convenient solution if compared to the optimal solution found in the first part of the work. The minimum annual

50

O&M cost obtained in a long-term investment in the PVT parametric analysis was of € 407 k, in a case where 20 % of FPC was replaced with PVT. This value was higher than the only-boiler system and the optimum solution of FPC/PTC found. One of the main reasons for this result could be due to the prices of PVT today. PVT is still an emerging technology, and it is in the start point of its developing and utilization in existent projects. The prices for PVT are currently still high and the number of projects in Europe are still low, as given within the IEA Solar Heating & Cooling (SHC) Task 60 – Existing PVT systems and solutions [54]. Moreover, most of the existent project using PVT are in the southern Europe, with a majority in Spain. For that reason, comparing the prices for a project in the Nordic country with a project in the south of Europe is a limiting factor. When the trend curve of prices for PVT in future will show a decrease and a consequently reach a point of stability of prices, the project could achieve more convenient results even in the north of Europe.

o It has been demonstrated that the addition of PVT into the system worsened the thermal energy production. The specific production varies from 451 kWh/m2 in the optimum solution FPC/PTC to 402 kWh/m2 as a maximum value in the PVT parametric analysis. The total annual thermal production decreases of 11 % compared to the optimal solution found with FPC/PTC (from 1484 MWh/y to 1315 MWh/y).

o When the area of PVT added to the system is larger (in the case studied around 8

times larger than in a case when using a share of 66.5 % FPC, 30 % PTC and 3.5 % PVT), the project starts to be economically feasible, with a annual O&M marginal of € 388 k, which was lower than the only-boiler system and the optimum solution of FPC/PTC found. This factor indicates that to make sure that the PVT technology gives positive aspects in the overall economy of the project, it is needed a larger area of the entire solar field. This could be a limiting factor, since the available area of a project is not a factor that may be varied as desired, and it is a fixed factor in projects.

It has been demonstrated that the PVT technology in the climate conditions of this research work to the present day has a negative potential compared to the use of standard solar thermal collectors, mainly due to the inexperience on it and the still high price, but also influenced by climate of Sweden, due to the geographic country’s location. Currently, the potential of PVT has been more tested in the southern part of Europe indeed. The following aims set forth in this thesis have been reached:

o Perform simulations in TRNSYS, by adapting the project for a Swedish case study in Hemse, a town in Gotland, a Swedish island, and evaluate if the same positive results obtained in the Taars SDH plant could be achieved in the new boundary conditions;

o Conduct a techno-economical evaluation by adding in the system the PVT, by substituting a share of the FPC, and discuss if it could be a convenient investment or not based on the results obtained from simulations in TRNSYS and further economical calculations;

o Compare the better combinations obtained by the first and the second aim of the work, and decide what share of FPC, PTC and PVT best suits to the particular case study from an energy and economy point of view.

51

6 Future work

In this chapter, there are some suggestions for a future work with the purpose of continuing and getting a higher level of detail of the research project. Here following some points for the further development of the project:

o A detailed analysis on the variation of the electricity spot price over the entire duration of the investment of the project can be done. The electricity spot price is a parameter always changing and it depends on a significant number of variables which in turn depends on the equilibrium on the market. It is a complex calculation which can be deeply developed for the estimation of the electricity production from PVT in this project.

o In a further improvement of the model, a different configuration of solar collector share studied in this study could be simulated, for example, by fully removing the part of FPC, and simulate the system with the integration with PVT, or even only with PTC, to see if there are both improvement in terms of energy production and economy combined.

o The short-term diurnal storage used now in the system could be replaced with a long-term seasonal storage, to evaluate if solving the problem of mismatch of the solar availability can give positive effects in the overall evaluation of the project.

o The simulation of the hybrid concept studied can be simulated for location on southern Europe, to see if the different amount of solar radiation availability significantly affects the economy of the project.

o In the model used, the defocusing of the PTC is not taken into consideration. The implementation of the defocusing of PTC field when there is excess solar production could be an input for a future work.

o Due to its novelty on the solar market today, in the future there will be more information about the PVT. A more precise investigation on the weighing factor for both the electrical and thermal price of the collector could be done. To the present day, it is still not possible to find accurate and solid information about that.

52

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55

8 Appendices

Appendix A1

- appendix A1: datasheets of solar collectors

GREENone TEC single-glazed GK3133 S by Aalborg [45]

T160 by Absolicon [41]

56

aH72SK by Abora [55]

57

Appendix A2

- Pump curve and load profile for the solar pump

- Pump curve and load profile for the solar charge pump

58

- Pump curve and load profile for the boiler side pump

59

Appendix A3

- Total investment cost of the solar system

FPC share [%] PTC share [%] Low range [€] Medium range [€] High range [€]

100% 0% 958 084 € 1 373 400 € 1 765 800 €

90% 10% 1 032 365 € 1 386 469 € 1 817 922 €

80% 20% 1 053 908 € 1 399 538 € 1 819 199 €

70% 30% 1 075 451 € 1 412 608 € 1 805 279 €

60% 40% 1 096 993 € 1 425 677 € 1 782 215 €

50% 50% 1 118 536 € 1 438 746 € 1 752 690 €

40% 60% 1 140 079 € 1 451 815 € 1 718 213 €

30% 70% 1 174 806 € 1 464 885 € 1 679 747 €

20% 80% 1 191 954 € 1 477 954 € 1 637 955 €

10% 90% 1 209 102 € 1 491 023 € 1 593 321 €

0% 100% 1 226 250 € 1 504 092 € 1 546 212 €

- Annual operation and maintenance cost of the solar system

FPC share [%] PTC share [%] O&M low [€] O&M medium [€] O&M high [€]

100% 0% 1 173 € 1 173 € 1 173 €

90% 10% 2 071 € 2 293 € 2 920 €

80% 20% 2 967 € 3 411 € 4 257 €

70% 30% 3 862 € 4 529 € 5 473 €

60% 40% 4 757 € 5 646 € 6 615 €

50% 50% 5 651 € 6 762 € 7 704 €

40% 60% 6 545 € 7 879 € 8 754 €

30% 70% 7 439 € 8 995 € 9 772 €

20% 80% 8 333 € 10 111 € 10 763 €

10% 90% 9 226 € 11 226 € 11 731 €

0% 100% 10 119 € 12 342 € 12 679 €

60

Appendix A4

- Electricity consumptions of the pumps in all different solar system scenarios with FPC and PTC

Pump’s energy consumption

FPC share [%] PTC share [%] Total_solar side

[kWh/year] Total_boiler side

[kWh/year] Total_overallsystem

[kWh/year]

100% 0% 13 698 14 320 28 018

90% 10% 13 939 14 573 28 512

80% 20% 14 078 14 717 28 795

70% 30% 14 217 14 863 29 079

60% 40% 14 305 14 955 29 259

50% 50% 14 373 15 026 29 399

40% 60% 14 429 15 085 29 513

30% 70% 14 488 15 147 29 635

20% 80% 14 533 15 194 29 727

10% 90% 14 565 15 227 29 792

0% 100% 14 595 15 258 29 854

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Appendix A5

- Annual marginal operations cost for a short-term investment FPC/PTC combination (15 years)

FPC share [%] PTC share [%] low - 15y medium - 15y high - 15y

Marginal cost - 0 % maintenance for the boiler

100% 0% 24 244 € 56 183 € 86 360 €

90% 10% 27 408 € 54 816 € 88 494 €

80% 20% 26 780 € 53 713 € 86 658 €

70% 30% 27 548 € 54 006 € 84 953 €

60% 40% 28 793 € 54 776 € 82 964 €

50% 50% 30 310 € 55 817 € 80 708 €

40% 60% 31 867 € 56 900 € 78 082 €

30% 70% 34 499 € 58 042 € 75 183 €

20% 80% 36 023 € 59 430 € 72 252 €

10% 90% 37 775 € 61 044 € 69 311 €

0% 100% 39 660 € 62 792 € 66 298 €

Marginal cost - 2 % maintenance for the boiler

100% 0% 16 499 € 48 438 € 78 615 €

90% 10% 19 664 € 47 072 € 80 749 €

80% 20% 19 035 € 45 968 € 78 913 €

70% 30% 19 803 € 46 261 € 77 208 €

60% 40% 21 048 € 47 031 € 75 219 €

50% 50% 22 565 € 48 073 € 72 964 €

40% 60% 24 123 € 49 155 € 70 337 €

30% 70% 26 754 € 50 297 € 67 438 €

20% 80% 28 279 € 51 685 € 64 507 €

10% 90% 30 030 € 53 299 € 61 567 €

0% 100% 31 915 € 55 047 € 58 554 €

Marginal cost - 5 % maintenance for the boiler

100% 0% 4 882 € 36 821 € 66 998 €

90% 10% 8 047 € 35 455 € 69 132 €

80% 20% 7 418 € 34 351 € 67 296 €

70% 30% 8 186 € 34 644 € 65 591 €

60% 40% 9 431 € 35 414 € 63 602 €

50% 50% 10 948 € 36 455 € 61 347 €

40% 60% 12 506 € 37 538 € 58 720 €

30% 70% 15 137 € 38 680 € 55 821 €

20% 80% 16 662 € 40 068 € 52 890 €

10% 90% 18 413 € 41 682 € 49 950 €

0% 100% 20 298 € 43 430 € 46 936 €

62

- Annual marginal operations cost for a long-term investment FPC/PTC combination (30 years)

FPC share [%] PTC share [%] low - 30y medium - 30y high - 30y

Marginal cost - 0 % maintenance for the boiler

100% 0% - 7 544 € 10 616 € 27 773 €

90% 10% - 6 844 € 8 816 € 28 178 €

80% 20% - 8 187 € 7 279 € 26 300 €

70% 30% - 8 133 € 7 138 € 25 057 €

60% 40% - 7 603 € 7 474 € 23 833 €

50% 50% - 6 801 € 8 082 € 22 557 €

40% 60% - 5 958 € 8 731 € 21 074 €

30% 70% - 4 479 € 9 440 € 19 452 €

20% 80% - 3 524 € 10 394 € 17 907 €

10% 90% - 2 341 € 11 574 € 16 448 €

0% 100% - 1 025 € 12 888 € 14 998 €

Marginal cost - 2 % maintenance for the boiler

100% 0% - 15 288 € 2 871 € 20 029 €

90% 10% - 14 589 € 1 071 € 20 433 €

80% 20% - 15 932 € - 466 € 18 555 €

70% 30% - 15 878 € - 607 € 17 312 €

60% 40% - 15 348 € - 270 € 16 088 €

50% 50% - 14 546 € 337 € 14 812 €

40% 60% - 13 703 € 986 € 13 330 €

30% 70% - 12 224 € 1 695 € 11 707 €

20% 80% - 11 268 € 2 649 € 10 163 €

10% 90% - 10 086 € 3 830 € 8 703 €

0% 100% - 8 770 € 5 144 € 7 253 €

Marginal cost - 5 % maintenance for the boiler

100% 0% - 26 905 € - 8 746 € 8 412 €

90% 10% - 26 206 € - 10 546 € 8 816 €

80% 20% - 27 549 € - 12 083 € 6 938 €

70% 30% - 27 495 € - 12 224 € 5 695 €

60% 40% - 26 965 € - 11 887 € 4 471 €

50% 50% - 26 163 € - 11 280 € 3 195 €

40% 60% - 25 320 € - 10 631 € 1 713 €

30% 70% - 23 841 € - 9 922 € 90 €

20% 80% - 22 885 € - 8 968 € - 1 454 €

10% 90% - 21 703 € - 7 787 € - 2 914 €

0% 100% - 20 387 € - 6 473 € - 4 364 €

63

Appendix A6

- Marginal operations cost for a short and long-term investment in PVT parametric analysis

PTC share [%] FPC + PVT share [%] PVT share (of FPC share) [%] 15 y 30 y

Marginal cost including electricity savings from PVT - 0 % maintenance for the boiler

30% 70% 5% 82 156 € 30 909 €

30% 70% 10% 82 169 € 26 540 €

30% 70% 15% 82 187 € 22 178 €

30% 70% 20% 82 224 € 17 837 €

Marginal cost including electricity savings from PVT - 2 % maintenance for the boiler

30% 70% 5% 74 412 € 23 164 €

30% 70% 10% 74 424 € 18 796 €

30% 70% 15% 74 442 € 14 433 €

30% 70% 20% 74 480 € 10 092 €

Marginal cost including electricity savings from PVT - 5 % maintenance for the boiler

30% 70% 5% 62 795 € 11 547 €

30% 70% 10% 62 807 € 7 179 €

30% 70% 15% 62 825 € 2 816 €

30% 70% 20% 62 863 € - 1 525 €