Implementation of multiple solar heating systems into existing heat

Transcription

RAPPORT
Implementation of multiple solar heating systems
into existing heat distribution networks
FVF 01 12 33
December 2001
Implementation
of multiple solar heating systems
into existing heat distribution networks
L. ERIKSSON
July 2001
ZW
Energiteknik
1
Preface
Development and utilisation of solar energy systems have been an ongoing process
since more than 40 years back. The technical knowledge of solar collector systems of
today is very good, and a number of manufactures in Europe have reached some kind
of common sense regarding the design and technology used for various types of
systems. Still, there is much to learn about the implementation of solar systems to an
existing heat distribution network.
Solar heating is expected to become a more usual source for producing heat in heat
distribution systems in the future. In a number of other projects, for instance “Solar
Procurement” and “Solar heating in Central and Northern Europe”, the experience
shows that the interest for solar heating has increased rapidly among district heating
and housing companies. Of course, this presumes that solar heat production becomes
economically compatible to other forms of heating.
The interest for use of renewable energy technologies increases, and hopefully solar
energy will live on its own merits when a way of thinking is accepted that takes into
account the external costs of different energy forms, a thinking that must be applied
to obtain a sustainable society.
When it comes to solar heating, there are only a very small number of actors in the
energy business who have the means and are willing to take the economic risk of
investing in a large thermal solar heating plant. However, a discussion with several
energy companies in Sweden revealed an interest in solar energy, if the conditions
were right. A question raised was the possibility to implement a number of distributed
roof-mounted solar collector systems to the heat distribution network over a longer
period of time, this way spreading the investment costs over a greater time-span.
Thus, such a system would first start up with a very low overall solar fraction, until when it is finalised - having a solar fraction of 70-100% of the summer load.
Depending also on other production units - in a still longer view - we can also see
solar district heating systems covering more than 50% of the annual load by means of
seasonal storages.
This report investigates the possibilities of integrating successively a number of small
and medium sized, roof-mounted solar collector systems, each 500-5000 m² large, to
a heat distribution network, with the aim of covering an important part of the summer
load.
Acknowledgement
This work has been performed as a master thesis for Thermal Engineering at the
University of Dalarna, Solar Energy Research Center, Borlänge, Sweden. The study
was carried out at the consultant company ZW Energiteknik AB in Nyköping, Sweden.
This project has been ordered and financed by the Council of Swedish Building
Research (BFR) in co-operation with the Swedish District Heating Association (Svenska
Fjärrvärmeföreningen FVF), Birka Energi and the District Heating Utility of Enköping.
2
It is a great pleasure for me to acknowledge gratefully the guidance and assistance of
my supervisor, Dr. Heimo Zinko, ZW Energiteknik AB, who contributed with his long
experience on large solar collector systems to the project. Heimo Zinko contributed
also the chapters about solar costs and the solar market to the report.
Furthermore, I will express my gratitude to Mr. Björn Johansson who contributed with
all necessary information about the investigated area of Romberga, Enköping. Finally I
also would like gratefully to acknowledge the participation of the a reference group
who followed the work with large engagement and who contributed with a lot of
detailed information about solar and district heating systems, respectively. The
following persons were member of the reference group:
Maryam Hagh Panah, Birka Energi
Göte Ekström, FVF
Mikael Gustafsson, FVF
Björn Johansson, AB Enköpings Värmeverk
3
Sammanfattning
Denna rapport behandlar användning av takmonterade/takintegrerade solfångarsystem i utspridda geografiska områden inom ett befintligt fjärrvärmenät.
Solfångarsystemen ska producera energi i olika delar av fjärrvärmesystem som i
första hand är anslutna till befintliga eller nya servisledningar. En del av värmen kan
användas av närbelägna fjärrvärmecentraler. En större del levereras emellertid som
överskottsvärme till stamnätet och till en eventuell ackumulatortank.
En analys av ett typiskt fjärrvärmesystem har gjorts i en dynamisk systemmodell.
Modellen är baserad på det fjärrvärmesystem som finns i staden Enköping med en
nominell storlek av ca 100 MW och som årligen levererar 250 GWh till anslutna
konsumenter. En detaljstudie har genomförts på området Romberga med en representativ blandning av flerfamiljs-, enfamiljs- och industribyggnader anslutna till
fjärrvärme. Totalt är omkring 50 flerfamiljshus, 13 industribyggnader, 3 skolbyggnader och 80 enfamiljshus anslutna. Sommarlasten är ca 1 MW eller ca 25 MWh/dag.
Nätets längd är ca 5 km. De flesta stora byggnaderna är lämpligt belägna och
representerar en takyta på 26 000 m2, (enfamiljshus ej medräknade), av vilka 70%
skulle kunna utnyttjas för solfångare.
Den största begränsningen är servisledningarnas dimension: De existerande
servisledningarnas totala kapacitet kan precis klara 100% sommarsollast med 15
fjärrvärmecentraler anslutna till ca 7 200 m2 solfångare (alternativ B). Det visade sig
emellertid lönande att reducera antalet anläggningar och öka servisledningarnas
dimension vid några utvalda byggnader, vilket reducerade antalet solvärmeproducerande anläggningar till endast 3 (alternativ A).
Nätet analyserades med två simuleringsmodeller: TRNSYS för solvärmeproduktion och
LICHHEAT för dynamisk beräkning av tryckfall och av värmeleveransen från de
utspridda solvärmeanläggningarna till de olika kunderna. Den lämpligaste utgångspunkten för konstruktion av solvärmesystemet visade sig vara i form av en produktionsanläggning, dvs inkoppling mellan retur- och ingångsledning. Solfångarna arbetar
under större delen av dagen på fjärrvärmetemperatur, alltså 80 °C fram- och 50 °C
returtemperatur.
Som ett resultat av simuleringarna finner man att det inte är något problem att
ansluta ett större antal produktionsenheter till nätet så länge enheterna är anslutna
mellan retur- och framledning. Med omkring 2200 m2 solfångare installerade kan ca
30% av den dagliga sommarproduktionen alstras utan värmelagring. Vid större yta
måste lagring ske, eftersom möjligheten till värmelagring i returledningen är
begränsad och motsvarar ytterligare ca 10% av den dagliga sommarlasten. 7200 m2
plana solfångare kan producera ca 100% sommarlasten. I många fjärrvärmenät finns
redan värmelager (i Enköping på 7 000 m3, motsvarande Rombergaandel blir då
700 m3), alltså är förutsättningarna för solenergi idealiska.
Eftersom kostnaderna för solfångarsystem vanligtvis minskar med systemets storlek
är det lönande att reducera antalet solvärmeanläggningar och i stället använda så
stora solfångarsystem som möjligt. För Romberga uppnåddes detta genom installation
av nya servisledningar för två system. Därigenom kunde antalet produktionssystem
reduceras från 15 till 3, vilket reducerade totalkostnaden med ca 20 % till en specifik
investering av 6-8 SEK/kWh,år (Alternativ A). Detta motsvarar energikostnader på ca
4
50 - 65 öre/kWh (20 år, 5%). I dessa kostnader är inga värmelagerkostnader inkluderade. Ett nytt värmelager skulle fördyra systemet med omkring 5 – 10%.
Slutligen utvecklades en installationsstrategi för introduktion av solfjärrvärme i
Romberga. Strategin innebär installation av ett komplett system inom en period av 6
år, vilket ger tid till utvärderingsprocesser år 3 och år 5. I princip finns det naturligtvis
inget hinder för att påskynda eller senarelägga enstaka installationer. Fördelen med
ett större antal utspridda system (jmft med centrala system) är att dessa kan
installeras när den ekonomiska situationen, husrenoveringsplaner eller den lokala
stadsplaneringen är gynnsamma för investeringsbesluten.
I princip kan solvärmesystem av vilken storlek som helst anslutas till befintliga fjärrvärmesystem om bara tak- eller markytor finns tillgängliga. Det bedöms emellertid att
att utbyggnaden den närmaste tiden av ekonomiska orsaker endast kommer att ske
undantagsvis. Anledningen är att solvärme kommer i konflikt med sommarvärme från
främst sopförbränningsanläggningar och värmepumpar, vilka mycket ofta levererar
värme till lägre kostnader. Å andra sidan förväntas det också att solvärme, särskilt i
mindre fjärrvärmesystem, helt kan ersätta förbränningsanläggningar sommartid. I
detta fall bör tillsatsvärme komma från andra källor, främst elvärme.
Analysen kan summeras med följande sammanfattande slutsatser:
•
Takplacerade, utspridda solvärmeanläggningar, lämpligt placerade i systemets
olika grenar, kan komplettera befintliga fjärrvärmesystem.
•
En lämplig och enkel anslutning är som produktionssystem mellan retur- och
ingångsledning.
•
För mindre solfångarytor kan solvärmesystem anslutas via befintliga servisledningar.
•
Om stora takytor, t ex på industribyggnader, finns tillgängliga för solfångare, är
det lämpligt att konstruera en ny servisledning med större dimension.
•
Omkring en tredjedel av den dagliga sommarlasten kan levereras utan värmelager; vid högre solandelar måste värmelager användas. Vid 100% solandel en
solig sommardag borde lagervolymen vara omkring 0,1 m3 per m2 solfångare.
•
100% sommarlast motsvarar i Sverige 5 – 10% årlig last beroende på lastprofilen
och fjärrvärmesystemets storlek. Vanligtvis kan en högre årlig solandel uppnås i
mindre system än i större.
•
En tumregel är att för varje nominell MWth i fjärrvärmesystemet (beräknad
vinterlast) kommer det att bli 0,1 - 0,2 MWth sommarlast motsvarande 2,5 - 5,0
MWh daglig solvärmeproduktion, vilket tillåter installation av omkring 500 –
1000 m2 solfångare, beroende på systemstorlek och lastdistribution.
•
Investeringskostnader för ett solvärmesystem som täcker 100% av en varm
sommardag är 6 - 8 SEK/kWh,år exklusive lagringskostnader. Lägre kostnader
gäller för större anläggningar. Vid en utvecklad marknad (dvs minst 100 000 m²
årlig försäljning) förväntas kostnaderna kunna minska med ca 20% och vid en fullt
utvecklad europeisk marknad ytterligare något.
•
Potentialen för solfjärrvärmesystem uppskattas till ca 1 TWh solvärme per år,
motsvarande 2,5 miljoner m² solfångare. Vid ersättning av fossilt bränsle skulle
detta resultera i en minskning av CO2-utsläppen med ca 500 000 ton/år.
5
Summary
This report concerns the implementation of distributed roof mounted/roof integrated
solar heating systems in different geographical locations of an existing heat
distribution network. The solar heating systems are to produce energy in different
parts of the heat distribution network connected to existing or new service pipes. Part
of the heat might be used by the nearby consumer station(s), a large part, however,
is delivered as excess heat to the main network and, if existing, to the accumulatortank.
An analysis of a typical heat distribution system has been made to create a dynamic
system model. The model is based on the real district heating system of the village
Enköping with a nominal size of about 100 MW, supplying 250 GWh to the connected
consumers. A detailed study has been made for a local area called Romberga with a
representative mixture of multifamily, single family and industrial buildings connected
to district heating. Totally about 50 multifamily buildings, 13 industrial buildings, 3
school buildings and 80 detached houses were connected to the area. The summer
load was about 1 MW or ca. 25 MWh/day. The length of the network was about 5 km.
Most of the large buildings are suitably oriented, representing a roof area of
26 000 m², (single family houses excluded), of which 70% were selectable for hosting
solar heating installations.
The strongest restriction were on the service pipe dimension: The existing service pipe
capacity could just match 100% solar load with 15 consumer stations connected to
7200 m² solar collectors (Alternative B). However, it turned out to be economically
worthwhile to reduce the number of solar plants and increase the service pipe
dimension of some selected buildings, that way reducing the number of solar heating
plants to only 3 (Alternative A).
The network was modelled with two systems: TRNSYS for solar heat production and
LICHHEAT for the dynamic calculation of pressure drop and heat production from the
distributed solar plants and heat distribution to the different customers. The most
suitable basic design feature for the solar heating system was found to be that of a
production plant, i.e. collectors connected between the return- and the supply pipe.
The collectors are most of the day operating at district heating temperature, i.e. 80 C
supply and 50 C return temperature.
As a result of the simulations it was found that there is no problem to connect an
increasing number of production units to the network, as long as the units are
connected between return and supply. With about 2200 m² solar collectors installed,
30% of the daily summer production can be produced without heat storage. At larger
areas, storage must be used. The possibility of heat storage in the return pipe is
limited and corresponds to another 10% of the load, at most. Totally, 7200 m²
collectors correspond to 100% summer load. In many district heating networks, a heat
storage is already available, (in Enköping it is 7000 m³, the corresponding Romberga
part is 700 m³), hence the prerequisites for solar energy are ideal.
As the cost of solar collector systems usually are decreasing with system size, it is
worthwhile to reduce the number of solar plants and instead use as large collector
systems as possible. For Romberga this was achieved by installing new service pipes
for two systems. By this measure, the number of production systems could be reduced
from 15 to 3, reducing the total costs by about 20% to ca. 6-8 SEK/kWh,yr (Alter-
6
native A). This corresponds to energy costs of about 50 - 65 öre/kWh. In these costs,
no storage costs are included. A new storage construction would increase these costs
by about 5 to 10%.
Finally, an implementation strategy was developed. The strategy foresees to install the
complete system within a period of 6 years, giving time for an evaluation process after
some operational phases (year 3 and year 5). In principle, of course there is no hinder
to accelerate or decelerate the solar implementation process. The advantage of the
distributed systems is that they can be installed whenever the economic situation, the
house renovation plans or the local city planning facilitate the economic decisions.
In principle, solar heating systems of any size can be connected to existing district
heating systems, whenever roof or ground area is available. However, it is judged that
in the next time this will be the case only in some exceptional cases, for economical
reasons. The reason is that solar heat is conflicting with summer heat from waste
icineration plants and heat pumps, a. o., which very often can deliver heat at lower
costs. On the other hand, it is also expected that especially in smaller district heating
systems, solar heat can completely replace combustion plants in summer time. In this
case, auxiliary heat will be provided from other sources, f. i. electrical heaters.
The analysis can be summarised with the following concluding remarks:
•
Roof-located distributed solar heating plants, suitably localised in different
branches of the net, can complete existing district heating systems.
•
A suitable and straightforward connection is as a production system between
return and supply pipe.
•
For smaller solar collector areas, the solar heating system can be connected via
the existing service pipes.
•
If large roof areas for solar collectors, f. i. from industrial buildings, are available, a new service pipe with increased dimension is worth to be constructed.
•
About one third of the daily summer load can be supplied without heat storage;
at higher solar fractions, heat storage must be applied. The storage size is
depending on the solar fraction. For 100% solar summer load, the storage
volume should be about 0,1 m³ per m² solar collector
•
100% summer load corresponds in Sweden to 5 - 10% annual load depending
on the load profile and size of district heating systems. Usually in smaller
systems, a higher annual solar fraction can be achieved compared to larger
systems.
•
A rule of thumb is that for each nominal MWth of the district heating system
(winter design load) there will be 0,1 – 0,2 MWth summer load corresponding to
2,5 – 5,0 MWh daily energy supply, enabling the installation of about 500 –
1000 m² solar collectors, depending on system size and load distribution.
•
A solar heating system for diurnal storage will cost about 6 – 8 SEK per kWh
annually produced solar heat, storage costs not included. The lower costs hold
for larger plants. When the market further develops, it is expected that costs
will decrease by about 20%.
•
The solar district heating potential in Sweden is estimated to be 1 TWh/yr,
corresponding to ca. 2,5 millions m² solar collectors. When replacing fossil
fuels, this amount would reduce the C02 emission by 500 000 tons/yr.
7
Contents
PREFACE .......................................................................................................... 2
ACKNOWLEDGEMENT......................................................................................... 2
SAMMANFATTNING ............................................................................................ 4
SUMMARY......................................................................................................... 6
CONTENTS ....................................................................................................... 8
1
INTRODUCTION ..........................................................................................10
1.1
Background...................................................................................................10
1.2
Project suggestion ..........................................................................................10
1.3
Project evaluation ..........................................................................................11
2
HEAT DISTRIBUTION SYSTEM ANALYSIS .......................................................13
2.1
Enköping heat distribution network ...................................................................13
2.2
Boundary conditions .......................................................................................15
2.3
The Romberga network selection ......................................................................15
2.3.1
Network analysis .........................................................................................16
3
ANALYSIS OF SOLAR HEATING SYSTEMS .......................................................19
3.1
Solar collector control strategies and system design .............................................19
3.1.1
Supply-pipe connection ................................................................................20
3.1.2
Return-pipe connection ................................................................................21
3.1.3
Constant and variable flow alternatives ...........................................................22
3.2
Solar potential and different boundary conditions.................................................23
3.2.1
Basic dimensioning guide-lines ......................................................................23
3.2.2
Roof limitations...........................................................................................24
3.2.3
Service pipe limitations ................................................................................25
3.2.4
Romberga real-case application .....................................................................26
4
4.1
SYSTEM SIMULATIONS ................................................................................32
TRNSYS ........................................................................................................32
4.2
Dynamic pressure distribution system model.......................................................32
4.2.1
Basic model preparations..............................................................................32
4.2.2
Dynamic calculations ...................................................................................34
8
5 CONTROL OF HEAT DISTRIBUTION SYSTEM WITH APPRECIABLE SOLAR FRACTION
.....................................................................................................................37
5.1
Heat distribution network ................................................................................37
5.2
Accumulator options and demands ....................................................................39
5.3
Heat distribution network without accumulator ....................................................40
6
6.1
7
RESULTS ...................................................................................................43
Selected network - Romberga ..........................................................................43
ECONOMICS FOR SOLAR DISTRICT HEATING .................................................45
7.1
Size depending solar costs ...............................................................................45
7.2
Cost of solar heating systems ...........................................................................47
7.3
Solar costs in Romberga ..................................................................................49
7.4
Additional costs..............................................................................................50
8
8.1
IMPLEMENTATION STRATEGIES ....................................................................54
Heat distribution ............................................................................................54
8.2
Solar heating system ......................................................................................54
8.2.1
System with low solar fraction .......................................................................55
8.2.2
Successive transition to higher solar fraction....................................................55
8.2.3
System with high solar fraction......................................................................55
8.3
Heat storage .................................................................................................56
8.3.1
Centralised or decentralised storage ...............................................................56
8.3.2
Comments on storage corrosion problems .......................................................57
8.4
The market potential.......................................................................................58
8.5
Access to roofs ..............................................................................................59
8.6
Environmental aspects ....................................................................................61
8.7
Recommendations and conclusions....................................................................62
REFERENCES ...................................................................................................65
APPENDIX A - DH NETWORK SCHEME FOR ROMBERGA .........................................67
APPENDIX B: ..................................................................................................68
9
1
Introduction
1.1
Background
As an alternative to conventional heat distribution during the summer period (oil,
wood-pellet etc), it is of interest to examine the possibility of connecting solar heating
systems to the existing heat distribution network.
For solar heat generation into a local heat distribution network a large solar collector
field connected to an accumulator tank is often the best solution. In Sweden, this has
been done in a number of plants such as Falkenberg, Figure 1, Nykvarn and Kungälv.
This technique is well known and has been successfully used for the last 20 years.
However, this type of collector fields has a few drawbacks. One of them is a large area
demand, making it somewhat difficult to find a suitable location close to the heat
distribution network. The land area close to populated areas might also be too expensive for solar applications of this kind. Building a large solar collector system also
demands an equally large investment.
Figure 1:
1.2
Solar collector field in Falkenberg with 5.500-m²-collector area built in 1989
(Schroeder/Isakson 1994).
Project suggestion
Aside from one large solar collector field, there are some other alternatives. A possible
solution is to use several medium and small roof-mounted solar collector systems (500
∼ 3000 m² collector area) placed in different critical areas of the heat distribution net,
Figure 2. This alternative offers a possibility to include both architecture and functionality with solar collectors in today’s city scenery.
Solar systems of this kind may be placed in branches, or in other suitable points of the
heat distribution net, where the additional solar energy can be distributed. They do
not have any demand for available land-area as they are to be placed on existing
buildings. However, the operation control might be more difficult to be achieved due to
temperature and pressure variations in the heat distribution net. For every heat distribution source added into the net, controlling the system will become more complex.
This will be addressed in Chapter 3 and 4.
10
One large solar system will of course be economically superior to several small solar
systems, but one large solar system also demands a large investment cost at a given
time. With small systems, the energy-company has the possibility of gradually adding
solar systems to the heat distribution net over a period of time, evaluate them and
decide if, or when, it is economically reasonable to further move the project forward.
The solar system implementation can also be combined with planned roof renovations,
this way allowing it to be introduced in a less investment-intense way according to the
intentions of the building owners.
1
2
N
3
1. Solar system on school, 2. Solar system on multi-family dwelling, 3. Solar system on industry
Figure 2:
Possible layout for several roof-mounted solar collector systems connected to an
existing heat distribution net.
As a rough approximation we can state that the multiple small solar systems will
increase the total solar costs by at least 10-20% compared to the traditional largescale solar collector field of the same size. This is due to the use of a larger number of
smaller components and piping compared to a single collector plant.
A dialogue with energy companies shows that there is an interest in this type of thermal solar energy solutions, and that some of the companies would prefer to invest in a
number of smaller roof-mounted solar systems feeding the close-by district heating
net compared with a single large ground mounted solar collector field, despite the
estimated higher overall costs.
In the light of this, the project has a goal to determine the technical and economical
possibility to implement a disparate number of roof mounted solar collector systems
as separate heat producing units to an existing heat distribution network.
1.3
Project evaluation
In this project report there will be two different implementation methods investigated:
1. Prime heat – solar heat produced and delivered to the supply pipe of the heat
distribution network at a temperature required for the summer period (usually 7080 °C).
2. Pre-heating of main return flow – solar heat produced and delivered to the heat
distribution network return pipe.
11
Later it will be shown that the supply pipe solar implementation strategy in many ways
is to recommend. Also, the majority of energy companies do not want a solution that
increases the temperature in the return pipe, as this may interfere with future implementation strategies for other heat production plants.
12
2
Heat distribution system analysis
An absolute demand for future solar heat distribution systems to have a good
efficiency is that the temperatures in the heat distribution net can be reduced from
today’s values. The overall annual mean return temperature for the Swedish heat
distribution nets was in 1999 about 49.5 °C. During the summer period when the solar
system is operative, the return heat distribution temperature should never exceed
50 °C, but preferably always stay below 45 °C. This is possible to achieve in almost all
heat distribution networks, but it demands that the energy companies use a more
active and systematic control of networks and consumer substations. In Skogås/Trångsund, a smaller heat distribution system south of Stockholm, the yearly mean
return temperature for 1999 was 39.8 °C. Figure 3 illustrates temperature values for
57 Swedish heat distribution systems (Fjärrvärmebyrån, 1999). An analysis of the
reference heat distribution system used in this report, Romberga (Enköping), is made
in Chapter 2.3.
°C
100
90
80
70
60
50
40
Skogås / Trångsund
30
Known heat distribution technique
20
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56
Figure 3:
2.1
Temperature values for 57 Swedish heat distribution systems (Fjärrvärmebyrån,
1999).
Enköping heat distribution network
AB Enköpings Värmeverk / ENA Kraft AB is producing approximately 250 GWh
heat/year for district heating purposes. Aside from this, they also produce about 64
GWh electricity/year. The production mix is based on an 80 MW wood chip-fueled
boiler for combined power and heat generation (run time V.37-V.20), which is also
equipped with a stack gas condenser of 10 MW.
The main option for the summer period is a 25 MW pulverised wood-fired boiler. They
are also equipped with a 36 MW electrical boiler, a 25 MW oil-fueled boiler for peakloads, a 50 MW oil/gas boiler and two oil boilers of 10 and 20 MW for backup purpose,
see Figure 4. From May -97 to June -98 the degree-hours were 530 000 °C⋅h1),
1
)This degree-hour value is a measure of the relative heat loss of the distribution system, i. e. mean pipe
temperature (supply and return) minus mean air temperature. Values below 500 000 C h are considered
to be good net conditions.
13
corresponding to a mean T of 60,5 C. For solar energy applications, it is important to
decrease that value as much as possible in order to keep the collector mean temperatures low and hence achieving a higher solar efficiency, (see also Figure 9).
100
90
Oil
80
Power [MW]
70
60
P ulverized
wood
50
40
Woodchips
30
20
FGC
10
0
0
Figure 4:
8760
Time [h]
Heat production units used and available power during a production year, from left
showing peak load (-20 °C) to right showing minimum load (summer +20 °C).
In 1997-98, the mean temperature was 83.7 °C in the supply pipe and 49.3 °C in the
return pipe of the heat distribution network. Studies indicate a potential for lower
temperatures in the net. The heat distribution network temperature level is illustrated
in Figure 5.
Tf °C
Tr °C
dT °C
120
110
100
90
T dh [°C]
80
70
60
50
40
30
20
10
0
-20
-15
-10
-5
0
5
10
T amb [°C]
15
20
25
30
Figure 5: Forward (Tf), return (Tr) and difference temperature (∆T) as a function of the ambient
temperature (Ta).
14
2.2
Boundary conditions
As the full-scale heat distribution network of Enköping would be very complex and
time demanding to simulate, see Figure 6, this report will focus on a selected
representative part of the network, in the following called Romberga. This section of
the network is roughly a factor ten smaller than the total Enköping net, and should
have a reasonable mix of single- and multifamily houses, industries and schools etc.
Within this Romberga-project, the effort and possibilities to perform multiple advanced
dynamic simulations of all the different heat distribution network solutions is also
narrowed down to only include a one main scenario, simply illustrated in Figure 2.
The section selected will be analysed regarding heat delivery, temperatures, pressure
and pipe dimensions. The network will also be simulated in a dynamic system model
for analysing the flow behaviour under the varying solar conditions during the day.
Figure 6:
2.3
Overview of the heat distribution network in the city of Enköping
The Romberga network selection
When analysing the heat distribution network in Enköping one part of the city is
especially interesting and might be suitable for further evaluation. North of the city, a
distribution feed pipe supplies an area known as Romberga with energy. Romberga is
a populated area with about 10% of the total heat demand of the city.
15
The heat distribution network in this area is built as a typical 2-pipe system, i.e. one
supply pipe and one return pipe that are buried parallel to each other in a common
pipe trench. In addition, this area has a very representative mix of single- and multifamily houses, small and medium sized industries and a school. These factors together
qualify the area as a good reference system.
Figure 7:
Selected part of heat distribution network in Enköping to be analysed
2.3.1
Network analysis
In order to develop a good reference system for the heat distribution network and
later dynamic simulations, the entire pipe dimensions, pipe lengths and pipe connections must be determined. The total design power needed for heat distribution in
Enköping at a dimensioning outdoor temperature (DOT) of -18 °C is 130 MW. The
subscribed power for the Romberga reference area is ~12 MW. The subscribed power,
type of dwelling and possible available roof area for each consumer station is illustrated in Table 1. However, collected values from 1998 show that the real power PMAX
used for the heat distribution network of Enköping at –18 °C is only 80 MW, and for
the reference area Romberga only about 6 MW.
In Figure 8 the heat distribution network is illustrated in more details, showing
geographical locations of the consumer stations, nominal diameters, pipe length of
each section and possible roof area for solar collector installations. The length of the
pipe system is about 5 km, i.e. the nominal (winter) line density is about 1,2 kW/m.
16
Table 1:
Subscribed power and available roof area for each consumer station
Map Area No.
Subscribed
power [kW]
Available roof
area [m²] *)
Type
3:1, 3:2
719
1800
Multifamily dwelling (secondary system)
3:3
70
352
Small industry
3:5, 3:6
1150
2696
Industry
4:1
351
792
Industry
5:1-7:7
318
-
Single family houses
8:1-8:3, 9:1-9:5, 10:4
4778
4800
Multifamily dwelling (secondary system)
10:3
485
1104
Multifamily dwelling
10:5
405
976
Multifamily dwelling
11:4
988
5760
Industry
11:5
94
510
Small industry
12:1-14:6
165
-
15:1-15:9, 15:11:16:11 657
-
15:10
444
896
School
17:1-18:7
309
-
19:2
69
560
Small industry
19:4
210
384
Industry
19:5
205
648
Industry
19:7
206
608
Industry
19:8
387
712
Industry
19:9
81
792
Small industry
20:1
143
448
Small industry
27:1
318
1320
Industry
*) Refers to half the total roof area, which also usually is the maximum possible solar collector area on the
roof
17
∅15
0
K14 mfhs(sn)
4778kW
ν
17
0
4800m²
18
∅d i a m e t e r ν l eenn g t hh o f t r a c k
ν
costumer typ of costumer
max power
∅
65
42
6c
Zw
eig
6
K15 mfhs
405kW
main pipes
ν
976m²
13
0
K23 efhs
318kW
pipes, which are connected to costumer
K13 ind
94kW
nodes
half
of
17
the
roof
area
6d
∅
K16 mfhs
485kW
ν
10
7
510m²
ν 145
65
65
K27 mfhs(sn)
719kW
6b
16
∅ 30
ν
∅1 5
1104m²
0
1800m²
∅6 5
ν
K19 zfh
115kW
19
0
896m²
ν
3e
ν
30
24
ν
34
29
∅
2b
50
5
0
28
ν
2a
34
ν
72
K26 ind
70kW
32
∅
23
∅ ν
K29 ind
351kW
27
∅5 0
2c
ν 96
K18 efhs
165kW
K20 efh
110kW
3d
K19 efhs
161kW
ν 28
Zweig
ν 158
∅8 0
ν
56
ν 120
2
3c
K17 efhs
309kW
21
ν 54
3h
K25 efhs
161kW
∅3 2
∅2 5 0
∅5 0 ν
19
(∅ 1 0 0 ν
ν 87
384m²
ν
20
ν
8
40
K5 ind
205kW
ν
64
648m²
ν4
4b
∅1 c
K6 ind
387kW
14
10
ν 64
ν ∅1 d
2 25 0
ν 60
∅2 5 0 ν 1 3 8
58
ν
10
0
11
K7 ind
206kW
∅
12
K11 foom
1250kW
K10 ind
69kW
5b
608m²
∅3 2 ν 4 0
560m²
712m²
K4 ind
81kW
14
0
ν
792m²
1b
∅8 0
2
1a
∅80ν
1
Feed
point
Figure 8:
ν 50
Zw
ei
7
g
4 8
ν 132
3
26
∅2 5 0
9
20/4/20)
∅2 5 0
4a
K3 ind
210kW
1000
5
4
ν 48
3a
20
ν ∅
4465
ν 168
5760m²
20
0
ν
13
6
22
6
1
Zw
ei
g
∅1 0 0 ν 6 0
∅
55
32
48
ν
ν
ν
32
∅
∅8 0
∅1 0 0
3b
∅
Zw
eig
3
352m²
28
8040
ν 26
K12 ind
988kW
6 aa
15
K21 efh
110kW
25
K28 ind
318kW
792m²
13
0
K22 sk(sn)
444kW
3g
ν 20
1320m²
ν
80
8
026
3f
30
ν 10
∅ν
10
13
ν 196
5a
Zweig 5
6 52 4
52
K1 ind
575kW
896m²
∅ν
K2 ind
575kW
K8 ind
143kW
∅1 0 0
ν 146
K9 foom
750kW
1800m²
448m²
Analyse of the nominal pipe diameters, pipe lengths and nominal building power
use at DOT [-18°C]. (See Appendix A for an enlarged diagram of this map).
18
3
Analysis of solar heating systems
In this chapter the solar heating system will be discussed, regarding solar collector
load, solar collector control, solar collector system design, optimum solar collector
area for the heat distribution network in Romberga, optimum geographical localisation
of the solar collector systems and possible implementation methods.
Some values have been assigned regarding data for the heat distribution network, i.e.
temperature and pressure strictly valid only in a given system. In practice, these
parameters are never constant in time and vary depending on the type of heat distribution network, geographical locations, consumption and condition of the consumer
substations.
3.1
Solar collector control strategies and system design
With a directly connected solar system, the system is delivering heat to the primary
heat distribution net. There are two different technical alternatives in this study, in
which a flat-plate (FP) selective solar collector module is assumed. Comparisons with a
vacuum collector (ETC) regarding produced energy will also be made, see Figure 9.
Annual solar heat production
kWh/m²,yr
Flat - HT
Evacuated
800
700
600
500
400
300
200
100
0
0
20
40
60
80
100
120
Operation temperature / °C
Figure 9:
Comparison of produced energy in flat plate (TeknoTerm DT) and vacuum collectors
as a function of the mean collector temperature.
From this Figure it can be seen that the collector mean temperature and hence the
mean temperature of the DH-system is very important, as the following example
illustrates. If the DH supply temperature and return temperature are 80 and 50 C,
respectively, the mean temperature is 65 C, and the resulting T = 58 C with Ta =
7 C as the mean ambient temperature. Using a heat exchanger in the collector loop
will increase the mean temperature of the collector by about 5 C, thus the mean
collector temperature will in this case be 63 C. As can be seen from Figure 9, a
19
change of the mean collector temperature by 5 C (60 – 65 C) for FP results in a
reduction of the produced energy by ca. 7%. ETC collectors are less sensitive to heat
losses and therefore the energy reduction in the same temperature range is only 3,5
%, or half of that of the FP. Although ETCs are performing 30% better at DH temperatures than FP collectors, the collector costs are so far too high for allowing the
choice of evacuated collectors on an economical basis.
3.1.1
Supply-pipe connection
This system solution is suitable for existing buildings connected to district heating,
allowing for the most economic installation. The solar system will work as a heat
production unit in the heat distribution network, Figure 10. The system is mainly
designed for the summer period, where there is a low load and a high insolation.
Water from the service return pipe will be heated by solar energy and then delivered
to the service supply pipe (much like an ordinary production unit). Any excess heat
not used by the customers connected to the service pipe will be distributed to the
main heat distribution pipe. For this purpose, the distribution pump must be designed
to lift the pressure difference between forward and return pipe.
T stagnation
Solar collector
Consumer Station
HX
Solar
control
T solar.out
TDH2
Tsolar.in
Psolar.1
TDH1
HX-solar
Energy
measuring
Psolar.2
Service pipe
50°C
Main district heating pipes
100°C
Figure 10:
System drawing for roof-mounted solar collector with heat delivery to service
supply pipe.
A short system example may illustrate the working conditions for such a system. The
supply pipe pressure Psupp is 6 bar and the return pipe pressure Pret is 3 bar. A pump
will operate a field of 300 m² with a power of 1.5 kW with 1400 hours per year
operating time. This will need 2100 kWh electricity. The assumed temperatures in the
heat distribution network (summertime) are Ts=75 °C and Tr=50 °C. The solar circuit
20
operates at Tsolar out = 80 °C and Tsolar in 55 C resulting in an energy production of
370 kWh/m²,yr or 111 MWh per year for 300 m² FP collector. For a vacuum collector
the resulting energy production would be 550 kWh/m²,yr or 165 MWh.
3.1.2
Return-pipe connection
A solar collector circuit preheats the return flow from the customer substation before
entering the main return pipe. No greater pressure difference is expected in this case,
resulting in a smaller pump with less energy consumption. If there is no load in the
substation, the solar system will use water from the main return pipe. For this solution, a third pipe is needed to avoid recirculation of preheated return water, see Figure
11. This solution may only be of interest if district heating and solar heating is to be
installed at the same time or if very large solar collector fields are to be connected,
otherwise the cost for connecting a third pipe in buildings with already existing district
heating will be too high.
One of the design-demands for this type of solution is that the solar mass flow never
exceeds the heat distribution network mass flow, thereby avoiding re-circulation of
solar heated water. This is, however, difficult to control, as the heat delivery is set by
the present heat-load, which usually is quit low during daytime. Unfortunately, this is
when the solar heat production is at its peak.
T stagnation
Solar collector
Consumer Station
HX
Solar
control
T solar .out
TDH2
T solar .in
P solar .1
T DH1
HX-solar
Energy
measuring
P solar .2
Ser
vic
e
pip
e
50°C
Main district heating pipes
100°C
Figure 11:
System drawing for roof-mounted solar collector with heat delivery to service return
pipe.
For this case, assumed temperatures in the DH-network are Tf=100-75°C and Tr (from
main) =50° C. A typical high flow solution in the solar collector circuit will give collector temperatures of Tinlet=53 °C, Toutlet=63 °C, or Tmean=58 °C, resulting in a yearly
mean energy production of 400 kWh/m². For an evacuated solar collector, the resulting energy production is 575 kWh/m², year. That means that the return-pipe solution
could produce about 8% more energy for FP collectors but only about 5% more
energy for ETC collectors compared to the supply pipe-connection.
21
For the two cases described, estimations are used for temperatures and pressures in
the heat distribution network. During a year the temperatures will of course vary due
to the energy consumption in the buildings and also depending on the choice of
system solution, thereby resulting in a yearly mean energy production of 350-420
kWh/m² for the selective flat plate solar collector. For the evacuated solar collector,
the resulting energy production will be 540-600 kWh/m², year.
The energy production of solar collectors is calculated for the climate in Stockholm
region. Anti-reflective glazing has been assumed for the flat-plate selective solar
collector, as this has proven to give an increase of total heat yield for low additional
costs.
3.1.3
Constant and variable flow alternatives
There are two different options of how to control the output parameters from the solar
collector facilities, constant or variable flow. With a constant flow, the control system
will be simple and less expensive, and the output temperature will depend on the
insolation from the sun. A variable flow, however, will allow us to control the output
temperature, although within certain boundary conditions.
When constructing a solar collector system there is usually a hot water store (accumulator tank) dimensioned for storing the hot water produced. If the collectors work
against a stratified store, there is no need for a temperature control. The temperature
will instead stratify in the store and the total delivered energy will pretty much be the
same at the end of the day, see Figure 12.
GT
40-90°C
65°C
55°C
55°C
Solar
circuit
45°C
Hot water
circuit
35°C
Constant flow
Figure 12:
30°C
15°C
Simplified illustration of solar system with stratification in hot water store.
However, when the collectors produce energy to deliver directly to the primary heat
distribution network, there is often a specific supply temperature required. It is
therefore in this application of interest to obtain a set temperature from the solar
system that matches the heat distribution network temperature, especially during the
summer period. Especially in the supply-pipe connection, it will therefore be worthwhile to use temperature controlled collector flow rates, adjusting the solar collector
outlet temperature to the demanded DH supply temperature.
22
V·
Tdemand
H
.
Figure 13:
3.2
Volume flow V control for solar heating circuit as a function of solar irradiation H
according to different DH-demand temperatures Tdemand.
Solar potential and different boundary conditions
For solar heating systems, parameters such as available roof area and the quality and
dimensioning of the existing heat distribution network determine the possible solar
potential and implementation ratio. It is of importance that an on-site study is made
for each heat distribution network to evaluate if a desired solar-/district heating
solution is possible.
3.2.1
Basic dimensioning guide-lines
To know the possible energy transportation in different pipes, data from the Lögstör
catalogue has been used. Table 2 shows the relation between nominal pipe diameter,
mass flow, power and maximum solar collector area (calculated for net output of
500 W/m² solar collector). This knowledge combined with an inventory of suitable
roofs for solar collector use often gives a god preliminary understanding of the system
(see Table 3 for Romberga values).
23
Table 2:
DN ∅
mm
Mass flow, power and maximum solar collector area for different service pipediameters
Mass
kg/s
flow.
max,
Powersolar
(∆T30°C), kW
Areamax,
500 W/m²)
150
21.70
2732
5464
125
13.42
1690
3380
110
8.78
1106
2212
100
7.49
942
1884
80
4.41
555
1110
65
2.89
364
728
50
1.47
185
370
40
0.79
99
198
32
0.53
67
134
25
0.23
30
59
3.2.2
m²
(calc. for
Roof limitations
For an existing roof to be suitable for solar collector implementation, it must fulfil
certain requirements. The ideal slope of the roof is approximately 30° (this depends
on the location). If sloped, the roof area should also have a direction to south, ± some
deviation angle, at the most 45 . Flat roof-areas allow for optional placement (usually
directly south-orientated solar collectors with a mutual distance twice the collector
height), but here a support-frame must be built as well. Finally, the roof must be
constructed so that it is mechanically strong enough for solar collector placement the
next 20-30 years. These criterias help to create a first knowledge of the available roof
area.
At a closer inspection, many of the first suitable roofs show various problems such as
chimneys, ventilation exhaust pipes or other roof constructions not shown in the
technical drawings. Examples of this can be electronic equipment later installed such
as radio- and television receivers, parabolic antennas and maintenance equipment in
form of ladders and walkways on the roof, Figure 14.
Figure 14:
Study of a problematic roof with parabolic antenna, walkway and chimneys.
24
When inspecting the roof of interest it is also of importance to observe the surrounFigure 14
shown). Partially shading by trees (or other objects) will decrease the efficiency of
solar collectors.
With South as the angle 0° it is common to accept an angular displacement of ±
East of South are negative and West of South are positive. This is commonly known as
the
γ , shown in Figure
.
Zenith
Sun
N
N
W
S
Figure 15:
E
W
E
S
Sun
Solar azimuth angle γs
With an angular displacement, the total collected energy will be less than that of a
solar collector placed directly to the South. For countries in the Northern Hemisphere a
collector placed in Southeast direction will collect more energy during morning hours,
and a collector placed in Southwest direction will collect more energy during evening
hours. For the heat distribution network purpose a combination of South, Southwest
and Southeast collectors might from one point of view be useful, as the total delivered
energy will be distributed more evenly during the day, although somewhat lower.
However, with increasing azimuth angle the solar collector performance will decrease,
see Figure 16 2).
Regarding mechanically strength, roof constructions in Sweden must be dimensioned
to hold for snow loads. In South Sweden this means 50 kg/m². A typical solar collector
installation on the roof has an average weight of 15 – 25 kg/m². The most critical load
condition is that of solar collectors to be mounted on large horizontal roofs. Very often
concrete or steel beams are used as foundations for support structures, which has to
be fixed on the roof truss. Such constructions and its load impact must be judged in
each individual case. For tilted roofs, roof mounting or roof integration of collectors do
in general not impose a serious weight problem.
3.2.3
Service pipe limitations
Limiting problems can also occur due to limited capacity of service pipes. In that case
the roof area would be large enough for a larger collector field, but the dimension of
the service pipe is limiting the collector area that can be connected, as can be seen in
2
) The diagram was developed by Bengt Perers, Vattenfall Utveckling, see Zinko (1999).
Table 3. Here one must consider and compare the two options available in this case:
1.00
0.90
0.80
1.00
0.70
Correction factor K
90
0.90
75
0.80
60
45 Collector-Slope
0.70
30
towards Horizontal
[°]
0.60
0
45
Deviation
from South
15
90
(azimuth angle)
[°]
Figure 16:
Reduction factor k for solar output from collectors with different orientations.
1. Use only the collector size allowed by the service pipe connection. One then has to
find additional roofs to implement the total numbers of collector area wanted, with
an additional higher implementation cost. This means more production units, with
more control systems and a greater maintenance cost.
2. Open the trench and connect a larger service pipe to allow for a full-scale
implementation on the suitable roof. The additional cost for a new pipe should be
added to the total cost of the planned implementation and then compared with the
total cost of implementation if the same collector area must be built somewhere
else.
If the solar collector area to be added by using a new, larger service pipe is large
enough and the trench-length is reasonable, this can probably be a better solution due
to lower overall costs and a favourable system control situation.
3.2.4
3.2.4.1
Romberga real-case application
Roof area evaluation
An on-site study in Romberga shows that approximately 15 000 m² of the total
25 000 m² roof-area is not suitable for solar collector use. This is mainly due to nonsuitable roof construction, orientation or slope. In some cases, the buildings are also
part of a larger secondary network, which makes the heat delivery to the main
network more complicated. The geographic orientations of roofs for solar system
implementation are shown in Figure 17.
26
Figure
:
Solar system implementation with
When single-family houses and other small buildings in Romberga are not included,
the total available roof area (50 % of brut area) is 25 158 m². Out of these, 5950 m²
orientation. Of the 17 928 m² remaining (70 %), 7273 m², spread among 15 different
buildings, are most suitable to be used. The most common limitation is that the
If the total available area is divided by the number of roofs, this gives an average
solar collector system area. For Romberga the average area is 480 m². The total solar
collector system area, and will decrease with increasing average area. Therefore, it is
of interest to minimise the number of roofs and thus maximise the average area.
7 300 m² solar collectors. If the existing service pipes to the three largest buildings in
Romberga were replaced with bigger ones, this would result in an available area of
620 m², or an average solar collector system area of 2540 m². The locations for
these systems are shown in
18.
area of 1795 m².
27
Figure 18:
Solar system implementation for Romberga based on connections with increased
service pipe dimensions.
3.2.4.2
Solar collector efficiency
The solar collector performance or “collection efficiency” (ηc) can simply be defined as
the ratio of the useful gain over a specific time-period to the incident solar energy
over the same time period:
ηc = ∫Qu dt/(Ac∫GT dt)
(equ. 1)
Where: GT is the total solar irradiance on the collector surface [W/m²]
Qu is the useful energy output from the collector to the net [Wh]
Ac is the collector area [m²].
The total irradiance, the useful energy output and the collector efficiency for a flatplate collector positioned south with a collector slope of 30° is shown in Figure 19. The
weather data used for these calculations are from Stockholm 1986, which correlates
well with the geographic location and weather in Romberga (Enköping).
3.2.4.3
Solar fractions and collected energy
In Romberga solar fractions from 0-100% have been simulated to evaluate the number of solar collectors needed for different implementation stages. This is also of great
importance for later dynamic calculations, Chapter 4.3, as pressure, mass flow and in
some extent, temperatures will change with rate of implementation.
In Figure 20 three different solar fractions (for a sunny summer day) are illustrated
together with the average 24-hour summer load in Romberga. With 2100 m² of solar
collectors (3), the solar fraction is close to 30%, which in the Romberga case is also
the maximum theoretical solar fraction if no accumulator tank would be available.
28
Table 3:
Roof area criteria for Romberga
Map Area
No.
DN ∅
mm
Roof area Type
[m²]*
building
of Comments
3:1, 3:2
65
1800
3:3
32
352
3:5, 3:6
80
2696
Industry
4:1
50
792
Industry
8:1-8:3,
9:1-9:5
150
4800
Multifamily
dwelling
10:3
65
1104
10:5
65
976
Multifamily
dwelling
Multifamily
dwelling
11:4
100
5760
Large
Industry
11:5
32
510
Small
industry
15:10
50
896
School
19:2
32
560
Small
industry
19:4
50
384
Industry
19:5
65
648
Industry
19:7
50
608
Industry
19:8
40
712
Industry
19:9
40
792
Small
industry
20:1
32
448
Small
industry
27:1
50
1320
Industry
Multifamily
dwelling
Small
industry
Maximum
collector
area [m²]
Not suitable due to secondary system None
and also no large roof areas available
Pipe DN too small for first hand 134
choice, only 134-m² solar collector
possible.
Suitable roof, but service pipe 1110
dimension only allows 1110 m² of
solar collectors.
Flat roof in two stages, but ok for 370
solar
collectors.
Service
pipe
dimension only allows for 370 m² of
collector surface.
Not suitable for big solar collector 650
system due to secondary system.
Possible to use two roofs, with 650m² collector surface.
Only 325 m² area available due to 325
orientation of the buildings.
650 m² area available. Service pipe 650
dimension allows 728 m² of collector
surface.
Very big flat roof. Very good for solar 1880
applications. Service pipe dimension 5400 **
only allows for 1880 m² of collector
surface. Using larger service pipe
(DN 150) will allow for 5400 m².
possible.
Not possible to use due to unsuitable None
roof constructions.
possible.
Not suitable. Gas station with “open” None
construction.
Flat roof with “closed yard” in middle 620
of building, roof construction allows
for 620 m² of solar collectors.
Flat roof, but service pipe only allows 370
for 370 m² of solar collectors, and
building layout is not favourable.
Two connected buildings, service pipe 198
only allows for 198 m² of solar
collectors.
Square building, service pipe only 198
allows for 198 m² of solar collectors. 728 **
Using
larger
service
pipe
possible.
Also,
two
connected
buildings.
Big flat roof suitable for solar 370
collectors. Service pipe dimension 1110 **
*Half the total roof area, which also usually is the effective solar collector area
**
Available area if larger service pipe is installed
29
5100 m² of collectors and a 250-m³ hot water accumulator tank (2) would result in a
solar fraction of 70% and 7300 m² of collectors and 470 m³ accumulator tank (1)
would result in a solar fraction of 100%.
1000
ηc
50%
40%
Ac∫GT
600
30%
400
20%
∫Qu
200
Solar Efficiency [%]
Insolation and Gain [W/m²]
800
10%
0
0%
0
Figure 19:
5
10
15
Time during day [h]
20
25
Total insolation, delivered power and efficiency for a flat-plate solar collector facing
South with a slope of 30° during a sunny summer day.
3500
1.
3000
2.
Effekt[kW]
[kW]
Power
2500
2000
3.
1500
1000
500
Total summer load
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23
Tid [h/dygn]
Time
[h/day]
Figure 20:
Heat delivery during a sunny day for a solar fraction of:
1. 100 %, 2. 70 %, 3. 30 % (collectors facing South).
However, these accumulator tank volumes are based on the excess heat from the
solar collectors and the assumption that the load of other production units in the heat
distribution network can be controlled within the range 0-100%, which is usually not
the case in reality. The start-up and stop time for a medium-sized wood-fired boiler is
at least a couple of hours, making it both a time demanding and costly affair. Boilers
also have a design-value at which point it is not economically reasonable to use a
30
lower set-load. For this reason, most installations with wood-fired boiler plants are
using accumulators for load management. So is also the case in Enköping, where a
7000 m³ storage tank is installed. Therefore, in a real application this storage can
easily take up all the energy from the solar collectors (the storage would even suit the
energy from 100 000 m² collectors). Indeed the real problem is to operate this large
storage in summer time without too much degrading the temperature of the hot water
charge.
If we take the case of Romberga, about 750 m³ would be adequate for load case 1
(100% solar fraction) and only the upper most 5 m or 10% of the storage will be
active. During the summer period, when the load is low and we have a long period of
sun, the most suitable operating mode would be from the solar collector systems, the
storage and the electrical boiler. However, to operate large storages at very low loads
demands some more experience, which for the moment is lacking. Care must be taken
that the hot water strata at the top of the storage is not mixed into the remaining
water volume.
31
4
4.1
System simulations
TRNSYS
A solar system model has been created and simulated in TRNSYS, a solar simulation
program. With TRNSYS, it is possible to simulate detailed system layouts for the solar
heating systems and to analyse the function of the solar circuit for different parameter
set-ups with time varying conditions. Although the solar system circuit is well documented, the simulations based on TRNSYS do not include any dynamic pressure
calculations. Therefore, pressure gradients and their influence on the flow distribution
are calculated separately by means of the network-planning program LICHHEAT, see
Chapter 4.2.
The solar system model in TRNSYS, Figure 21, was designed mainly to evaluate the
amount of energy available from the collectors during a sunny day, by calculating
energy production, heat losses, mass flows and temperatures in solar and heat
distribution networks. The model was also used to simulate the possibilities to store
energy in the heat distribution return pipes and how this would affect the solar
collector efficiency and the heat distribution network. This will be described in
Chapt. 5.3.
The heat distribution network is simulated for 3 different solar fractions, 30, 70 and
100%, respectively. The locations of the collector systems are shown as light-blue
triangles in the network model of Figure 22.The results from the TRNSYS simulations
are summarised in Excel calculations as the amount of solar collectors needed in each
system, Figure 23. These calculations are based on hourly values showing delivered
solar energy, total energy needed and mass-flows for the given set of parameters.
These hourly values are essential for the dynamic pressure simulation of the heat
distribution network.
4.2
Dynamic pressure distribution system model
For consumer stations (or substations) in the network, it is important for their control
function that the differential pressure between supply and return pipe never drops
below one bar (100 kPa). For a heat distribution network with one production unit, the
main distribution network pump controls this by maintaining a constant differential
pressure at the point in the network that has the lowest differential pressure. If the
heat distribution network includes more than one production unit, the differential
pressure will depend on the amount of heat and mass flow distributed from the
different units.
4.2.1
Basic model preparations
For the dynamic calculation, a simplified network model of Romberga was created,
Figure 22. The instantaneous summer load for the network is 1000 kW and the total
length of the simplified network is 3000 meters.
32
33
Pcoll
Tin
21:
Return pipe
Supply pipe
Tin
min
Tout
min
Tsup
Tset
Data
reader
Reg
Time dep.
forc.function
TDHset
Tbot
Reg
Ttop
Tamb
GT
TRNSYS system model including: Solar system. consumer
station, accumulator tank and heat distribution network for Romberga
min
Radiation
processor
Weather data
reader
Tret
Pcoll
Tin
min
Radiation
processor
Tin
min
Tout
min
Data
reader
Tset
15150
∑load = 1000 kW
∑pipe = 3050 m
15100
400kW
15050
1 = NodNumber
A21/ A22 = Supplypipe/Return pipe
15000
85kW = subscribed power
17
Ø100 = pipe diameter
14950
200m = pipe lenght
Ø150
430m
9
14900
A11/ A12
130kW
14850
16
14800
Y
[m
]
80kW
7
Ø80
14750
A17/
Ø1
40
00
0m
A18
200m
30kW
14700
Solar.1
14650
6
5
15
15
0m
Ø100
250m
8
A15/ A16
4
170m
14550
2
Acc.tank
14450
1
A8
A7/
10
Ø65
120m
A2
7/
A2
8
14
Ø150
90kW
12
A23/ A24
11
A14
A13/
3
Ø100
260m
A5/ A6
Ø1 12
50 0m
A4
A3/
Ø80
Ø1
190m
50 10
0m
A1/ A2
75kW
A30
A9/
A10
Ø1
50
140m
Ø150
14600
14500
80m A29/
A21/ A22
Ø50
60m
A19/
A20
Solar.3
Ø100
Ø8
35 0
0m
A25/ A26
40kW
Solar.2
13
85kW
14400
Prod-facility
70kW
14350
44400
44450
44500
44550
44600
44650
44700
44750
44800
44850
44900
44950
45000
45050
45100
45150
45200
45250
45300
45350
X [m]
Figure 22:
Simplified heat distribution network in Romberga.
DH:
Tf=
Tr=
Cp=
P.DUT=
DH:
Tf=
Tr=
Cp=
P.DUT=
DH:
Tf=
Tr=
Cp=
P.DUT=
80
50
4,12
14562
°C
°C
kJ/kg.K
kW
80
50
4,12
14562
°C
°C
kJ/kg.K
kW
80
50
4,12
14562
°C
°C
kJ/kg.K
kW
SOLAR:
S1:
As=
500
Ts.f=
85
Ts.r=
55
Cp.s=
3,76
SOLAR:
S1:
As=
1165
Ts.f=
85
Ts.r=
55
Cp.s=
3,76
SOLAR:
S1:
As=
1665
Ts.f=
85
Ts.r=
55
Cp.s=
3,76
S2:
670
85
55
3,76
S2:
1570
85
55
3,76
S2:
2245
85
55
3,76
S3:
1000
85
55
3,76
S3:
2330
85
55
3,76
S3:
3330
85
55
3,76
Stot
2170 m²
°C
°C
kJ/kg.K
Stot
5065 m²
°C
°C
kJ/kg.K
Stot
7240 m²
°C
°C
kJ/kg.K
EFF:
1
Ps=
1,7
Pn=
5,5
eta.s= 30,0%
2
2,2
7,4
29,9%
3
3,3
11,0
30,0%
tot
7
MWh
24
MWh
30,0% %
EFF:
2
5,2
7,4
70,0%
3
7,7
11,0
70,0%
tot
17
MWh
24
MWh
70,0% %
1
Ps=
3,9
Pn=
5,5
eta.s= 70,0%
EFF:
1
2
3
tot
Ps=
5,5
7,4
11,0
24
MWh
Pn=
5,5
7,4
11,0
24
MWh
eta.s= 100,0% 100,1% 100,0% 100,1% %
Figure 23:
Basic data from Excel that describes the amount of solar collectors needed for the
three simulated solar systems according to Figure 22.
4.2.2
Dynamic calculations
The dynamic simulations3) show that pressure differences in the heat distribution
network due to variation in solar energy output are very small, and can therefore be
neglected. The reason is that the net is dimensioned for much larger flow rates
corresponding to the winter load. The main heat distribution pump therefore controls
the pressure difference in the lowest point of the net, allowing the solar systems to
have a simple control function. Figure 24 illustrates the resulting flow rates in the heat
distribution network for a solar fraction of 100% during a day with high insolation.
3
) The Lichheat calculations were performed by Gunnar Larsson, Chalmers Energiteknik.
34
Negative flow rates show that the flow direction in the network has changed. Excess
heat will be stored in the accumulator tank.
10
1
5
2
flowrate [m³/h]
0
3
-5
-10
-15
-20
0
2
4
6
8
10
12
14
16
18
20
22
24
time [h/day]
Figure 24:
Dynamic simulation results for flow rates at 100% solar fraction in:
1. Node 1-2 (main production unit), 2. Node 8-12 and 3. Node 4-5. Negative flow
rates indicate flows towards the accumulator.
solar collector
area m²
K14 mfhs(sn)
4778kW
18
customer typ of customer
max power at DUT
e6
Lin
Main production
K15 mfhs
405kW
Solar production
nodes
K13 ind
94kW
K23 efhs
318kW
17
16
K16 mfhs
485kW
K27 mfhs(sn)
719kW
K22 sk(sn)
444kW
26
K19 zfh
115kW
Solar.1
A=500 m²
K28 ind
318kW
K12 ind
988kW
15
25
24
K18 efhs
165kW
K20 efh
110kW
29
K26 ind
70kW
Solar.3
A=1000 m²
K21 efh
110kW
K19 efhs
161kW
23
3
Line
28
K17 efhs
309kW
21
22
20
9
K29 ind
351kW
27
10
19
K25 efhs
161kW
Lin
e2
5
6
11
Line 4
4
1
K3 ind
210kW
K5 ind
205kW
7
K11 foom
1250kW
14
K7 ind
206kW
K6 ind
387kW
K10 ind
69kW
12
8
Line
K4 ind
81kW
3
13
2
1
Feed
point
Figure 25:
Line
5
K2 ind
1150kW
K1 ind
K8 ind
143kW
Solar.2
A=670 m²
K9 foom
750kW
Flow chart at 12.00 a.m. for a day with high insolation. 2170 m² of solar collectors,
approximate solar fraction 30% - case 3, no accumulator tank.
35
From Figure 24 and Figure 25 it becomes clear that the system dynamic with several
parallel and dispersed production units becomes more complex. The reason is that the
excess heat from local solar heating plants will be transported either to other loads,
were it can be consumed, or to the accumulator. Because heat is delivered from the
solar circuit-supply pumps towards the main supply pipe and the production pumps
are flow controlled, the flow direction will point towards points of lowest pressure,
which is at the accumulator or at local heavy loads. Therefore, the flow will automatically reverse under such conditions. Even if there is no accumulator (at solar fractions below 30%) the flow can reverse in some branches with excess heat generation
and be directed towards other nearby loads. Flow conversion can therefore arise at
several pipe sections and for parts of the day, depending on load and solar conditions.
In certain nets, this can cause some extra problems. It has been observed that
reversed flow can detach pipe sediments which otherwise would be settled in the
pipes. If the flow is reversed, filters will not prevent the transport of sediments to
sensitive components such as meters, valves and heat exchangers. However, after a
couple of hours, the flow will be redirected and suspended material can reach the
filters again the normal way. In any case, it is recommended to control filters and
other components in the beginning of the solar operation more often in order to see, if
flow reversion has some impact on sediment transport in a given net.
36
5
Control of heat distribution system with
appreciable solar fraction
One of the most important factors is the control of the heat distribution network,
which in some cases can be a very complex task, especially as the solar fraction
increases.
5.1 Heat distribution network
A basic heat distribution network usually controls the amount of heat-delivery during
the seasonal changes by changing the supply temperature as a function of the outdoor
temperature. At outdoor temperatures above “break-point” (usually -3 to +10°C), the
supply temperature is constant; in the Enköping case the break point is about 10 °C
and the supply temperature is 78 °C (see Figure 5). In summertime, at outdoor
temperatures above 17 °C, there is no need for space heating and the heat demand in
the network can be considered “constant” with some exception for morning and
evening variations.
Variations in the heat distribution network with one production unit are controlled by
the main distribution network pump maintaining a constant differential pressure at the
point in the network that has the lowest differential pressure. If the heat distribution
network holds more than one production unit, the differential pressure will depend on
the amount of heat produced from the different units. Figure 26 illustrates a typically
heat distribution network configuration with pressure difference control.
In district heating solar systems, the heat production is automatically controlled by the
available irradiation, and not by the heat demand of the consumers, which is the
normal case for production units. This means that the solar heat distribution pump
(6.) continuously will adjust the flow-rate to maintain the set supply temperature, and
thus deliver a mass flow that varies depending on insolation. Hence the solar
production unit will not be controlled by the lowest differential pressure. However,
with the main distribution pump (4.) already using this type of control, there is no
need for additional control systems. If the solar heat production to the heat
distribution network increases, this will automatically lead to a decreased mass flow
and therefore heat delivery (the temperature is separately controlled) from the main
production unit according to the set pressure difference.
37
tf = konst
6.
1.
5.
solar collectors
tsf = konst
Return pipe
Pmin = konst
Supply pipe
tvv = konst
consumer
ta
trf
4.
tf
TT3
TT2
Accumulator
TT1
steam pillow
3.
Pmin = konst
2.
ta
Figure 26:
Concept of controlling the heat distribution network.
A supply pipe temperature sensor in the heat distribution network (1.) controls the
heat delivery from production unit (2.). Pressure in the return pipe before distribution pump is held constant by the accumulator tank (3.). Pressure difference in
the end-point of the heat distribution network controlled by the distribution pump
(4.). Variable flow in the solar loop (5.) control solar output temperature and
variable flow of primary solar pump (6.) control output temperature to heat
distribution network supply pipe.
38
5.2 Accumulator options and demands
As the solar fraction in the heat distribution network increases, so does the need to
accumulate excess heat. If the main heat production is based on renewable energy
such as pellets or other wood products, the plant is often somewhat “slow” to adapt to
heat demand changes in the network. It is therefore very likely that these plants are
equipped with some hot water accumulator, which allows for a more calm operation of
the production unit and also better economic and environmental criteria. If however,
heat storage does not exist, it should be built and integrated to the heat distribution
network whenever the daily solar fraction exceeds ca. 30%.
Steam pillow
TT1
Accumulator
Productionunit
Supply pipe
TT2
Return pipe
TT3
Figure 27:
Simplified concept of accumulator connection to the heat distribution network.
Enköping heat distribution network has an accumulator tank with a volume of
7000 m³. When it is fully charged it can supply the heat delivery for approximately 3
days. Usually a heat distribution network based on renewable energy such as biomass
has this kind of arrangement. As Romberga is considered a small reference system to
Enköping, the equivalent accumulator size would here be 700 m³. For a solar fraction
of 100%, the storage volume must be at least 460 m³ to store excess solar heat. This
leaves 240 m³ or more (at not so sunny days) of accumulator volume for load
management of the main production unit.
A rule of thumb is that the accumulator should have enough volume to store solar
heat but still also be able to work with the main production unit.
39
5.3 Heat distribution network without accumulator
If the heat distribution network does not have an accumulator tank available, the
expectations for the solar system efficiency is likely to decrease with increasing solar
fraction. Without an accumulator, there is no possibility to store excess heat other
than increasing the supply temperature or to use the distribution network return pipes
as hot water storage. However, too much excess heat will lead to an increased return
temperature and therefore increased solar collector supply temperature and reduced
solar system efficiency.
For a daily solar fraction of less than 30%, the lack of hot water storage should not be
a problem as the maximum solar power only reaches the maximum consumption in
the heat distribution network, Figure 20. No, or very little, excess heat will be
produced. As the solar fraction increases, so do the excess heat and thus the need to
store this excess heat. It is therefore of interest to evaluate the amount of possible
energy storage in the return pipes, and the time-span available before this has an
influence on solar collector performance. Total length and volume of network for these
calculations are shown in Table 4.
Table 4:
Total length and volume for Romberga network
DN ∅ [mm]
Length [m]
supply + return
Volume [m³]
supply + return
250
1368
67.16
200
272
8.54
150
876
15.48
100
1212
9.52
80
1180
5.94
65
924
3.06
50
2292
4.50
40
538
0.68
32
636
0.52
25
148
0.08
Total
9446 m
115.5 m³
Knowing length and volume of network, TRNSYS simulation according Figure 20 to will
show that the possibilities to store solar heat in the return pipe are very limited.
Equation 2 shows the average diameter in the heat distribution network of Romberga
and equation 3 the volume flow.
DNaverage = √(4Vr/πLr) = 124,8 [mm]
(equ. 2)
Where: Vr is the total volume in the return pipe [m³]
Lr is the total length of the return pipe [m].
The average volume flow for some given loads is illustrated in Figure 28, but can also
be expressed as
V& = (πd2v)/4 = (πDN2average · v)/4
[m³/s]
Where: v is the velocity [m/s] at a given load.
40
(equ. 3)
Figure 29 shows the amount of excess flow that is re-circulated into the return pipe
during the day if no accumulator tank is available. For re-circulation to occur, the heat
distribution network must also be equipped with some short circuit connections. These
are usually placed at consumers in distant points or with low consumption otherwise
the net might have a problem to stay at the required temperature. The total time to
load the heat distribution return pipe with excess heat as a function of different solar
fractions is shown in Table 5. The time-factor to load the return pipe is calculated for
an average hourly insolation and volume-flow during solar collector operation of a
sunny day.
Table 5:
Average time to load the return pipe in the heat distribution network
Solar fraction Collector
(Daily load) area
[m2]
[%]
Solar load Average
.
power
[kWh/day] [kW]
Accumulator
need
[m³]
Time to load
return pipe
[min]
30%
2170
7200
600
6
-
40%
2900
9600
800
54
-
50%
3615
12000
1000
115
176
70%
5065
16800
1400
245
154
100%
7240
24000
2000
460
101
4000
140
100%
3500
120
3000
power [kW]
2500
80
50%
2000
60
1500
30%
flow [m³/h]
100
70%
40
1000
20
500
0
0
0
3
6
9
12
15
18
21
24
time [h/day]
Figure 28:
Delivered power and flow rate from solar collector systems for solar fractions
30-100%.
41
90
flow [m³/h]
80
70
60
50
40
30
20
10
0
0
3
6
9
12
15
18
21
24
time [h/day]
Figure 29:
Amount of re-circulation flow in heat distribution network return-pipe if no
accumulator is used, for solar fractions 30, 50 70 and 100%, respectively.
Treturn.solar = 80°C
Treturn.main = 75°C
Heat distribution network
HX
Solar collector system
Tsupply.main = 80°C
Tsupply.solar = 100°C
Temperature scenario when network return pipe is used as accumulator
Figure 30:
When the distribution network return pipe is completely loaded with solar heat, the
entire network will hold a temperature level of let’s say Tf = 80 °C and Tr = 75 °C
(Figure 30). The temperature increase in the main return pipe will cause a similar
increase in average solar collector outlet temperature due to a limit of the maximum
speed of the solar circulation pump. Thus, the average solar collector temperature will
increase and the collector efficiency will in this case decrease as can be seen from
Figure 31.
Collector heat production
Ta = 20°C, H = 800 W/m²
700
Q (W/m2)
600
500
400
300
200
100
0
0
50
100
150
200
Ta (°C)
Figure 31:
Collector heating power as a function of mean collector temperature, the same
collector as in Figure 9.
42
6 Results
6.1 Selected network - Romberga
In the district heating area of Romberga, a solar implementation of 100% based on
existing service pipes is technically possible. The possible collector area is according to
Table 3 7273 m² distributed among 15 different buildings. Simulation according to
Figure 23 indicates 7240 m² of needed collector area for full solar fraction. However,
to build 15 solar systems out of which 13 have an area less than 650 m² on 15
different buildings will not be the best technically or economically acceptable solution.
Instead, it can be worthwhile to just concentrate on some larger buildings and invest
into some new service pipes.
If the service pipe connections at 2 of the 3 best suitable buildings are replaced with
larger pipes, Table 6, available roof area for these 3 buildings will be 9800 m² and
possible collector area 7600 m².
Table 6:
Map Area
Selection of most suitable roofs in Romberga
mm
Roof area Type
[m²]*
building
3:6
80
2696
Industry
11:4
100
5760
Large
Industry
27:1
50
1320
Industry
No.
DN ∅
of Comments
Collector
[m²]
area
Suitable horizontal roof, but service 1110
pipe dimension only allows 1110 m²
of solar collectors.
Very big horizontal roof. Very good for (1880)
solar
applications.
Service
pipe 5400
dimension only allows for 1880 m² of
collector surface. Using larger service
pipe (DN 150) will allow for 5400 m².
Big horizontal roof suitable for solar (370)
collectors. Service pipe dimension 1110
*Half the total roof area, which also usually is the effective solar collector area
Based on the selection table above, the implementation of solar collector systems in
Romberga can be performed in different stages. Below is an example of a possible
implementation scenario for a period of six years based on roof selections according to
Table 6:
Year 1: An 1100 m² solar system is built on building 3:6. Existing service pipe DN80
can be used. The solar fraction will be 15%. The supplied energy will be
absorbed directly by the load. This installation can be built very fast and costeffective on the flat roof of the building.
Year 2: Another solar plant 1100 m² solar system is built on building 27:1. The solar
fraction will increase to 30%. The existing DN50 service pipe must be
replaced with a DN80. The produced solar energy is still absorbed by the load
without storage.
Year 3: Operation and system evaluation. Now we have two distributed systems in
operation and a year of operation and evaluation is recommended in order to
study the dynamic behaviour of the system.
43
Year 4: A third solar heating system with 2700 m² collectors is built on building 11:4,
including preparation for another 2700 m² at a later stage. This will add
about 35% of solar fraction and hence the total solar fraction will be 65%.
The existing DN100 service pipe must be replaced with a DN150. During a
day with high insolation approximately 220 m³ of excess solar heat must be
stored in the accumulator tank.
Year 5: Operation and system evaluation. The 5th year should be used again for
system evaluation and operating experience for three parallel solar heating
plants.
Year 6: Finally, the solar heating system on the large industry building 11:4 should
be completed with another 2700 m². This will result in 100% solar covering
of the daily summer load. 500m³ storage volume has to be used to balance
the daily energy need.
If Romberga would be a separate distribution net, an accumulator tank of 500 m³ for
covering the excess energy production from the solar collectors during the day would
be needed, see Figure 32. However, for co-operation with other production units as
well, as an ideal size for an accumulator tank at least 700-800 m³ is recommended. In
this case, the basic heat production units would not be so vulnerable to variations in
solar heat production.
4000
60
1
3500
40
20
Power [kW]
4
2
2500
0
2000
-20
1500
-40
3
1000
DH-flow [m³/h]
3000
1 Total flow
2 Flow from
DH-pump
3 DH-load
4 Solarproduction
-60
500
-80
0
-100
0
2
4
6
8
10
12
14
16
18
20
22
Time during day [h]
Figure 32:
Delivered power from the 3 solar systems at 100% solar fraction, and also the
resulting flow in the heat distribution network.
44
7 Economics for solar district heating
7.1 Size depending solar costs
In Sweden a 25 years long history exists for large solar collector systems and also
their costs. It is connected with the Swedish effort of building large solar district
heating systems. The price development is illustrated in Figure 33 (for more details
see Zinko/Dalenbäck, 1996).
SEK/kWh per year
Solar costs
30
25
20
15
10
5
0
Ground placed
Roof integrated
Total solar costs
75
85
95
year
Figure 33:
Price development for large solar collector systems (price level 94 for all plants
except the most recent ones).
From this Figure it gets evident that solar collector systems followed a learning curve.
The price of large collector fields decreased roughly by a factor 3 during the last 20
years, i.e 6% per year. Today the costs for a ground installed collector field of
10 000 m² is roughly 1400 SEK/m² or 3,5 SEK/kWh,yr (Kungälv). The costs for roofintegrated systems are of the same order of magnitude although the field size is much
smaller, 500 – 1000m² (the value for the 1999 plant is for only 200m² roof integrated
collector in a new-construction). The system costs including short-term storage piping,
circulation equipment and control system usually add an important cost to the
collector cost, from about 100% for smaller systems to 50% for larger ones.
Contrarily, medium sized systems (several 100 m²) to be installed at existing
buildings can cost a lot more. The reasons are costs for projecting, piping, roof
adjustments, security devices and so on. Especially in high buildings, these costs can
become an important part of the solar costs. Similar holds for systems for new
buildings that are not planned in an integrated way as could be done in the course of
an early planning, but which are designed as separate systems. However, in
Gothenburg a series of projects have been built were integrated solar collectors exhibit
the low costs shown in Figure 33.
In the solar heating R&D program carried by STEM and Vattenfall 1996-1999
(Helgesson et al., 2000) a series of projects have been built with costs between 10
45
and 15 SEK/kWh,yr. Furthermore a series of projects have been investigated in predesign studies showing (not yet verified) costs just below 10 SEK/kWh,yr. Hence in
this last designs, solar collector costs (mounted on roofs) are usually around 2000
SEK/m² and the remaining costs are roughly between 1000 and 2000 SEK/m²,
depending on the type of building, roof and system size. In general, it can be stated
that the solar collector costs (per m²) as well the costs of the circulation system and
the storage decrease with the size of the system.
Studies giving some basic relations for size depending costs have been performed by
Dalenbäck/Åsblad (1994) and by Mangold (1995). Such costs as a function of the
collector field from both reports are summarised in Figure 34.
SEK/m2
Cost of solar fields
7000
6000
5000
4000
3000
2000
1000
0
100
Sweden
Denmark
Germany
1000
10000
m²
Figure 34:
Solar collector costs as function of collector area. Costs for Sweden from
Dalenbäck/Åsblad (1994) and for Germany and Denmark from Mangold (1995).
The costs for the three countries are not completely comparable as they are from
different years. The conversion rate for DEM to SEK was taken to be 1:4. However,
the trend is quite clear, the specific costs per m² collector area decrease with the size
of the total field. This holds for as well ground-installed as roof-mounted collectors,
but not necessarily equally strong for roof-integrated collectors (roof-integrated
collectors are roofs where the collector is part of the roofs tightening function. In such
systems, the collector is part of a roof section and less dependent on collector field
size).
As to Romberga, we have according to Table 3 a spectrum of possible collector fields
between 132 and 5400m², which means a variation of the collector costs by a factor 2
(taking the Swedish cost curve from Figure 34).
A study of collector and system costs for different type of buildings has been made by
Zinko, Eriksson and Brost (1998). The costs for both collectors and main system
components were based on budget offers and therefore can be taken as being
representative (though slightly optimistic). We will use these costs together with cost
functions from Figure 34 for establishing cost relations for solar collector systems for
roof mounted collectors in Romberga.
46
7.2 Cost of solar heating systems
Comparison of the total solar cost for large systems such as Kungälv (Dalenbäck,
2001) for 10 000 m² and from Zinko, Eriksson, Brost (1998) for 300 m² and 100 m²,
respectively, indicates also a cost variation by a factor 2 (see Figure 33). The costs of
two typical systems, of which the larger one has been built in Hammarby Sjöstad, are
summarised in Tabell 7.
Tabell 7:
Costs of solar heating systems designed for Hammarby Sjöstad
System 1
175
CPC-reflector
SEK/m²
1780
SEK/m²
794
kWh/m²,yr
214
SEK/kWh,yr 12
Collector surface
Type
Coll. costs mounted on roof
Circulation system
Spec. production
Specific investment
m²
System 2
370
Flat plate
2100
711
342
8,2
Hence, for the purpose of this study we will establish a cost function shown in Figure
36. But it should be noted, that usually systems larger than 1000 m² are mounted on
ground or on a flat roof and smaller systems are mounted on a tilted roof. Collectors
on horizontal planes have to be supported by support structures, and collectors on
tilted roofs will be mounted on the roof with work to be done for connections and feedthrough to the roof. This work will cost more the smaller a system is.
Costs (SEK/m²)
Solar costs
4000
Collectors
3000
Mounting
2000
Circulation
1000
Total
0
10
100
1000
10000
Area (m²)
Figure 35:
Cost function for total solar costs 2000. Roof respectively ground mounted solar
collectors.
Because we mostly deal with established district heating areas, possible roof-integrated collectors or collector roofs suitable for new development areas are treated
separately. Figure 36 shows the specific investment costs in SEK per annual produced
kWh per m² for both technologies: Solar collectors mounted on flat or tilted roofs and
47
solar roofs, respectively (calculated as marginal costs for the collectors integrated in
the roof trusses). Observe that heat storage costs are not included in these cost
functions !
SEK/kWh,year
Solar costs
12,00
10,00
8,00
6,00
4,00
2,00
0,00
Existing buildings
Solar roofs
0
500
1000
Area (m²)
Figure 36:
Solar investment costs for collectors mounted on roof surfaces and solar roofs,
respectively (based on an annual energy production of 350 kWh/m²).
It gets evident that the solar heating systems in new construction areas can achieve
very attractive energy costs. Figure 37 to Figure 39 show typical illustrations of roof
mounted solar collectors and solar roofs, respectively.
Figure 37:
800 m² roof mounted solar collectors on a school in Orust. Manufacturer: Solid,
Austria.
48
Figure 38:
210 m2 solar collectors mounted on a horizontal roof in Markbacken, Örebro.
(Manufacturer: Arnes Plåtslageri AB).
Figure 39:
200 m² solar roof on a garage building in Onsala. Manufacturer: Derome AB.
7.3 Solar costs in Romberga
By means of the established solar costs function we can now calculate the system
costs for Romberga. In these system costs, we include the solar costs and eventually
also the costs for the service pipes. The heat exchanger substation costs for transferring the heat from the collector to the district heating system are included in the
49
circulation system, since practically all solar collector systems in Sweden use antifreeze and therefore have to use heat exchangers for the connection to the consumer.
For the cost study we investigate two alternative cases with either only three systems
or with 15 solar systems connected to the district heating network. In both cases, the
solar heating systems will deliver 100% of the load on a sunny summer day. The costs
for hot water storages are not included since an accumulator is already available.
Table 8 compares costs for the two alternatives.
For Alternative A, only three suitable large systems have been connected, adding up
to 7620 m² collectors thus producing about 105% load. The total investment costs for
this alternative are 16,6 MSEK. The new service pipes (assumed to be 20 m long) for
connecting the collectors to the district heating net cost only 132 kSEK and represent
only a small fraction of the total cost.
If instead, as shown in Alternative B, all 15 systems are connected without altering
service pipe size, the total investment cost would be 19,8 MSEK, thus the system
would be 20% more expensive and produce just 100% of the load.
Hence a pre-design investigation with the aim of long-term planning pointing out the
most suitable locations for solar collector systems is highly recommended when a
successive exploration of solar district heating is to be undertaken.
Table 8:
Map
Area
No.
System costs for solar district heating for Romberga for two exploration alternatives
Service pipe
DN
Alternative A: Large systems
Collector system
mm
Collector
area
[m²]
3:3
32
3:5, 3:6
80
4:1
8:1-8:3,
9:1-9:5
10:3
Spec costs
SEK/kWh,yr
Alternative B
New service pipe
System
costs
kSEK
Collector system
DN
Costs *
Total costs
mm
kSEK
kSEK
Collector
area
[m²]
Spec costs
SEK/kWh,yr
System
costs
kSEK
134
10
469
1110
7,1
2758
50
370
8,4
1088
150
650
8
1820
65
325
8,5
967
10:5
65
650
8
1820
11:4
100
1880
6,6
4343
11:5
32
134
10
469
19:2
32
134
10
469
19:5
65
620
8
1736
19:7
50
370
8,4
1088
19:8
40
198
9,3
644
19:9
40
198
9,3
644
20:1
32
27:1
50
Total
costs
1110
5400
7,1
5,8
2758
10962
1110
7,1
2758
7620
6,2
16479
2758
150
80
76
11038
134
10
469
56
2814
370
8,4
1088
132
16611
7277
7,8
19872
7.4 Additional costs
Some additional costs are to be added to the system costs shown above. These are
related with the planning and the operation of the systems as well as with eventual
costs for storage, ground and/or roof placement of the collectors.
50
Planning costs
Planning costs should be seen as single costs for the total system. The overall system
should be carefully planned, optimised and designed. The purchase of systems should
be made through standardised request of offer. If the basic planning of the overall
system and of the principle solar circuit design is done, the planning of individual
systems can be reduced to making adjustments according to the local conditions. An
estimate for Romberga would be to add 300 000 SEK for planning costs to the total
system investment, and about 25 000 to 50 000 SEK/per system for the individual
design of systems. Hence, for Romberga this would mean about 450 000 SEK for
system Alternative A and 600 000 SEK for the total of systems according to
Alternative B.
Hot water storage
Costs of hot water storage are not included in the system price of Chpt. 7.3. As
mentioned in Chapter 8.3, most of the existing district heating systems will already
have storage tanks. If this is not the case, costs for hot water storage have to be
added. The costs for such storages are dependent on size and quality. The necessary
storage size depends on the desired solar fraction. With a successive integration of
solar collector systems into the district heating network, no storage is needed in the
beginning. At a certain stage of the implementation process, however, storage will be
required. At this point, perhaps instead of building a large storage, a storage with
limited size will be built, serving the extension process for a certain period. After that,
another storage with an additional capacity can be built on another location of the
network. Sizing the storage has to be done in each individual application.
Specific storage costs
Costs SEK/m³
6000
5000
4000
3000
2000
1000
0
10
100
1000
10000
Volume (m³)
Figure 40:
Solar storage costs.
Standard designs and standard costs for storages do not exist yet. However, rough
estimates can be made from storages reported from different projects with different
designs. From these, a cost relationship shown in Figure 40 can be found.
If a new storage in Romberga would be necessary, the costs for it (750 m³) would be
roughly 1 MSEK, i.e. 5% of the solar system costs.
51
Operating costs
Operating costs are mostly due for internal electricity consumption for pumps and
other auxiliary systems such as control systems. As the latter ones are practically
small compared to the pump electricity, we can concentrate on the pumps. In the
Romberga type of systems, two types of pumps are of interest: The circulation pump
for the solar collector circuit and the production pump feeding the solar heat to the
net. Most power is used for the latter, operating against the total pressure difference
between return and supply pressure of the net. The pumping power for individual
systems is depending on the size of the pumps, i. e. on the volume flow and size of
the collector fields. From Figure 41 the pumping power as a function of system size for
both types of pump applications can be seen.
Pumping power
Power (kW)
25
20
15
Pcirc
10
Pprod
5
0
0
5000
10000
Collector field area (m²)
Figure 41:
Typical pumping power as a function of collector fields - circulation and production
pump, respectively.
The pumping power for each collector system is in the order of 1 – 10 kW per system.
The operation time is approximately 1500 hours and hence typical operating energy
for Romberga will be about 50 MWh/year. With an electricity price of 300 SEK/MWh
the annual operating costs would be about 15 000 SEK.
Maintenance costs
Maintenance costs are reported to be relatively low for well operating (=planned)
systems. The most important maintenance is checking and completing antifreeze in
the solar collector circuit. Other controls are for checking measurement- and control
systems. The collectors need usually no maintenance during the economical lifetime,
but some exceptional repairs (glass, leaking absorbers, leaking joints) should be taken
into account. Also the function of heat exchangers should be controlled regularly for
avoiding too high collector temperatures. Additionally, some refill procedures for the
case of blow-down due to power failure must be accounted for. In all, good functioning
plants report maintenance costs being less than 5% of the annuity, i.e. less than
80 000 SEK in the case for Romberga. Probably the system Alternative B based on
many small systems will exhibit higher maintenance costs than the system for
Alternative A with three larger systems.
52
Costs for collector allocation
Costs for allocation of ground and roofs are difficult to determine in this stage. They
are depending on the local presumptions and type of contracts and maybe even
political measures. Ground close to cities can be very valuable and practically not
available for solar collectors. Roof placement on the other hand calls for legislative or
administrative regulations if no co-operating building owners are found. Examples
from Germany and Austria show that negotiations between utilities and building
owners can lead to a fruitful co-operation and to gratuitous use of roof surfaces for
solar collector implementation. In any case, the repair and restoration of roofs in the
case of demounting of collectors must be regulated and will need some amount to be
reserved for this purpose (se also Chpt. 8.4).
53
8 Implementation strategies
For implementation of solar systems into a heat distribution network there are no
simple truths or guidelines that will easily apply without at first evaluating the existing
system boundaries.
8.1 Heat distribution
It is of great importance that a thorough study of the heat distribution network is done
before considering this kind of solar system implementation.
The study should include the production capacity and production mix, but also pipe
lengths and dimensions, geography, standard of the existing distribution pipes and
temperatures in the heat distribution network during the year. A value to reflect upon
is the degree hours. The lower the value of the degree hours, the more efficient the
solar systems will prove to be.
The production mix is also of importance, as the solar systems themselves will be
production units. Some of the questions to answer are:
•
How will the existing main production unit for the summer period function
together with the solar systems?
•
What other production mix might be considered?
•
How does these alternatives look on an economical basis?
•
How does this affect the company policies, such as future investments,
energy planning, environmental issues, etc?
•
Is there an accumulator tank already available in the heat distribution
network that can be used for solar applications?
•
Are decentralised solar systems favourable when regarding the geographical
conditions of the networks?
8.2 Solar heating system
The technical aspect of the solar system is not of a major concern here, though
important. The solar technology itself has been used for more than 30 years, and the
different systems used today have all pretty much been standardised.
Important for this kind of use, however, is the control of the heat delivery from the
solar system to the heat distribution network. Preferably the distribution pump for the
solar system should be frequency controlled, so as to maintain a “set temperature” of
heat delivery to the heat distribution network.
A review of certified solar collectors is available at SP Sveriges Provnings- och
Forskningsinstitut (Swedish Test- and Research Institute). The web page address is
shown below:
http://www.sp.se/energy/CertProd/P_solfangare.htm
54
Other important issues to reflect upon regarding solar implementation strategies are
the heat distribution network planning, the possible solar heat production, existing
production units and approximate costs for implementation. Depending on heat
distribution network size the implementation ratio from 0-100% will vary in time. For
each specific network a project plan based on system parameters and economic
calculations must be made. In short, this project plan can be simplified into three
different implementation stages, system with low solar fraction, successive transition
to higher solar fraction and system with high solar fraction.
1.
P
> 30%
Figure 42:
3.
2.
P
30-70%
P
< 70%
Implementation scenarios. 1. System with low solar fraction,
2. Successive transition to higher solar fraction, 3. System with high solar fraction.
8.2.1 System with low solar fraction
First stage solar implementation usually does not affect the already existing production units in the heat distribution network at any greater range. If an accumulator tank
is available in the system, it can be used to obtain calmer operation criteria. This must
of course be evaluated for each specific heat distribution network.
The best-case scenario at this point is to use the largest available roof areas to build
1-3 solar collector systems, obtaining a solar fraction of 10-30%. Larger solar system
will decrease investment costs and allow for a god evaluation of the solar system
operation in the heat distribution network.
8.2.2 Successive transition to higher solar fraction
The transition to higher solar fraction is likely the stage to have most negative impact
on existing production units. Increasing the solar fraction from 30% to 70% will force
the other production unit(s) to work on part-load, thus decreasing its efficiency with
increasing costs. It is likely that the main production unit for the summer period here
must be replaced with a smaller production unit.
The solar implementation ratio at this stage is therefore very much dependent on the
kind of production units available in the district-heating network to match the solar
production.
As heat delivery from solar systems during transition to higher solar fraction during
daytime will increase to exceed the heat demand, an accumulator tank must be
available to store excess heat.
8.2.3
System with high solar fraction
When solar fraction reaches more than 70% the main summer production unit in most
cases must be replaced with smaller units. In this stage, the solar systems should
cover all or most of the heat demand.
55
The accumulator tank must for the ‘high solar fraction’ scenario be big enough to store
all excess heat during daytime. The small conventional production units are to work
‘more or less’ as backup systems only.
As the solar systems now have become the ‘main production unit’, the heat
distribution network is here most vulnerable for solar system failure, either technical
problems or due to lack of insolation. Because of this solar dependence, conventional
production units must still be available as backup systems. Access time of these units
is dependent of heat demand and accumulator size.
8.3 Heat storage
8.3.1 Centralised or decentralised storage
The basic concept of the solar district heating system proposed in this paper is the
direct supply pipe connection of the solar heating system via the service pipe of a
building. Roughly 30% of the daily summer load can be supplied without heat
storages, at larger solar fractions, heat storage must be used. Depending on the size
of the building roof and the purpose of the building (industry, dwelling, a.o.) an
existing service pipe is used or an additional solar service pipe has to be built.
In most cases, the summer load is hot water and heat losses. Excess solar heat from
an individual solar collector system is fed out to the net to other users and to the
storage. In the evening, the heat is supplied by the central storage or by the auxiliary
system.
An alternative way would be to have one or several local storages at the solar production units. This could reduce the dimensions of service pipe connections. We can
look at the two alternatives for Romberga and see if such a design is worthwhile.
In Alternative A, we have three systems, one producing roughly 70% and the other
15% each of the total load. The internal hot water consumption at the load (industry)
of the 70% system is assumed small compared to the total load. Through the existing
service pipe about 40% of the produced energy can be supplied to the net, the remaining part should be stored in a new storage at the site. The necessary storage size
would be about 300 m³ to be constructed at a cost of roughly 500 000 SEK. The
remaining size of the central storage would then be 450m³ to be built at a cost of
650 000 SEK. Hence the sum of both storages is 150 000 SEK higher than the cost of
a single central storage. This difference has to be compared with the costs of a new
service pipe to be estimated to 76 000 SEK for a length of 20 m. Hence there is no
economical reason for building decentralised storages (in Romberga the question is
hypothetical because a central storage already exists). A similar reasoning can be
done for the smaller system at 15%. In this case about 50% of the daily energy production have to be stored in a 50 m³ storage at a cost of 140 000 SEK. The remaining
costs of a central storage (700 m³) would be ca. 900 000 SEK. The extra costs of the
service pipes were given to 56 000 SEK and since the central storage with 750 m³ was
estimated to ca 1 MSEK, both measures are economically about equal, if no storage is
available.
For Alternative B, the arguments are different since there are no costs for service
pipes. Instead, we have 15 systems with different loads, the largest being that of an
industry building with a service pipe connection of DN 100. Most of the industrial loads
56
of energy will be consumed during daytime and hence no large storage for own use
will be necessary. This is different for multifamily buildings, where large DHW
consumptions are expected in the morning and evening hours were no solar heat is
available. Because detailed load figures are not available, we make an estimate on
average basis. Splitting up the total storage volume of 750 m³ on 15 local storages of
50 m³ will result in costs of 140 000 per storage or ca 2,1 MSEK totally, i.e. twice the
costs of a single large storage.
Hence, the only reason for building local storages is to satisfy wishes from the building
owner and his customers for prioritised use of the solar energy produced on their own
building. Although such desires can be judged to be irrational it should be taken
seriously and result in information meetings with owners and customers were the
different system aspects and involved costs should be discussed. It is of great
importance that all partners are involved in the process of solar heating implementation and that the applied technology is widely accepted. Otherwise, solar energy
systems will fail break-through due to other drawbacks such as disparity and nonregularity.
8.3.2
Comments on storage corrosion problems
In the past, a number of unpressurised hot water storages have been built for solar
heating systems (Zinko. 1996). The operation of such storages differ from that from
the common hot water storages usually used in district heating plants for the reason
that the charging temperature in solar heating systems very often is lower, i.e. around
60 to 80 C. That means that the common anti-corrosion method of applying a
sustained protecting steam cushion on the top of the accumulator water for avoiding
its contact with air oxygen by means of an electrical steam generator consumes a lot
of energy at these low temperatures. In former projects, f.i. in Nykvarn and
Falkenberg, corrosion occurred because the vapour generator was underdimensioned
for this application (Nilsson/Schroeder, 1996, Nilsson/Schroeder, 1998) at lower
temperatures. In these installations, the problem was tried to be solved by using a
specially designed water-siphon airlock, which, however, was not functioning properly.
Therefore, the steam cushion was replaced by a nitrogen cushion. The nitrogen can be
generated from air by semi-permeable membranes or by air liquefaction systems. In
both systems electrical work must be applied. The amount of energy used depends on
the amount of nitrogen that has to be added to the storage (thermal expansion of the
water and in- and outtake of water implies varying water levels during the day).
Nowadays, the storages at Falkenberg and Nykvarn are reported to work satisfyingly.
For smaller storages, another method for anticorrosion is used. Thermally resistant oil
is put on the top of the water preventing air contact. In this case it is very important
that this water- and oil levels remain undisturbed in order to avoid that the oil is
mixed into the water. This protection has been working successfully in several smaller
storages (Dahm, 1994; Zinko/Hahn, 1994), but eventually problems with cooking
occurred in Särö, the protecting layer was destroyed, leading to corrosion problems.
In the case of Romberga and other district heating applications, these problems must
be observed, because the storage combines both district heating and solar heating
functions. Possible ways are protection of the storage by a combined system, steam
and nitrogen cushion4, which probably has higher investment and lower operating
4
) Steam cushion in winter operation at higher district heating temperatures and nitrogen during summer
operation
57
costs, or by means of a nitrogen cushion solely, which probably, has higher operating
costs. The best solutions to this problem need to be investigated in further detailed
studies.
8.4
The market potential
The market potential for solar heating in Sweden was investigated in number of
studies. Two recent studies were parts of international studies within EU projects (Sun
in Action (Rodititi, 1996) and APAS (Zinko, Bjärklev, Margen, 1996) and another one
was performed for Stockholm Energi (nowadays Birka Energi) (Zinko, 1998). In the
APAS study, the Swedish market for district heating and block heating systems were
investigated separately from the remaining market for multifamily buildings and single
family houses. Table 9 shows a table for solar collectors for different applications and
a possible market growth for Sweden (from Zinko, 1998).
Table 9:
Solar heating market in Sweden – Trends
m² collectors
Year
Single family Multifamily
houses
houses
Block heating and Pools
district
heating
systems
with
diurnal storages
Accumulated
1997
130 000
15 000
22 000
20 000
Sales/Yr
1998
4 000
1 500
1 000
1 000
-”-
2000
5 500
-”-
2005 *
-”Accumulated
2 200
1 400
1 000
14 500
5 500
3 600
1 500
2010 *
35 500
13 500
9 000
2 000
2010 *
320 000
85 000
70 000
45 000
*) Prognoses
The market potential for block heating and district heating in Sweden has been
analysed in the APAS-study, judged to be interesting only for such applications where
oil or other expensive summer fuel is used. Totally the solar heating potential was
found to be roughly 8 TWh/year technically and 0,6 TWh for practical limiting reasons,
including roof access. According to the selection criteria applied in this study, we do
not feel that roof access is a real limitation except in large city centres; therefore, we
dare to increase the practical potential to be around 1TWh/year. Although this figure
represents only a small fraction of the total supplied heat for district heating and block
centrals, the potential corresponds to ca. 2,5 millions m² solar collectors or 10 times
the total collector volume in Sweden 1997.
On the other hand, according to Table 9, the economic market for solar district
heating and block heating systems is expected to grow only slowly, for various
reasons.
One reason is economic, solar heat has to compete with heat from biomass heating
plants and co-generation systems. In the future – with an increasing international
energy market and reduced nuclear capacity it will be of interest to produce electricity
in biomass fuelled co-generation plants delivering heat at marginal costs. The costs of
58
biomass-based heat are only a fraction of that of solar heating (see Chapt. 7). It is
therefore difficult to see that solar energy will be an important energy source for
district heating in the next decade.
Another reason is system technical, i.e. that solar heating with diurnal storage only
can deliver 5 – 10% of the annual energy of a given system. This is not a disadvantage in itself, but the problem is that solar energy with diurnal storage cannot deliver
primary energy and therefore always needs to be back-upped even in summer time.
However, there are two possibilities for giving solar energy a more important role
within the energy system:
a)
Combine solar energy with biomass heating plants and an auxiliary (bio-)oil or
electrical heater
b)
construct solar heating plants with seasonal storage – this will convert
secondary heat to primary heat.
In the case a) solar heating can take over the heating during the summer period, let's
say June until August, with a solar fraction of about 70 – 80% for this period. Hence,
the annual contribution of electricity or oil will be relatively low.
In the case b) solar heating will be converted into primary energy by means of a
seasonal storage. Sweden was during the 1980-ies the principal country for R&D in
seasonal energy storage, demonstrating the technical feasibility of it. But it became
clear that seasonal storages add another economical burden on the costs for delivered
energy, increasing the costs for delivered solar heat by 50 to 100%, depending on
plant size and storage technology.
However, in a longer perspective it can be expected that more complex local and
regional energy systems will be built, storing heat from waste heat, biomass, cogeneration and solar heating plants into a common energy storage for both diurnal
and seasonal load management, taking away the burden of storage heat from the
solar heating system by letting it be part of a total energy system.
8.5
Access to roofs
The concept of distributed solar heating plants feeding a common district heating net
is based on the idea that buildings are the most common and widely available carriers
of solar collector systems. In the tradition of the northern countries, large-scale solar
heating plants have so far mostly been used for ground installation of solar collectors.
This might be a possibility at low solar development in rural areas and close to small
Northern cities. However, on the European continent ground placement of collectors
was never an option and so it will neither be in well-developed solar areas in Northern
countries. The reason is that available ground is getting rare where people are living,
whereas roofs are well available in living areas.
Hence roof - and to some extent - wall surfaces should be considered as the primary
support surfaces for solar collector systems in built environment. Because most of the
buildings are existing we have to find ways of making roofs available for solar collector
structures. In future new constructions, we are expecting that roofs will be built as
59
solar roofs, using the energy production for internal use or delivering energy to a
common district heating or local net.
In the APAS study (Zinko, Bjärklev, Margen, 1996) it was found that enough roof
surfaces are available in Sweden and most of the other countries for supplying the
needed energy even taking into account non-suitable surfaces, shading and other
obstacles (such as monumental protection of buildings). However, placing solar
collectors on roofs usually means some kind of interference on the existing protective
roof structure and hence private house owners are not very keen to place their roofs
at disposal for solar collectors to a third party. Besides fear for damages or leakages,
also the problem of future restoration has to be considered.
Therefore, some administrative and/or legislative ways have to be found regulating
the conditions for which roofs can be used for solar collector placement. From
experiences in Germany and Austria, it gets evident that participation of house owners
and tenants in the process of planning and operating solar collector plants was the
best way of getting acceptance for solar collector installations. People are getting
familiar with the techniques and the operation of solar plants and very soon are
converting scepticism towards a positive engagement.
In general, the following possibilities for solar collector allocation to solar district
heating with decentralised systems exist:
a) The district heating company rents (contracts) the roofs of suitable buildings.
In this case, the building owner and the tenants are making an agreement with
the utility about the use of the roof for a limited time. The house owner and
tenants may receive some kind of benefit such as a green label, a price
guaranty or a solar discount for their involvement. Responsibility for
interference and restoration are at the utility.
b) The district heating company organises an open solar district heating project
for voluntary participation. In this case the utility stands for technical
information, design principles, model contracts, purchase support, etc. and
guaranties a certain purchase rate for the delivered energy. The house owners
can connect to the system whenever they want and in any size. In this latter
case the house owner takes all responsibility for interference and restoration.
c) The district heating company together with a group of interest, an association,
etc., constructs a new local solar heating net. This case deals with a limited
number of partners interested in a common, often well-defined project. In this
case, there should not be a conflict of interest and all partners can sign an
agreement contract sharing elements from a) and b) above.
Future development
In the future - with a strongly expanding solar market – solar district heating will be
common and there will be a need for regulated and controlled roof contracting. Of
course, one prerequisite is that solar energy can be an economic option in competition
with other energy supply. In this case, we are expecting two trends:
a) New buildings will be obliged by the building code to have solar roofs (factory
made roofs built as solar collectors) and in certain cases even solar facades.
60
Such systems must not necessarily be used for district heating purposes;
instead, the energy can be used in internal heating systems.
b) In existing areas, suitable roofs can be reclaimed by law. Such a law will also
regulate the question of compensation and of responsibility for eventual
damages caused when installing or replacing solar collector systems. Generally,
it is expected that house owners will see the possibility of making energy
business out of available roof surfaces.
8.6
Environmental aspects
There is no doubt that solar energy systems represent an important environmental
potential, not only for the greenhouse problem but also generally in the respect of the
use of limited natural resource such as fossil fuels. Solar energy should be principally
used for replacing either electricity (which in Sweden is the case because domestic hot
water is very often produced with electricity in summertime) or fossil fuels (which
often is the case in block heating and sometimes in district heating nets).
CO2- reduction
By replacing other forms of energy, the produced solar heat is directly decreasing the
corresponding amount of non-used energy, at the same time reducing the generation
of a corresponding amount of CO2. From Table 10, the amount of CO2 for different
energy replacements is shown.
Table 10:
Reduction of CO2 production by solar energy replacing other energy forms. 1 MWh
solar energy reduces the following amount of CO2 emissions:
Type
kg CO2
Oil
280
Natural gas
200
Coal
330
Electricity (European
condensation)
coal 1000
In Sweden, oil is very often used in summer operation of block centrals and small
district heating nets and hence solar energy can there make an important
environmental contribution. On the other hand, Swedish electricity production in
summer time is mostly based on hydropower and since water storage capacity is
limited, the domestic environmental aspect of electricity replacement is not very
important. However, in a number of years it is expected that the total European
market is deregulated and that Swedish electricity is used on export for replacing
continental coal condensation power. In this case each replaced MWh can be used on
export and therefore save about 1000 kg CO2 emission. Hence, in this aspect, solar
energy will play a very important role for reducing the climate problem of fossil fuels.
Furthermore, CO2 emissions have also an economical aspect (the external costs of CO2
emissions for coal fired electricity are judged to be at least 50 SEK/MWh and some
times up to 2000 SEK/MWh according to different studies Carlson (1999)). Therefore,
it should be mentioned that these costs have to be added to the respective energy
61
costs when compared with the costs of solar energy. In this aspect, solar energy can
already today be found economically competitive in many applications. The only
problem is that these costs are not paid by the consumers of fuels or electricity, but
by the society as a whole in form of taxes, costs of damages, insurances and costs for
building and ground restoration. It is expected that the 21st Century will see a change
of the economical assessment of environmental and social impacts and of the uses of
limited natural resources.
Internal energy use
Some times, the argument is used that solar energy needs a lot of energy for its
production, part of it in the production of system components and part of it by
collecting the dispersed energy. None of it is true. In several studies, (a.o. Hohemeyer
(1990)), the internal energy use of solar energy has been investigated. It was found
that solar thermal energy production in collector systems has an energy payback time
of 0,5 to maximal 1 year. Hence, with a demonstrated lifetime of 20 years and
anticipated lifetime of at least 30 years for well-developed systems, the useful energy
output of a collector is reduced by only a few percents.
However, pumping energy must be used. As for solar district heating systems, this
energy was found to depend on the system size. Smaller systems use higher pumping
power (per produced kWh) than larger systems. However, the energy consumption for
the heat production/distribution system is not a peculiar solar problem but holds for all
distribution (except that smaller solar pumps need more power than large central
distribution pumps). In a rough estimate we can assign half of the solar distribution
energy and the whole energy of the solar circulation pump (from the solar circuit) to
the solar heating system. For Romberga the total electricity consumption was
estimated to be about 50 MWh/year, taking into account only 50% of the solar
distribution energy will result totally in about 30 MWh/yr operating energy attributable
to a system producing about 3 000 MWh/yr solar energy. Hence, the internal energy
use for solar energy production is practically negligible.
8.7
Recommendations and conclusions
Heat distribution systems are a product of the geographical location, existing infrastructure and heat demand, and although they are all ‘distribution systems’, they
cannot easily be categorised. They have all different means of producing and
distributing energy.
Each heat distribution system must be evaluated separately to obtain optimal function.
As they have one common factor, to supply their customers with heat, some rules of
thumb can be declared concerning implementation of decentralised solar systems into
the existing heat distribution network.
62
A thorough system analysis must be performed on the heat distribution network. This
should cover the system:
•
•
•
•
•
•
•
•
•
network status
network dynamics
geography
production units
production strategies
accumulator tanks
heat demand
temperatures
flow rates
As these above specified parameters are known, a possible solar implementation can
be addressed concerning:
•
•
•
•
•
•
•
available roof area
technical data of suitable solar collectors
geographical solar insolation
solar collector system
maximum achievable solar fraction
solar implementation strategy
economical calculations
These parameters are all essential for a solar system implementation to take place,
however, a less-thorough study might prove sufficient enough to evaluate the
possibility of this kind of project.
One must also take into consideration that this type of project, with an
implementation task from 0-100% of the summer loads might have a project time of
approximately 10-20 years. During this time energy strategies, economy and
techniques of solar heating can drastically change. However, we believe that this
change will be rather to the advantage of solar heating systems.
63
By summarising, we can notice the following general facts about distributed
solar district heating systems:
•
Distributed solar heating plants suitably localised in different branches of the
net can complete existing district heating systems.
•
A suitable and straightforward connection is as a production system between
return and supply pipe.
•
Collector systems can be placed on suitable horizontal or inclined roofs.
•
For smaller solar collector areas, the solar heating system can be connected via
the existing service pipes.
•
If large roof areas for solar collectors, f. i. from industrial buildings, are
available, a new service pipe with increased dimension is worth to be
constructed.
•
If a central storage exists, smaller decentralised storages are normally not
economic to construct.
•
If no central storage exists, the construction of one or two storages is more
economic than the construction of a larger number of smaller building-located
storages.
•
In the summer months, a large amount of the load is distribution of heat losses
levelling out the domestic hot water peaks.
•
Roughly one third of the daily summer load can be supplied without storages.
•
In the case without storage, roughly another 10% of the load can be stored in
the return pipe, but depending on the location of the solar heating systems and
loads, the risk exists that solar heated water returns to the solar heating
plants, decreasing their efficiency considerably. At right design of the solar
collector circuit, no other operational risk exists in this case.
•
At higher solar fractions, storage must be used.
•
100% summer load corresponds in Sweden to 5 - 10% annual load depending
on the load profile and size of district heating systems. Usually in smaller
systems, a higher annual solar fraction can be achieved compared to larger
systems.
•
Larger solar fractions can be achieved with partial seasonal storages, however,
these storages must be considerably larger than those discussed in this paper.
•
A rule of thumb is that for each nominal MWth of the district heating system
(winter design load) there will be 0,1 – 0,2 MWth summer load corresponding to
2,5 – 5,0 MWh daily energy supply.
•
Therefore, 1 design-MWth allows the installation of about 500 – 1000 m² solar
collectors, depending on system size and load distribution.
•
A solar heating system for diurnal storage will cost about 6 – 8 SEK per kWh
annually produced solar heat, storage costs not included.
•
The size of the storage is depending on the solar fraction, i.e. on the state of
implementation. For 100% solar summer load, the storage volume should be
about 0,1 m³ per m² solar collector.
64
References
Carlsson, A. (1999). Externa kostnaders inverkan på tekniska energisystem. Simulering av
biobränsleanvändningen i tre regioner. (Influence of external costs on technical energy systems.
Simulation if the use of biofuel in three regions). LiTH-IKP-R-1074.
Dahm, J. (1994). Design of a Solar Heating System for a small residential Building Area.
Institute for Building Service Engineering, Chalmers University.
Dalenbäck, J-O. and A. Åsblad. (1994). Förutsättningar för solvärme i gruppcentralen och
mindre fjärrvärmesystem. (Prerequisites of solar heating in group centrals and smaller district
heating systems). Chalmers Industriteknik.
Dalenbäck, J-O. (2001).Home-page information for Kungälv
http://www.hvac.chalmers.se/cshp/Kungalv_se.htm
Fjärrvärmebyrån (1999). Intern-communication FVB-Nytt (FVB-News).
Helgesson, A., et.al. (2000). Solvärme – Slutrapport för FUD-program Solvärme 1996-99.
(Solar Heating – Final Report for R&D-programme Solar Heating 1996-99). Vattenfall
Utveckling, UD 00:12.
Hohemeyer, O. (1990). Impacts of external Costs on the competitive Position of Wind Energy in
the Federal Republic of Germany, in External Environmental Costs of electric Power, Proceedings
of a German-American Workshop, Ladenburg, FRG, October 23-25, eds O. Hohemeyer &
R.L. Ottinger, Springer-Verlag, Berlin.
Mangold, D. (1995). Kostenreduktion bei der Herstellung von Solarkollektoren durch
Massenfertigung/neue Konzepte. (Cost Reduction by means of mass-production when
manufacting Solar Collectors/New Concept)). Institut für Termodynamik und Wärmetechnik,
University Stuttgart.
Nilsson, L. and K. Schroeder. (1996). Korrosion I solfjärrvärmeackumulatorn i Falkenberg.
(Corrosion in the Solar District Heat Accumulator in Falkenberg). Mätcentralen, Chalmers
University.
Nisson, L. and K. Schroeder. (1998). Korrosionsskydd med hjälp av inert gas – ett system för
solvärmeackumulatorn i Nykvarn. (Corrosion Protection by means of Inert Gas – A System for
the Solar Heat Accumulator in Nykvarn). Mätcentralen, Chalmers University.
Roditi, D. (1996). Sun in Action. The solar thermal market. A strategic plan for action in Europe.
European Solar Industry Federation.
Schroeder, K. and P. Isakson. (1994). Central Solar Heating Plant with diurnal Storage in
Falkenberg. BFR, R23:1993.
Zinko, H. and T. Hahn. (1994). The high Temperature (95°) Water Pit Storage of Malung.
ZW-94/03.
Zinko, H. and J-O Dalenbäck. (1996). Solvärmeteknik – Underlag för Byggforskningsrådets
forskningsprogram 1997-99. (Solar Heating Technique - Basis for the research Programme of
the Swedish Council for Building Research). BFR, G11:1996.
Zinko, H. (1996). Säsongssvärmelager i Sverige. (Seasonal heat storages in Sweden).
ZW Energiteknik, ZW-96/05.
Zinko, H. (1996). Solvärmeanläggning i Henån – Fördjupad förstudie. (Solar Heating Plant in
Henån – Deeper pre-design study). ZW Energiteknik, ZW-96/11.
65
Zinko, H., J. Bjärklev and P Margen. (1996). The Market Potential for Solar Heating Plants in
some European Countries. APAS. ZW Energiteknik, ZW 96/16.
Zinko, H. (1997). CEC-Thermie B: The Solar Heating Market. ZW Energiteknik, ZW-97/07.
Zinko, H. (1998). Solvärmemarknaden i Sverige – En studie för Stockholm Energi AB.
(The Solar Heating Market in Sweden – A study for Stockholm Energi AB). ZW Energiteknik,
ZW-98/07.
Zinko, H., L. Eriksson and V. Brost. (1998). Hammarby Sjöstad, Sickla Udde - Förprojektering
(Pre-design study). ZW Energiteknik, ZW-98/09.
Zinko, H. (1999). CEC-Thermie B: Solar Heating in Nothern and Central Europe. Final report.
ZW Energiteknik, ZW-99/12.
66
1800m²
K27 mfhs(sn)
719kW
half of the roof area
nodes
pipes, which are connected to costumer
main pipes
costumer typ of costumer
max power
ν length of track
67
K29 ind
351kW
0
∅5 8
2
ν 9
6
2c
ν
∅ 50
1320m²
∅
29
28
27
2a
∅
∅1
32
K26 ind
70kW
ν 1
58
ig 2
352m²
Zwe
72
00
ν
2b
1
ν 48
∅ 250
0ν
52
Feed
point
∅8
1a
23
ν
3e
25
∅ 250
ν 120
K1 ind
575kW
0 ν
196
∅ 80
ν 168
K20 efh
110kW
896m²
K22 sk(sn)
444kW
K21 efh
110kW
ν 28
3d
26
896m²
∅8
4
24
3f
ν 1
0
1800m²
K3 ind
210kW
32
3a
∅
ν
55
4800m²
5
6
4a
ν 2
0
7
8
K4 ind
81kW
792m²
648m²
K5 ind
205kW
132
∅250 ν
K17 efhs
309kW
K18 efhs
165kW
∅50 ν 1000
(∅100 ν 20/4/20)
20
ν 50
19
21
ν 87
3h
∅32
384m²
K2 ind
575kW
K25 efhs
161kW
54
∅ 80 ν
22
K19 efhs
161kW
3b
ν 44
∅65
ν 8
2
0
ν 3
4b
3
1b
ν 20
3g
26
ig 3
792m²
0
K28 ind
318kW
K19 zfh
115kW
K23 efhs
318kW
∅80
ν 30
∅ diameter
19
4
ν 3
∅ 80
ν
Zwe
ν 40
65
4
ν 3
Zweig 4
ν
18
976m²
712m²
9
K15 mfhs
405kW
K6 ind
387kW
0
Zwe
ig 1
7
48
10
26
3c
ν 64
1104m²
K16 mfhs
485kW
6d
ν
10
5
∅6 0
3
16
608m²
K7 ind
206kW
1d
ν
ν
56
∅3 2 ν
∅ 50
ν 4
5
∅6
17
ν 60 11
448m²
K8 ind
143kW
12
15
ν 58
17
∅ 100
ν
5
∅6 2
4
ν
0
ν 140
6c
3
ν 1
∅2 0 0 ν 1 3 6
5a
0
6
50
0
14
13
5760m²
K12 ind
988kW
510m²
K13 ind
94kW
∅ 250 ν 138
∅1
ν 1
46
ig 5
00
Zwe
560m²
K10 ind
69kW
∅ 100 ν 60
∅ 32 ν 40
5b
ν 145
6a
6b
∅65
Zw
eig
∅1
3
ν 1
ν2
4
∅
15
K14 mfhs(sn)
4778kW
K9 foom
750kW
K11 foom
1250kW
Appendix A - DH Network scheme for Romberga
ν 22
∅4 0 ν 6 4
1c
Appendix B:
Scheme for connection of solar heating plants to district heating networks (return-supply
connection).
I ett ekologiskt och ekonomiskt uthålligt samhälle är det
naturligt att fjärrvärme och kraftvärme utgör dominerande delar
av den energiförsörjning som kunderna efterfrågar
Svenska Fjärrvärmeföreningen • 101 53 Stockholm • Telefon: 08-677 25 50 • Fax: 08-677 25 55
Besöksadress: Olof Palmes gata 31, 6 tr • E-post: [email protected] • www.fjarrvarme.org

Implementation of multiple solar heating systems into existing heat

Transcription

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