MASTER’S THESIS
2008:122 CIV
Universitetstryckeriet, Luleå
Karl Oskar Gard
Biomass Based Small Scale Combined Heat and Power Technologies
MASTER OF SCIENCE PROGRAMME Mechanical Engineering
Luleå University of Technology
Department of Applied Physics and Mechanical Engineering Division of Energy Engineering
2008:122 CIV • ISSN: 1402 - 1617 • ISRN: LTU - EX - - 08/122 - - SE
Preface
This thesis has been carried out during the year 2007-2008 as a Research Trainee for the division of Energy Engineering at Luleå University of Technology.
I would like to take the opportunity to thank my supervisor Dr. Joakim Lundgren for doing an excellent job. I would also like to express gratitude the rest of the staff members on the division for making me feel welcome and supporting me during the year. Special thanks to Prof. Björn Kjellström for very incentive and helpful suggestion in the study.
Furthermore, I would like to thank all the Research Trainees, which it has been a privilege to work with and of course for a very enjoyable trip.
Karl Oskar Gard Luleå June 13 2008
Abstract
At present governments aim to increase the share of renewable energy in the European Union as an attempt to reduce the emissions of green house gases. One approach is to replace some of the non-renewable power generation methods, with biomass based combined heat and power generation technologies.
The main objective of this study has been to investigate the state-of-the-art in the area of small-scale biomass based combined heat and power generation. Other aims have been to identify proper biomass based CHP technologies for the county of Norrbotten and to make a pre-study of such a plant located in the small community Harads.
The technologies investigated were the Organic Rankine Cycle (ORC), steam engine, gas engine and externally fired gas turbine (EFGT). An economic comparison shows that no one of the considered technologies is economically viable at present Swedish electric prices and green electric certificates. In order to reach profitability the green electricity certificates or the electricity prices must increase with at least 35 €/MWhel. Still if the problem of fouling and corrosion in the externally fired gas turbines heat exchanger is solved in a sufficient way, this technology shows potential for the future due the high electrical efficiency and resulting low cost of electricity. This is also true for the gas engine, which has similar problems with the dirty gas, yet this technology might be more suitable in power ranges higher than 5 MWth. Regarding the Harads plant, a 2 MWth Organic Rankine Cycle was assessed to be the most suitable technology. Still, calculations showed that the electricity share will be unprofitable, but the full-plant will be economically viable due to a high return from the heat sales.
Furthermore a sensitivity analysis showed that the most important parameter for the cost of electricity is the annual operation hours in addition it also showed the fuel price has not so much influence on the cost of electricity.
Abbreviations
b Additional operation cost per fuel unit c Annual operation and maintenance cost Cfuel Fuel cost
CH4 Methane
CO Carbon monoxide CO2 Carbon dioxide COE Cost of electricity COH Cost of heat
CPI Consumer price index Cserv Service cost
EFGT Externally fired gas turbine ESP wet electrostatic precipitator GHG Green house gases
h Annual operation hours H2 Hydrogen
H2O Water
Iadd Additional investment for the electricity part IFGT Internally fired gas turbine
IR Interest rate Is,add
Specific additional investment for the electricity part
Is,th Specific investment heat part Ismarg
Specific additional investment for the electricity part
Ith Investment heat part Itot Total investment CHP plant NOX Nitrogen oxides
O&M Operation and maintenance ORC Organic Rankine cycle Pel Electric power
Pf,heat Fuel cost for hypothetical heat producing plant Pth Thermal power
SNRC Selective non-catalytic reduction te Economic life time
tt Technical life time wt% Weight percentage ηel Electrical efficiency ηmarg Marginal efficiency ηth Thermal efficiency ηtot Total efficiency
Contents
PREFACE... I ABSTRACT... II CONTENTS... IV
1. INTRODUCTION ... 1
1.1. BACKGROUND... 1
1.2. OBJECTIVE... 5
1.3. METHODS... 5
2. POWER GENERATION PROCESS VIA COMBUSTION... 10
2.1. ORGANIC RANKINE CYCLE... 10
2.1.1. Process Description ... 11
Economic Evaluation... 13
2.1.2. Reference Plants... 16
Admont Plant... 17
Lienz Plant... 19
2.1.3. Summary Organic Rankine Cycle ... 21
2.2. STEAM ENGINES... 22
2.2.1. Process Description ... 22
2.2.2. Reference Plants... 22
Spilling Steam Engine ... 23
Hartberg... 24
2.2.3. Summary Steam Engines ... 26
2.3. EXTERNALLY FIRED GAS TURBINES... 27
2.3.1. Process Description ... 27
2.3.2. Reference Plants... 28
Anheden Simulations... 28
Talbott’s Biomass Energy ... 30
Compower ... 32
Vrije Universiteit Brussel ... 33
2.3.3. Summary EFGT... 35
3. POWER GENERATION PROCESS VIA GASIFICATION... 36
3.1. COMMON GAS GENERATORS... 36
3.2. HEAT AND ELECTRICITY GENERATION BY GASIFICATION... 37
3.3. GAS ENGINES... 39
3.3.1. Process Description ... 39
3.3.2. Reference Plants... 40
Güssing... 40
Harboore... 45
Movisala Plant... 47
Kokemäki ... 49
3.3.3. Summary Gas Engines ... 50
4. ECONOMIC COMPARISON... 51
5. CASE STUDY OF HARADS IN NORRBOTTEN, SWEDEN... 54
7. REFERENCES ... 63 8. APPENDIX ... 68
1. Introduction
1.1. Background
The global warming and the climate change is one of the most discussed topics in the scientific community. Major evidence shows that the global warming is caused by an increased concentration level of green house gases (GHG) in the atmosphere. This increase is almost entirely caused by human activities and partly due to electricity and heat generation from fossil fuels. The Nobel Prize winner Dr. Rajendra Pachauri, chairman of the Intergovernmental Panel on Climate Change (IPCC), has made statements like “Today, the time for doubt has passed. The IPCC has unequivocally affirmed the warming of our climate system, and linked it directly to human activity” and “Slowing or even reversing the existing trends of global warming is the defining challenge of our age.”, [1]. Statements like this, along with observed effects of increasing intense of tropical cyclones , sea level rise, melting of the artic cap etc, [2] have consolidate governments and nations to take joint measures to reduce the emissions of anthropogenic GHG to the atmosphere in order to mitigate the climate change.
In September 2007 the Swedish Scientific Council on Climate Issues released a report with scientific recommendation for future Swedish climate policy targets at national, EU and international levels, [3]. The council concludes that the EU’s target of limiting the increase of the global mean temperature to 2°C above pre-industrial values is a reasonable basis for emission reduction measures. This target is likely to be achieved if GHG concentration in the atmosphere is stabilized at 400 ppmv1 carbon dioxide equivalents in 2050. To achieve this global GHG concentration, the emissions by the year 2050 needs to be at least halved compared to the 1990 level and by the end of the century global emissions need to have been reduced to almost zero, [3].
One issue is to decide which measures to prioritize. According to the council a combination of increasing energy efficiency with the use of present and future technologies along with a fundamental reform of consumptions patterns is crucial to achieve the target, [3]. A part of the reduction might be achieved with the replacement of fossil based power generation methods with renewable energy technologies as bio energy, solar energy, wind power and hydro power. Since Sweden has large biomass assets, bio energy will probably provide a large part of the renewable energy in the future, except for the already commercial hydro power. To achieve cost-effective generation and minimize the environmental impact it is a basic requirement to make use of the heat which often is formed when generating electricity from
1
biomass (combined heat and power). To ensure outlet of this heat, generation would favorable be of small-scale. In addition the biomass low energy density would favor generation located at rural areas which often are rich on biomass, thus minimizing fuel transports but also encourage rural development by creating job opportunities.
At present, the biomass usage is under strong progress in Sweden, in particularly the heat only plant expansion, [4]. Unfortunately biomass based combined heat and power (CHP) is not as prevalent much because it has to compete with already established heat only plants and with technologies such as hydro- and nuclear power, which generally generates less expensive electricity. Yet the introduction of green electricity certificates along with rising electric prices will increase the profit electricity generation, thus be advantageous for expansion of biomass based small-scale combined heat and power. This expansion has already been seen in other European countries, for example Austria, Germany and Italy etc, which currently have higher electricity prices compared to Sweden, [5].
Green Electricity Certificates
In May 2003 the Swedish parliament introduced a green electricity certificate system with the ambition to encourage the production of renewable electricity (incl. peat). The aim of the certificate system is to increase the generation of renewable electricity with 17 TWh by 2016 relative to the generation level in 2002. The government grants one green electricity certificate per produced MWhel renewable electricity. Technologies that are entitled for certificates are:
• Wind power
• Solar energy
• Wave energy
• Geothermal energy
• Biomass fuels1
• Peat, burned in CHP plants
• Hydro power
There are some restrictions on the rights to receive certificates. For example plants commissioned after the first of May 2003 are entitled to certificates for 15 years or to the end of 2030 if that occurs earlier. Plants commissioned before the introduction of the certificate systems are granted certificates to the end of 2012. Plants that at the time of their construction or conversion received a public investment grant after February 15th 1998 are entitled to certificate until the end of 2014, [6].
1 Electricity produced from biofuels are entitled to certificates under Ordinance 2003:120 presented online at http://www.notisum.se/rnp/sls/lag/20030113.HTM
Quota Obligation
The electricity suppliers are required to purchase electricity certificates corresponding to a certain quota of the electricity they sell. In addition electricity intensive companies and electricity users, who have used electricity that they have themselves produced, imported or purchased on the Nordic electricity exchange, are also labored to purchase certificates. This quota is set in advance so the objective of increasing the production of green electricity is reached by 2016, [6]. A table with the quota up to 2030 is found in Appendix E.
Certificates
The electricity certificates are traded purely electronically between producers and those who have quota obligations. This means that the price of certificates is determined by the relationship between supply and demand, [6]. Price changes can be seen in Appendix E.
However in this study an average price of 235 SEK (26.1 €) per certificate is used.
Electricity Prices
The electricity price differs a great deal among the member states in the European Union. At present Sweden has a one of the lowest electricity price in the Union. This is probably due to the large percentage of hydro power utilized in the country, since hydro power in general generates electricity at a relatively low cost compared to competing technologies. Figure 1.1 shows a comparison between electricity prices for house holds in different European countries, it can be seen that the prices in Sweden is approximately 60-70% of the prices in Germany and Italy. However, the Swedish prices have increased the last decade, this is most likely related to the increased trade of electricity within the Union and if the trade continue to increase the Swedish prices will probably approach the higher European prices in the future, [7].
Figure 1.1 Electricity prices in July 2007 for households in different European countries, [8]
Combined Heat and Power Generation
Combined heat and power (CHP) or cogeneration is defined as the simultaneous production of both useful heat and electric power in the same plant. The biggest advantage of cogeneration is the high total efficiency this gives resource effective operation which is crucial if the emission targets are to be fulfilled but also for achieving economic viability.
Efficiencies up to 90% have been achieved with CHP, compared to the conventional way of generating electricity and heat in separate plants which achieves efficiencies up to about 60%.
Figure 1.2 shows the difference between cogeneration and separate generation. It can clearly be seen why this technology is interesting for the future. Especially on the small scale market were CHP could replace the more common heat only plants.
Figure 1.2 CHP vs separate generation, [9]
At present there are numerous methods of cogeneration with biomass. The most common and promising technologies along with their respective state of development are listed in Table 1.1.
Table 1.1 Different biomass based CHP technologies
Technology Present State of Development
Steam Turbines Established
Steam Engines Under development(demonstration units)
Gas Engines Established
Gas Turbines/Combined Cycle Under development (demonstration plants) Externally fired gas turbines (EFGT) Under development (pilot plants)
Organic Rankine Cycle (ORC) Established
Stirling Engine Under development (pilot plants)
1.2. Objective
As mentioned there are numerous different technologies for small scale biomass based combined heat and power generation. The main objective of this study is to perform an impartial investigation of the state-of-the-art in the area both from a technological and economic perspective. The investigation should point out possible technical obstacles for commercialization of the considered technologies and in addition determine where future R&D should be directed. In more detail this study will focus on:
• Summarize national and international R&D and collect information of economic and operational experiences of biomass based CHP technologies in the thermal output range of 1-5 MWth
• Identify future technological improvements and pin-point where future research should be focused
One of the most suitable counties for CHP expansion in Sweden, is Norrbotten which has large assets of biomass and many decentralized communities. Therefore it comes naturally that some of the state-of-the-art in the area could be demonstrated here. If the CHP expansion is to fully satisfy the potential market, difficult fuel like forest residue must probably be utilized. Since the CHP technologies have to compete with pellets manufactures, pulp mills and saw mills for the quality biomass and such companies in general outrival CHP plants because they can afford to pay a higher price for the biomass. It is therefore of great interest to identify the most suitable technologies that can handle local conditions and from there resolve a plan for future demonstration and implementation of the technologies. Hence additional objectives with this study is to identify the most promising technologies from a Swedish perspective with focus on achieving economic viability with present and future condition on the electricity market and electricity certificate system. The additional objectives are in more detail to:
• Identify suitable technologies for biomass fired CHP plants in the Northern region of Sweden
• Perform a techno-economic pre-study of a plant located in Harads, Norrbotten
1.3. Methods
Initially an extensive literature study on different combined heat and power technologies that are available or under development was carried out. The technologies that were regarded are shown in Figure 1.3 along with their typical electric power ranges. Still as mentioned this study focus on state-of-the-art in the area of small scale CHP generation within the region of 1-5 MWth therefore some of the technologies were discarded directly. The steam turbines was discarded from the start because of poor economic viability in sizes under 1000 kWel, much because of scale-factors but also due to decreasing efficiencies in smaller sizes, [7]. The Stirling engine was also discarded without further investigation since the developers of this technology only seem to focus on application under 1 MWth. Finally the gas turbine or
combined cycle was rejected since only two demonstration plant could be identified namely the ARBRE and Värnamo plant and in addition both these plants suffers from financial problems. Still the technologies that are evaluated in this report are ORC, EFGT, gas engines and steam engines (circumscribed in Figure 1.3). The information needed for the techno- economic evaluation of these technologies was collected from already published work but also via personal communications with responsible persons for some of the reference plants considered.
Figure 1.3 Biomass based CHP technologies for different plant sizes
Economic Evaluation
Considering the economic evaluation it should to be mentioned that when generating heat and electricity simultaneous in a CHP plant it will produce sale revenues from both heat and electricity. Consequently both should be accounted for in the economic calculations. However since this study only consider small-scale CHP plants, which in general are heat controlled, the electricity producing part can be seen as an additional investment to the heat plant and should therefore be economic motivated by it self. One way to approach this is to distinguish the costs for the electricity generation part from the heat generating part and from there calculate a cost of electricity (COE) respective cost of heat (COH). Yet since it is difficult to obtain detailed investment and cost information for every plant studied, a simplification was made to distinguish the electricity part from the heat part.
Given that the total investment of the CHP plant is known, one wants to decide the investment amount that corresponds to the electricity generating part. This was done with the method of subtracting an assumed investment for a hypothetical heat generating plant of the same thermal power as the considered CHP plant from the total investment of the plant. The required specific investment (Equation 1.1) for different heat only plant in the range 0.5-10 MWth was taken from Kjellström, [7].
th th th
s P
I , = I [€/kWth] (1.1)
The specific investment was plotted versus the thermal power. The results are shown in Figure 1.4
Specific Investement vs Thermal Power
y = 3383.9x-0.2652
0 100 200 300 400 500 600
0 2000 4000 6000 8000 10000 12000
kW(th)
€/kW
Curve-fit, Heat plant investment
Figure 1.4 Investment heat only plant
Further the plot was fitted with the power function in Equation 1.2.
2652 . 0 ,th =3383.9 th−
s P
I [€/kW] (1.2)
The additional investment required for electricity production can be defined as in Equation 1.3
th th s tot
add I I P
I = − , × [€] (1.3)
The method used to calculate the specific electricity generation cost was presented by Kjellström [7] and is used in this study. The electricity generation cost is defined as the additional investment cost for electricity production (Iadd) divided by the generated electricity.
When accounting for annuity the electricity generation cost is calculated by using Equation 1.4. Yet this equation do not account for lower part-load efficiencies.
arg
) ,
(
m fuel add
s C b
h I c COE a
η + +
= + [€/MWhel] (1.4)
Where a is the annuity factor defined by Equation 3.5,
( )
−
+ ⋅
−
×
− +
=
t e t
t t
t t t IR IR
a IR
e te
1 1 1
1 1 1
(1.5)
For which, te and tt is economic and technical lifetime respectively and IR is the interest rate.
Is,add is the specific additional investment for the electricity part and c is a factor for calculation of the annual operation and maintenance costs, h is the annual operation hours.
Cfuel is the fuel cost per MWh and b is an additional operation costs per fuel unit. The efficiency ηmarg is defined as how much extra fuel energy input the plant require to achieve the specified electric power, while still maintaining the heat generation, [7] see Equation 1.6.
heat f fuel
el
m P p
P
,
arg = −
η (1.6)
Where pf,heat is the fuel amount needed to operate a hypothetical heat producing plant of the same size. Nevertheless this variable strongly depends on the efficiency of this theoretical plant, in this study the total efficiency for such a plant was assumed to be 0.9, [7].
According to Kjellström [7] some thumb rules for c and b are 0.02 and 2.22 €/MWhfuel,Which is used if nothing else is stated. The economic and technical lifetime along with h are assumed according to the case studied.
The fuel price (Cfuel) varies significantly, depending on grade of refinement and geographical location. The prices used in this report are valid for the year of 2006 and are taken from the Swedish Energy Agency [10], Table 1.2 shows mean prices for different fuels in Sweden.
Table 1.2 Fuel prices, 2006, [10]
Period 2006
Refined fuel
(Briquettes & Pellets)
Heat plants [€/MWh] 23,4 Forest residues Industry [€/MWh] 13,2 Heat plants [€/MWh] 16,2
By-products
Industry [€/MWh] 12,4 Heat plants [€/MWh] 14,2
Return wood
Heat plants [€/MWh] 8,7
The technologies studied in this thesis regularly uses forest residue as fuel and if nothing else is stated forest residue with the cost of 15 €/MWhfuel is assumed to be utilized. It should also be pointed out that there are a few possible agricultural fuels, which also might be interesting in a future perspective. No calculations are based on these but some of them are presented in Appendix I.
2. Power Generation Process via Combustion
Methods to extract heat through combustion of biomass have been used for centuries and the different technologies for this can be considered well developed. At present a large focus is put on electricity production from biomass which is not as well developed and thus requires large R&D efforts.
The most common power generation method from biomass today is the Rankine cycle, but the technology is rarely used in small scale application since it tends to be less profitable in sizes below 10 MWel. The reason is mainly down-scaling effects but also because of a reduction in efficiencies for smaller plants. Still there are some other technologies available for cogeneration in the considered small scale power range the:
• Organic Rankine Cycle (ORC) Chapter 2.1
• Steam Engines Chapter 2.2
• Externally Fired Gas Turbines (EFGT) Chapter 2.3
All of the above mentioned processes could in theory be combined with conventional biomass furnaces. In Appendix G direct combustion and most common biomass furnaces are described and discussed.
2.1. Organic Rankine Cycle
The Organic Rankine Cycle (ORC) is based on the ordinary Rankine cycle, with the difference that instead of water an organic working medium is vaporized, [11]. Since the organic medium has a lower boiling point than water, the ORC has the advantage of using heat sources with substantially lower temperature than in the case of a steam cycle.
In the past, the most common way to utilize the ORC technology has been with a geothermal heat source, taking advantage of the low temperature capacity of the ORC. Another approach has been to utilize ORC systmes in the heavy industry, by using waste heat to generate electricity. There have also been technologies utilizing solar energy combined with an ORC, [11, 12]. Companies as Turboden S.r.l, Conpower Energieanlagen and Ormat, Inc have developed small ready to plug-in modules for this kind of applications, [7, 13]. Nevertheless there have been developments on the subject of biomass fired ORC plants, especially in the medium range (200 – 2000 kWel) where the ORC technology already have been established on the market as a commercial CHP method, [14].
At present there are numerous CHP plants based on the ORC-cycle and several more are under construction. The plants are mainly located in central Europe unfortunately no biomass based ORC could be identified in Sweden. A list of some manufactures and contractors involved in the ORC- market are presented in Table 2.1.
Table 2.1 Different ORC plant manufactures, [15]
Biomass furnace manufactures
Kohlbach Gruppe, Austria
Mawera Holzfeuerungsanlagen GmbH,Austria
Polytechnik Luft- und Feuerungstechnik GmbH, Austria Thermal-oil boiler
manufactures
Maxxtec AG, multi-national Kohlbach Gruppe, Austria
Mawera Holzfeuerungsanlagen GmbH, Austria HTT Energy Systems GmbH, Germany ORC module
manufactures
Turboden S. r. l, Italy Adoratec GmbH, Germany
Dresser-Rand Nadrowski Turbinen GmbH, Germany GMK Gesellschaft für Motoren und Kraftanlagen, Germany AG Kühnle, Kopp & Kausch (Siemens), multi-national Conpower Energieanlagen, Germany
Contractors and engineering companies
Bios Bioenergiesysteme GmbH,Austria Adoratec GmbH, Germany
Aldavia BioEnergy GmbH, Netherlands
2.1.1. Process Description
As mentioned there are several different manufactures of CHP plants based on the ORC- cycle, however the general process technology are the same. A process flow sheet is shown in Figure 2.1.
Figure 2.1 Process flow sheet of an ORC plant with recuperator (Lienz plant)
Biomass is burned in a common moving or fixed grate combustor with automatic ash disposal and biomass feeding system. The heat is then taken up in the boiler where thermal oil is used as heat transfer medium instead of water as in a steam cycle. The oil speeds is relatively high to avoid hot spots and keep the oil temperature in the range of 250-300°C. The exhaust gases are cooled in a gas/water economizer to increase the total boiler efficiency to about 80%. In some cases (depending on the fuel used) an air pre heater can be installed, [16].
The heated thermal oil from the boiler runs through a heat exchanger (3-6), evaporating the organic working medium (toluene, isopentane, isooctane or polysiloxane oil) present in the ORC-cycle, [16]. The evaporated medium is expanded in an axial-flow turbine (6-7) which runs at low speed allowing it to be directly connected to a generator, thus minimizing the mechanical losses. Further downstream the expanded organic medium is cooled in a regenerator (7-8) to increase the ORC-cycle efficiency. After the regenerator the organic medium is condensed in the district heat condenser (8-1) producing hot water at a temperature of 80-90°C which is suitable for district heating. Furthermore the fluid is pumped back to the thermal oil heat exchanger (1-2) to close the cycle, [16].
As mentioned the ORC-cycle is very similar to a Rankine cycle, the main difference is the thermodynamic properties of the working fluid. Figure 2.2 shows a T-S diagram for an ORC- cycle using a working medium with negative slope on the saturation curve (i.e. isopentane).
The same denotations are used as for the ORC-cycle in Figure 2.1.
Figure 2.2 T-S diagram for a typical ORC-cycle with superheating and recuperator, [17]
The recuperation illustrated by the line h7-h8 in Figure 2.2 is used to heat up the saturated fluid described by h3-h2. The thermal efficiency can be described as in Equation 2.1.
3 6
7 6
h h
w h
h pump
tot −
−
= −
η (2.1)
The main advantages of the ORC-cycle is the good partial load behavior and fairly good electrical efficiency, which is about 15% of fuel input and constant down to half load. The technology is also considered robust having long service life and relatively low maintenance cost. ORC-cycles can also operate fully automatic and unmanned, thus the technique requires very few personnel, [18]. The main drawback of using silicon oils as working medium is that it is gaseous at room temperature and highly flammable.
The main reason for using thermal oil instead of water in the boiler is that the oil system operates pressure-less at the considered temperatures span of 250-300 °C. This minimizes the wear in the cycle and prolonging the lifetime of the boiler and as there is no high pressure levels no license is needed to operate the boiler, as for steam boilers in many countries. Still the thermo-oil cycle demands higher security measures regarding leakage than water or steam, [16].
Economic Evaluation
To find out how well the ORC competes with other CHP technologies an economic evaluation was done. The method of separating the costs for electricity production from the heat part (explained in Chapter 1.3) was used to calculate the cost of electricity. Calculations
were done for three different plant sizes based on ORC modules from Turboden s.r.l with the sizes 600, 1100 and 1500 kWel (T600,T1100 and T1500), [16].
The fuel and heat powers for the 600 and 1500 kWel plant are calculated with efficiencies presented for the 1100 kWel plant by Obernberger [19], see Table 2.2
Table 2.2 Data for the plants
P(el)] [kWel] 600 1100 1500 P(th) [kWth] 3041 5575 7602 P(fuel) [kWth] 4138 7586 10345
ntot 0.88 0,88 0,88
nel 0.15 0.15 0.15
ηth 0.73 0.73 0.73
nmarg 0.79 0.79 0.79
The additional investment (Iadd) 2974 k€ for the 1100 kWel plant was taken from Obernberger [19]. This value was then used along with scale factors of 0.46 and 0.65 (calculated from Duvia [16], (See appendix B) to calculate the additional investment for the T600 and T1500 module. The results are listed in Table 2.3.
Table 2.3 Additional Investment for the considered plants
Plant 600 1100 1500
Additional investment (Iadd) [k€] 2249 2974 3642 Specific additional investment (Is,add) [€/kWel] 3748 2704 2428
The costs were divided in to capital-, consumption- and operation cost, all values was taken directly or calculated from Obernberger [19], with the exception of the economic and technical lifetime which was assumed to 20 years. The frame conditions used are presented in Table 2.4 and the calculation can be found in Appendix B
Table 2.4 Frame conditions, [19]
Capital cost
Interest rate 0.06
Economic lifetime [year] 20
Technical lifetime [year] 20
Consumption cost
Fuel price [€/MWhfuel] 15
Own electricity consumption cost [€/kWel)] 31.2
Additional costs [€/kWhel] 0,0047
General Consumption costs % of Iadd 0.2
Operation cost
Hourly rate [€/h] 30
Annual working hour [h] 800
Management (fixed for every size) [€] 5918
Maintenance cost % of Iadd 1.81
The values in Table 2.2, Table 2.3 and Table 2.4 were used to calculate the cost of electricity as a function of the number of annual operation hours. Figure 2.3 shows the results, (calculations are presented in Appendix B).
0 50 100 150 200 250 300 350
0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000
Annual full load operation hours [h]
Generation cost [€/kWh]
600kWel 1100kWel 1500kWel
Electricity sell price inclusive certificates
Figure 2.3 Electricity production costs as a function of annual operation hours
The average price for one MWhel of electricity during the years 2006-2008 in Sweden was about 39.5 €/MWhel, [20]. If including revenues from green electricity certificates (see Chapter 1.1) which currently amounts to 26 €/MWhel the total electric income becomes 55.5
€/MWhel , this is illustrated by the dotted-line in Figure 2.3. To achieve economic viability the cost of electricity must be less than the total electric income, which is the case for the 1100 and 1500 kWel if the annual full load operation hours exceeds 8000. The 600 kWel is not profitable at present electricity prices and green electricity certificate values. Nevertheless, this is only valid for Sweden, which compared to other European countries has relative low electricity prices.
Since the cost of electricity also depends on the biomass price a plot was made with the cost of biomass varying between 5 and 40 €/MWhfuel. The annual operation hours was assumed to be 6000, Figure 2.4 shows the results.
0 20 40 60 80 100 120 140 160
0 5 10 15 20 25 30 35 40 45
Fuel price [€/MWh(ncv)]
Generation cost [€/kWh]
600kWel
1100kWel
1500kWel
Electricity price inlcuding certificates
Figure 2.4 Electricity production cost vs Fuel price
Figure 2.4 it shows that the cost of electricity is linearly-dependent to the fuel price and an increase of 5 €/MWh on the biomass price will result in a 6 €/kWhel increase in electric generation cost. Even a low fuel price as 5 €/MWh will not make the technology economically viable at 6000 annual operation hours.
2.1.2. Reference Plants
It is in the late 20th century that biomass based ORC technology has been established on the CHP market. At present there are more than 50 plants in operation, and according to Goldsmith [15] there are at least 25 more under commissioning. A table of different reference plants is found in Appendix A
This chapter will discuss technical and economic advantages and drawbacks of two ORC plants located in Admont respectively Lienz, Austria. The Admont plant was chosen since it was the first European biomass fired ORC plant to be erected (1999). Thus it has already generated some long term operation data. The Lienz plant was chosen on the criteria that it was an upscale version of the Admont plant and with the know-how from Admont the costs could be minimized and therefore show a more fair representation of the economy for the ORC-technology.
Admont Plant
The Admont CHP plant is located near the sawmill STIA-Holzindustrie GmbH in Admont, Austria. The plant was the first ORC demonstration plant in the European community, with focus on cost-effective operation through combined heat and power production. Another ambition was the reduction of NOX and dust emissions with the use of an SNCR process.
The plant was commissioned in 1998 and has an electric capacity of 400 kWel along with a thermal capacity of 2250 kWth. It supplies the Benedictine monastery of Admont and STIA with space heat. In addition it supplies STIA with process heat along with 45 % of their electricity demand. The fuel utilized is solely biomass (saw dust and wood residues) from STIA, [21].
Technology
The plant was constructed with two combustion units, one thermal oil boiler and one hot- water boiler, with nominal thermal outputs of 3.2 MWth and 4.0 MWth respectively. The flue gases from the boilers are cleaned in a multi-cyclone before they are fed to a condensation unit with the capacity of 1.5 MWth, [22]. The ORC-unit which was delivered by Turboden s.r.l is connected to the thermal oil boiler and has a nominal capacity of 2.25 MWth, since 0.95 MWth of the total thermal oil power is directly used as process heat by STIA. The ORC-unit runs on a close cycle with a silicon oil as organic working fluid. The pressurised silicon oil is evaporated by the thermal oil and then expanded in a two stage axial turbine which drives a generator. The expanded silicon oil then passes a regenerator for internal recuperation after that the oil is finally condensed in a district heating heat exchanger. The condensed oil pressure is further increased by a pump and returned to the evaporator unit, thus closing the cycle. The process flow sheet is very similar to that shown in Figure 2.1, [21].
The thermal oil boiler covers the basic heat load, yet for peak load conditions the 4 MWth hot water boiler is set into operation. The flue gas from the hot water boiler uses the same condensation unit as for the thermal oil boiler. An illustration of the total plant is shown in Figure 2.5. It should be pointed out that due to technical problems the NOX reducing glue- water injection system have been replaced by adding the glue-water mixture directly in the fuel, [21].
Figure 2.5 Flow sheet of the ORC-CHP plant at Admont, [21]
System Performance
In February 1999 test runs where preformed. The test runs showed that the efficiency for the water boiler and the thermal oil boiler amounted to 89% and 70 -75% respectively. Taking the flue gas condenser into consideration an overall thermal efficiency of 90% was achieved for the whole CHP plant. For the ORC unit it was discovered that the nominal power output of 400 kWel could be achieved with lower thermal oil temperatures (>300 °C) than anticipated.
The electric efficiency of the ORC was measured to 18%. This efficiency was also achieved on partial loads down to 50% of the nominal load, which is important since it is a heat controlled CHP plant. The overall efficiency of the ORC-cycle amounts to about 98%, [21].
Technical details are presented in Table 2.5. The reliability of the plant is relatively good compared to other CHP techniques, between the year 1999 and 2005 the ORC unit reached 48000 hours of trouble free operation, except for a small number of hours stops, due to minor problems, [13]. An energy balance for the Admont plant can be found in Appendix C.
Table 2.5 Technical data for ORC- Admont Process
Pel [kW] 400 Pth [kW] 3480 Pfuel [kW] 5425
α [%] 11
ηtot [%] 72
ηmarg [%] 26
ηel [%] 7
ηTh [%] 64
Economic Evaluation
The investment of the plant excluding the hot water boiler was 3 200 000 € including monitoring and distribution costs, [21]. The other costs were evaluated using thumb rules presented in Chapter 1.3. All economic data are presented in Table 2.6 and the calculations are found in Appendix F.
Table 2.6 Economic data for ORC-Admont
Unit Data
Total investment [€] 3200000
Interest rate [%] 0.06
Economic lifetime [years] 20
Technical lifetime [years] 20
Annuity factor (a) [%] 0.087
Additional cost per fuel unit (b) [€/MWhfuel] 2.2
O&M factor (c) [%] 0.02
Fuel cost (Cfuel) [€/MWh] 16
Annual Operation Hours [h] [hours] 5000
COE [€/MWhel] 170
As seen in Table 2.6 the Admont plant has a relatively high cost of electricity. One explanation might be that the Admont plant delivers process heat directly from the thermal oil boiler, thus by-passing the ORC-cycle which results in a very low marginal efficiency (ηmarg).
It should also be pointed out that the plant is a demonstration plant which always means higher costs than for a subsequent plant when the know-how is recognized.
Lienz Plant
The biomass CHP plant in Lienz, located in the east of Tyrol in Austria is a further improved and an up-scaled version of the ORC in Admont. The aim was to demonstrate the largest European CHP plant based on an ORC process. Another innovation was the development of a Fuzzy Logic process control system in combination with an Artificial Neuronal Network for analysing, forecasting and optimising the performance of the overall CHP plant, in order to improve plant availability and efficiency as well as to reduce operation costs, [23].
The Lienz plant was commissioned in 2002 and generates 1100 kWel which is supplied to the public grid. The plant also produces 4969 kWth of heat which is supplied as district heat to the town of Lienz, with a total coverage of 70 % of all buildings. The fuel used is forest- and industrial wood chips, sawdust and bark, [11, 18, 19]. A picture of the Lienz plant is shown in Figure 2.6.
Figure 2.6 Lienz ORC plant, Austria, [23]
Technology
The plant was constructed with two biomass boilers, one hot water boiler with a nominal thermal output of 7000 kWth and one thermal oil boiler with a nominal thermal output of 6000 kWth. The thermal oil boiler is linked to the ORC-cycle with a nominal electric power of 1000 kWel, supplied by the Italian manufacture Turboden s.r.l. Two economizer units with nominal thermal outputs of 500 kWth and 1500 kWth were installed for the thermal oil and hot water boiler respectively. Moreover a 350 kWth solar collector was installed on the roof. For peak loads and stand-by system an oil boiler with a nominal thermal outputs of 11 000 kWth is used. The ORC-cycle flow sheet is the same as for the Admont plant except for the air pre- heater, shown in Figure 2.1, [23].
System Performance
The Lienz plant has been in continuous operation since the year 2002, and as the Admont plant it is operated fully heat controlled. The plant is able to operate in fully automatic mode, even under start-up and shut down procedure, [19].
The thermal efficiency of the thermal oil boiler was measured to 84 % which is substantially higher than for the Admont plant (70-75%). This could be explained by the air pre-heater utilized. The overall electric efficiency (electric energy out/ fuel energy in) amounts to 15 % at nominal load (1 MWel). The electric efficiency of the ORC cycle is 18%, which is the same as for the Admont plant. At half nominal load (0.5 MWel) the overall electric efficiency drops to 14 %, which again shows the ORC good partial load efficiencies, [23]. Tests also show that the plant can be operated at 120% of its nominal electric power. This can be very helpful during winter months when the demand is high, [18]. Currently the district heating network is expanded, in the final phase the plant is expected to run about 5000 hours per year.
Economic Evaluation
The base investment amounts to 8 959 k€ which includes the thermal oil boiler, hot water boiler (HWB) and backup boiler was divided into a heat and electricity producing part, [19].
The annual operation-, consumption- and capital costs was also regarded separately for the
electricity- and heat generating part. Worth to notice is that the electricity respective heat generating part of the plant has different economic lifetime a summary is listed in Table 2.7.
Table 2.7 Investment and annual cost CHP plant in Lienz,[19]
Investment
Investment electricity related [€] 2 974 000
Investment heat related [€] 5 985 851
Annual costs electricity related
Economic lifetime Years 20
Capital recovery factor (Interest rate = 0.06) 0.087
Capital cost [€/a] 259287
Consumption costs (fuel, electricity consumption) [€/a] 168653
Operation costs (Personnel, maintanace) [€/a] 83998
Other costs [€/a] 29740
Sum [€/a] 541678
Annual costs heat related
Economic lifetime Years 15-25
Capital costs [€/ a] 575161
Consumption costs [€/ a] 1079769
Operation costs [€/ a] 250142
Other costs [€/ a] 41901
Sum [k€/a] 1947
If the plant is in full operation 5000 hours per year, it will produce 5500 MWhel of electricity and 24845 MWhth of useful heat with a generation cost of 98 €/MWhel and 31 €/MWth
respectively. The complete economic calculations are presented in Appendix C.
2.1.3. Summary Organic Rankine Cycle
The ORC is suitable for decentralized small scale CHP applications thanks to the excellent partial load efficiency, which is beneficial when operated in a heat controlled mode. The fact that the technology is also robust and well developed besides requires very few personnel, makes it even more suitable for this kind of application. Yet the ORC-working fluid is often highly flammable which puts higher demand on fire safety measures. The thermo-oil boiler also needs higher safety precautions regarding leakages than an ordinary steam boiler. The cost of electricity for the technology is relatively high and amounts to about 100 €/MWhel for a 1 MWel plant. This means that subsidies are needed, either in the form of electricity certificates or investment grants to make the technology competitive in Sweden.
2.2. Steam Engines
Steam engines have been used since the 18th century in a variety of industrial applications, but when considering electricity production in modern time the steam engine have been out marketed by steam turbine, much because of the turbines higher electrical efficiency. As the interest for small scale biomass based CHP has increased, the steam engine might have a new era coming. One biomass based steam engine manufacture is Spilling Energie Systeme GmbH which provides commercial modules in the 1-5 MWth range. Furthermore, a new state-of-the- art screw-type steam engine has recently been demonstrated in Hartberg, Austria, [24].
2.2.1. Process Description
The steam engine works under the same principles as a steam turbine. The process is described in Figure 2.7. First combustion of biomass occurs in a boiler that produces super heated steam. The steam is then fed to the engine which drives an electrical generator. After the engine the steam is condensed by a heat exchanger connected to a district heating circuit.
The saturated fluid is further collected in a feed water tank which is pre heated by steam from the engine. The heated water is then fed back to the boiler and completing the cycle.
Figure 2.7 Simplified flow-sheet for a steam engine CHP plant
2.2.2. Reference Plants
The only cases that could be identified for this technology in the power range of 1-5 MWth
was the Spilling Energie Systeme GmbH module and the screw-type steam engine in Hartberg.
Spilling Steam Engine
Spilling Energie Systeme GmbH a German steam engine manufacture which delivers biomass based CHP plants up to 1500 kWel. There are at least 18 CHP plants based on the Spilling engine in Germany, [7].
Technology
The Spilling system uses a setup illustrated in Figure 2.8. The boiler generates superheated steam with the combustion of biomass. The steam is then used in the steam engine, which produced electric power. The expanded steam is later condensate in the district heat network or the air cooled surplus steam condenser. After condensation the saturated water is returned to the boiler.
Figure 2.8 Spilling steam engine cycle, [25]
System performance
Hansen, [26] presented performance data for a steam engine plant delivered by Spilling. The plant has an electricity power of 110 kWel , heat output of 1050 kWth and fuel power input of 1620 kWth. This results in an electric efficiency of 7% and a total efficiency of 72%. No real performence data could be identified.
Economic evaluation
According to the same presentation by Hansen [26] the specific investment of the 110 kWel
plant amounts to 3500 €/kWel. If this value is used with the assumptions in Table 2.8 and evaluated with the method presented in Chapter 1.3, the COE amounts to 133 €/MWhel, calculations is found in Appendix F.
Table 2.8 COE calculation Spilling steam engine
Pel [kW] 110
Pth [kW] 1050
Pfuel [kW] 1620
nmarg [%] 24
Total Investment
[€] 385000
Interest Rate [%] 0.06
Economic Lifetime [years] 20
Technical Lifetime [years] 20
Annuity factor (a) [%] 8.7
Additional cost per fuel unit (b) [€/MWhfuel] 2.2
O&M factor (c) [%] 2
Fuel cost (Cfuel) [€/MWh] 15
Annual Operation Hours [hours] 6000
COE [€/MWhel] 133
133 €/MWhel is a relative low COE for a plant of this size. As this technology also can deliver process steam to industries, it might increase the annual operation hours to over 7000 hours per year which would result in a COE of 124 €/MWhel.
Hartberg
The Hartberg plant is located in Styria, Austria and commissioned late in the year 2003. The plant consists of a water tube boiler and a screw-type steam engine. At nominal conditions the plant generates an electric power of 730 kWel and supplies process- and district heat to consumers with a thermal power of 4800 kWth, [24].
Hartberg Engine
The University of Dortmund in co-operation with industrial companies has developed the screw-based engine with technology from screw compressors. The engine is a rotary- displacement engine with a screw instead of cylinders and pistons, see Figure 2.9. The steam enters at the inlet (1) and is allowed to expand throughout the working chambers of the screw, and therefore decreasing the energy content of the steam. When expansion is finished (e.g. 1 bara, 100°C) the steam exits the outlet at (2) and the shaft work is extracted at (7).
Figure 2.9 Hartberg, screw-type steam engine,[24]
Technology
As seen in Figure 2.10 the flow sheet reminds much of the Spilling plant, yet there are a few differences. The engine is designed as a two-stage unit, one for high and one for low pressure steam. Since the rotational speed of the screws is high, a gear unit has to be installed before the generator. Additionally, a spray cooler is used after the super heater to ensure the steam is kept at 255°C and 25 bar.
Figure 2.10 Harberg CHP flow sheet,[24]
Performance
The screw-engine has been in almost continuous operation between November 2003 and May 2004. Under the monitoring period, the data for the calculation of efficiencies where collected. The overall net electric efficiency of the CHP plants amounted to about 10 % and the thermal efficiency was measured to 70% giving an overall efficiency of 80%, [27].
Economic Evaluation
An economic evaluation was made by Hammerschmid, [24]. The surplus specific investment costs for the CHP plant amounted to 3750 €/kWel and the COE was calculated to 138
€/MWhel. This may be considered a reasonable cost for a demonstration plant of this size.
Table 2.9 Economic data for the Hartberg plant
Investment [€] 2958750
Specific investment CHP [€/kWel] 3750
Annual operation hours [h] 5000
Fuel price [€/kWh] 0,015
Economic lifetime [years] 13
Interest rate [%] 6
COE [€/MWhel] 138
2.2.3. Summary Steam Engines
Steam engines can be considered as a well developed technology and it seems like this is a better alternative than steam turbines when considering small scale applications. With a COE of about 133-138 €/MWhel the steam engine is not the most economical solution, but it has one advantage over the other technologies, the possibility to deliver process steam. This makes the steam engine very suitable for cogeneration in for example a saw- or pulp mill. If such a plant would be erected, the COE would decrease since the annual operation hours of such a plant would probably exceed 6000 hours per year.
2.3. Externally Fired Gas Turbines
The EFGT is not a new concept, as several EFGT plants where build between the years 1930- 1960. At this time they were used to fire fuels like coal, mine gas and blast furnace gas.
Nevertheless, accessibility and reduction in costs of “clean” fossil fuels like natural gas and oil, which could be burnt in internally fired gas turbines lead to a diminish of interest in EFGT technology, [28]. At present, a new grown interest in the EFGT technology has flourished, much thanks to increasing oil and gas prices but also due to increasing focus on environmental friendly energy. The idea is to utilize an EFGT with renewable biomass. The technology is currently under development by several institutes and companies, for example University of Rostock, the Swedish Royal Institute of Technology, Talbotts Biomass Energy and Compower AB. Yet Talbotts Biomass Energy is the only company that could be identified with a commercial module currently available. Since there is only one company with a commercial module this chapter will include some promising EFGT-system under development.
2.3.1. Process Description
There are two main types of EFGT technologies, the open cycle and the closed cycle. The closed cycle has the higher total efficiency, while the open cycle has higher electrical efficiency. Both types of EFGT are presented in Figure 2.11a along with an ordinary direct fired gas turbine in Figure 2.11b.
The main difference between an EFGT and a common internally fired gas turbine is the combustion occurs outside the working fluid circuit in an EFGT. The heat from the combustion is transferred through a heat exchanger to the compressed working fluid. The working fluid is expanded in the turbine and later cooled in a heat exchanger (e.g. district heat circuit) before fed to the compressor again. The principles for open cycle is the same as for the closed with the exception of that the working fluid (usually air) after expansion is used either as combustion air in the furnace or just cooled and fed to a stack, see Figure 2.13.
Figure 2.11 a) Closed or open externally fired gas turbine b) Directly fired gas turbine, [28]
