The world of natural gas
Heat and Power Combined Heat and Power: An Overview and Guideline
The world of natural gas
Heat and Power Combined Heat and Power: An Overview and Guideline
The world of natural gas
Heat and Power Combined Heat and Power: An Overview and Guideline
GasTerra / Castel International Publishers Groningen, The Netherlands
in Driebergen, the Netherlands from a concept by GasTerra Communication. Cogen Projects is a specialist organisation in the field of CHP (Combined Heat and Power) and is a member of the Cogen Nederland and Cogen Europe associations. Please note
Contents
This book was compiled and written in 2008 by Cogen Projects,
Introduction
6
Preface
8
Chapter 1 Vision on natural gas and cogeneration 1.1 Natural gas, the national fuel 1.2 Natural gas and decentralised power generation 1.3 The role of CHP in the Netherlands 1.3.1 Power plants and industry 1.3.2 Developed areas 1.4 The future role of natural gas
11 11 12 12 12 12 13
Chapter 2 CHP in the Netherlands 2.1 CHP as a means to save primary fuels 2.2 Natural gas as a fuel for CHP 2.3 Benefits of CHP 2.4 The development of CHP in the Netherlands 2.5 CHP potential in the Netherlands 2.5.1 CHP potential for glasshouse cultivation 2.5.2 CHP potential for non-residential buildings 2.5.3 CHP potential for the industrial sector 2.5.4 CHP potential for district heating 2.5.5 CHP potential for dwellings 2.5.6 Complete overview of CHP potential up to 2020 2.6 Environmental impact of CHP in the Netherlands
15 15 18 19 20 21 21 21 22 22 23 23 23
Chapter 3 Cogeneration: from concept to realisation 3.1 Technology, design and use 3.1.1 Conversion technology 3.1.2 CHP design 3.1.3 Usage aspects 3.2 Economic analysis 3.2.1 Basic principle of economic analyses 3.2.2 Operating costs and benefits for CHP 3.2.3 Required investments 3.2.4 Influence of the energy market and energy contracts 3.2.5 Subsidies and fiscal benefits 3.2.6 Determining profitability 3.2.7 Feasibility calculations
27 29 30 44 52 56 56 59 65 67 71 72 72
that any information referred to in this book reflects its status as at 2008. English translation: September 2010 Authors: Erik Koolwijk, Peter Goudswaard, Jan Grift, Arjen de Jong, Stijn Schlatmann, Peter Steenbergen, Margot van Gastel and Ina de Visser (all of Cogen Projects), Gerard Hoek Editors GasTerra: Hans Overdiep, Henk Ensing and Ben Warner Editor Castel Mediaproducties: Arnold Assink Editor Cogen Projects: Erik Koolwijk Final editing Energy Delta Institute: Pieternel Overmars English translation and editing: WTS Vertalingen B.V. Figures and illustrations: Cogen Projects, Corbis, Asue, Nuon, Emmtec Services, Capstone Turbine Company, CFC Solutions GmbH, Gas Transport Services, MicroGen, NedStack, Daarderop, MTT, Agfa-Gevaert, Bosbad Putten, GasTerra and Axima Services Concept and design: Castel International Publishers © 2010 GasTerra / Castel International Publishers All rights reserved. No part of this publication may be reproduced, held in an automatic database or made publicly available in any form or by any means, whether electronic, mechanical, by photocopying, photography or by any other means, without prior permission from the publisher. ISBN 978 90 79147 11 3 NUR 600 www.castel.nl
www.cogenprojects.nl
www.cogen.nl
www.energydelta.com
www.cogeneurope.eu
www.gasterra.nl
3.3 Detailing and realisation 3.3.1 Final design and tendering 3.3.2 Regulations and permits 3.3.3 Financing 3.3.4 The decision-making process 3.3.5 Planning and realisation 3.4 Management and maintenance 3.4.1 Maintenance requirements 3.4.2 Contract types 3.4.3 Selection criteria for the contract type 3.4.4 Calling for outsourcing tenders 3.5 Micro CHP 3.5.1 Situation in 2008 3.5.2 Technology 3.5.3 Integrating micro CHP 3.5.4 Micro CHP in the market
76 76 78 83 85 86 89 89 90 91 92 96 96 97 102 105
Chapter 4 Example projects 4.1 Agfa-Gevaert Project, Mortsel (Belgium) 4.2 Bosbad Putten Project 4.3 Emmtec Cogeneration Project 4.4 Micro CHP Project 4.5 De Omval Cogeneration Plant Project 4.6 UMC Utrecht Power Plant Project 4.7 Amersfoort-Vathorst Dictrict Heating Project 4.8 Gebr. de Groot Kwekerijen CHP Project
109 110 113 115 118 120 123 126 129
Appendix 1 The hydraulic and steam-side integration of CHP
133
Appendix 2 Determining the size of a CHP installation
141
Appendix 3 CHP and protection of interests
147
Bibliography
148
Index
149
Corporate statement GasTerra
152
5
Introduction
Heat and Power
Introduction
GasTerra is of the opinion that natural gas will play an important role in global energy supply far into the 21st century. This view is based on facts and prognoses. It is a fact that fossil fuels still supply 90% of primary energy needs within the current time frame and that it has relatively good use properties and the least environmental impact of all fossil fuels. Gas reserves will last far into this century. In this era of transition to more sustainable forms of energy, renewable sources will gain a larger share in the energy supply. Prognoses indicate that in the total picture of supply and demand, of growth and economising and the development of alternative energy sources and current knowledge, renewable resources will gain a 20 to 30% share by the middle of this century. Even in the event of an unforeseen acceleration in the energy conservation process it is clear that natural gas will be an important energy source, together with oil and coal.
‘Heat and Power’ is one of several books in this series. The content is compiled and written by Cogen Projects in Driebergen, an expert organisation in the field of combined heat and power. GasTerra, although acting as principal, has had no contextual involvement other than this introduction but does agree with its content. Cogen Projects deserves our appreciation for this comprehensive overview, which in my expectation will contribute to knowledge and usage of CHP for the benefit of maximum energy efficiency.
Gertjan Lankhorst CEO GasTerra
This creates a double responsibility. The existing natural gas supply must be maintained at a high level whilst vigorously pursuing a transition. GasTerra considers itself an expert in the field of natural gas and in that capacity considers transition opportunities related to natural gas: what can be done more economically, cleaner and more effectively? GasTerra also feels obligated to share its knowledge in this field. Energy developments affect everyone: specialists and consumers. Discussions and choices will benefit from correct information from all concerned. GasTerra will therefore – apart from other means of transferring knowledge – publish a number of books to make this information available in the coming years.
6
7
Preface
Heat and Power
Preface
Knowledge is power; power which GasTerra wants to share.
Between 1800 and 2100 fossil fuels have and will be used in abundance. Humanity has been using natural gas, oil and coal for heat and cooking purposes for centuries but the heaviest use has occurred in our time. It has gradually increased since the origin of modern living habits and the implementation of industrial technologies to peak demand in the last decades. Yet we can look ahead with a reasonable amount of certainty at reserves and future use of fossil fuels. We know that these reserves – even though they will be available for another 500 to 1000 years – will ultimately diminish.
We emphasize that natural gas does have a major role to play for some time yet in the Netherlands, the European Union and in many other places in the world. For that reason we wish to share our natural gas knowledge with as many people as possible so that all concerned are aware of the facts and can make the most of its possibilities.
The world is faced with the enormous task of using new energy sources as large-scale replacements and successors of current fuels; preferably sources that are renewable and clean in view of the threat of possible climate change.
This publication, the second in a series entitled ‘The World of Natural Gas’ written by GasTerra and external specialists, provides an insight into the function and the role of natural gas for combined heat and power applications. The combined heat and power process (CHP) has two obvious advantages: high energy efficiency and both large and small scale applications. CHP is therefore pre-eminently suited for decentralised energy supply systems.
GasTerra has specialised in natural gas since it was established in 1963 as a consequence of the 1959 discovery of the Groningenveld, a large natural gas field. This field was supplemented by the discovery during the past 50 years of several smaller fields whose total capacity equals half that of the Groningenveld. Together these discoveries have contributed substantially to the Dutch natural gas reserves.
Other publications in the GasTerra series ‘The World of Natural Gas’ deal with natural gas and transition (published in 2008), the history of natural gas from 1963 with a view to future use in this century (published in 2009) and the gas heat pump. This will be published in 2010.
The Netherlands has developed into a natural gas country, using this natural resource in a number of ways and reducing the country’s dependency on fuels originating outside the EU. This will still apply in the next decades because – despite our decreasing reserves – the Dutch natural gas supply will suffice till after 2030. Gertjan Lankhorst Now that a considerable transition must be made to alternative and successive energy sources in the first half of this century natural gas is entering a second stage of life. The development and intensive use phases have given way to a phase in which more sustainable use of economic and high-efficiency applications contribute to a CO2 reduction and the development of renewable energy sources. GasTerra’s transition policy enables us to work towards this transition based on our specialist knowledge.
8
CEO GasTerra
9
Chapter 1 | Vision on natural gas and cogeneration
Chapter 1
Vision on natural gas and cogeneration In the first half of the twentieth century coal was the most important energy source and fuel in the Netherlands. Sporadic use was still made of natural gas, either as town gas or coal gas. In 1959 Europe’s largest gas field at that time was discovered near Slochteren, in the province of Groningen. This discovery began a revolution in the Dutch energy supply which led to a decision to connect all of the Netherlands to natural gas.
1.1 Natural gas, the national fuel The use of natural gas in the Netherlands increased substantially between 1965 and 1980. In that period natural gas became the national fuel and the most important source of energy in Dutch households, amounting to 50% of the total Dutch energy demand. About half of Dutch electricity was generated from natural gas. The share of coal in energy generation decreased from almost 80% in 1950 to 10% in 2006. Natural gas took over the entire domestic and commercial building heating market and part of the industrial steam production market. It was not just availability which caused this massive use. The fact that natural gas is by far the cleanest fossil fuel where NOx and SO2 emissions are concerned also contributed to its popularity. Natural gas also has
lower CO2 emissions than any other fossil fuel and are half that of coal for instance. The Dutch government aims to reshape the current national energy system into an energy supply based on the most sustainable sources. This transition, referred to as the transition era, requires much time and financial investment. Over the past few years several organisations have worked hard in various fields to contribute to the development of a sustainable energy management system in which far-reaching energy savings and emission reductions are policy objectives. However, even the substantial efficiency improvement achieved in fossil fuel use of the last decades does not appear to be sufficient to realise the environmental objectives, even less so with the added goal of halting climate change. The objectives of the Dutch and European governments are becoming
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Chapter 1 | Vision on natural gas and cogeneration
Heat and Power
clearer and stricter. An absolute CO2 emission reduction of 20% to 30% is aimed at for 2020. This is not the final objective but an interim one, with the final goal being an 80% to 90% reduction of CO2 in the western world by 2050, with a 50% reduction score in 2030 as an important stage on the way.
1.2 Natural gas and decentralised power generation Nearly all heat generation with natural gas is decentralised. Power generation with natural gas is partly decentralised via CHP installations. Decentralised conversion of natural gas into heat and electricity is preferred to central conversion since the transport of heat and electricity involves considerably higher losses than the transport of natural gas. Combined heat and power (CHP) is a very efficient way to simultaneously convert natural gas into both heat and electricity. Further decentralisation of this process has great benefits. Consequently, there is a strong movement in 2008 towards the introduction of smaller CHP types; Mini CHPs for non-domestic buildings and Micro CHPs for dwellings.
1.3 The role of CHP in the Netherlands 1.3.1 Power plants and industry Natural gas has become the most important fuel in the Dutch power generation sector, achieving a 60% market share in the Dutch electricity production in 2008, due mainly to improved efficiency of so called STAG technology (Steam and Gas). A STAG is a power plant driven by two turbines, one driven by the combustion of natural gas and the other by steam. The steam is produced by heating the combustion gases of the turbine in a heat recovery boiler. STAGs can achieve an efficiency of almost 60% (lower heating value) and they are flexible in meeting peak demand. This flexibility gives natural gas a unique position when it comes to electricity generation for daily, regular and even unexpected peaks in electricity demand. The only technologies at present that can fulfil a similar role are hydro power and flex fuel power plants, where flexibility comes from natural gas (source: CE Delft and ECN, 2007). STAG installations that supply both heat and electricity are in fact CHP installations. Gas turbines and gas engines are other examples of CHP installations as they also supply both electricity and heat. Gas engines are primarily used in glasshouse cultivation.
12
STAGs are the preferred choice for new power plants in many countries. 40% of electricity in the Netherlands is presently generated by a STAG, 90% comes from natural gas (CBS, Central Statistical Office, 2007). Electricity generating installations based on natural gas are, as previously stated, characterised by their large regulating capacity. Gas-fired power plants (CHP or otherwise) can quickly increase their production. Other energy sources (such as coal, oil and nuclear energy) are characterised by slow regulating capacity. For this reason the role natural gas plays in electricity production will continue to increase. At the same time efficiency must be improved through further development of STAGs and CHP systems (including Mini CHPs and Micro CHPs).
1.3.2 Developed areas A number of changes can be observed in developed areas. A decreasing trend in the consumption of natural gas in households was observed from the end of the 1970s, despite an increase in the number of dwellings. This decrease was caused by demand reduction measures (insulation), efficiency improvements in centralheating systems (high efficiency boilers) and milder winters. Research and market prognoses indicate that by 2030 the primary energy demand for heating and warm water supply in the domestic sector will decrease by approximately 20%, while the use of electricity in this period will double to almost 55%. This substantial increase in primary energy use for electricity will be caused by an increase in average domestic use and the total number of households. The number of electrical appliances is growing with the rise in number of television sets and personal computers per household coupled with the fact that more appliances run on electricity and demand for comfort, for instance with respect to air-conditioning is on the increase. A micro cogeneration installation, or Micro CHP, is a development that anticipates this increasing use of electricity. A Micro CHP is a high efficiency combi boiler which generates both heat and electricity. As a result, less electricity need be bought from the electricity company thus realising a saving. Large power plants cannot use this low quality heat and their efficiency is thus lower than that of CHP installations. Electricity generated in the home
with a Micro CHP has twice the efficiency of a modern STAG (after the reduction of transport losses). Emission reductions of up to 1,000 kilograms of CO2 per dwelling per year can be achieved. Micro CHPs have developed rapidly. The design phase and the lab test phase lie behind us and many field tests are in place. An increasing number of boiler manufacturers are working on or developing prototypes. There are now (2008) various Micro CHP technologies. These include the Stirling engine, the ORC (Organic Rankine Cycle), the gas engine, the gas turbine and the fuel cell. Each of these technologies is in a different development stage. At present the Stirling engine for compact integration with a high efficiency boiler seems to be the most advanced. Since Micro CHPs produce power based on the heat demand in a dwelling these boilers are less suitable for homes with a low heat demand, as in well insulated new buildings. Fuel cell technology, which is still being developed, is considered to be suitable for new builds as a result of the favourable relation between heat and power.
requires a different, more flexible role of natural gas in the near future, making it the ultimate transition fuel. The import (in gas and liquid form) and the addition of biogas, secures the role of natural gas in the energy supply sector for many decades to come. The combination of heat and power can be used in this context as a very efficient conversion technology to generate heat and electricity until at least 2050. ■
1.4 The future role of natural gas Energy supply in the Netherlands is based largely on the use of natural gas which is being used ever more efficiently. The design of sustainable energy supply is still undergoing development requiring a lot of time and effort of many organisations and institutions to ensure natural gas meets increasing requirements. In the time ahead natural gas as a relatively clean fossil fuel with a high conversion efficiency can fulfil this important role. More than any other EU country the Netherlands will for decades to come have sufficient gas reserves, combined with imported natural gas, for this fuel to play a prominent role in its energy supply. New and improved energy systems and technologies and the more efficient use of natural gas will ensure that national gas reserves last longer, whilst achieving an emission reduction. Within that framework new technologies are being developed such as gas heat pumps, gas cooling machines, STAG systems and Micro CHPs. Natural gas can also fulfil a useful additional role for other sustainable energy types such as solar energy, wind energy and biogas. It is quite possible to add biogas (derived from fermentation and gasification) to natural gas, so that natural gas becomes an even cleaner fuel. However, the integration of sustainable sources
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Chapter 2 | CHP in the Netherlands
Chapter 2
CHP in the Netherlands This chapter discusses the role of CHP in the various sectors in the Netherlands, as well as its background and potential for the future use of CHP. Environmental advantages of CHP such as CO2 reduction and decreased NOx emissions are also recorded.
2.1 CHP as a means to save primary fuels Most companies and buildings have energy requirements comprising both electricity and heat demands. The source of this electricity and heat in the Netherlands is traditionally a primary energy source such as natural gas, oil or coal. Heat, for instance, comes from a gas boiler and electricity is supplied by the electricity grid. This electricity in its turn comes from a power plant, which burns and converts primary fuels (Figure 1, page 17). There is, however, an alternative that can save a lot of energy by combining heat and power. Combined heat and power, or CHP in short, is in fact no more than a clever conversion method which converts primary energy efficiently into heat and electricity. ‘Plain’ electricity generation such as in power plants requires fuel that is converted into high
temperature heat. This subsequently undergoes a conversion process, producing electricity and eventually exiting the process as low temperature heat. The French physicist Nicolas Carnot was aware in 1825 that this conversion from heat to electricity is physically limited, which is why large power plants will always release a large proportion, 40 to 60%, of this excess heat energy into the environment in the form of low quality heat. This excess heat is released into rivers or the sea, or into the open air via large cooling towers. Because of the large capacities concerned this can be problematic, for instance in situations with high river water temperatures. Like normal electricity production, CHP installations also convert the primary fuel by means of combustion into high temperature
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Chapter 2 | CHP in the Netherlands
Heat and Power
heat and subsequently into electricity. The difference is that the heat in CHP installations is extracted from the process at a slightly higher temperature so that it can be put to good use, for instance as central heating at 90 °C or as steam at 10bar/180 °C, and not as cooling-water at 30 °C. The total energy loss drops to between 10% and 15% and the total use of energy increases to 85%-90% (Figure 2). Combined heat and power technology for larger installations does not differ much from that of power plants, only the location and the scale are different. The CHP installation is usually situated at the heat customer’s site and the capacity is aligned with the customer’s demands. An electricity surplus can be fed back onto the grid if required and a shortage can be purchased. Local use of electricity also avoids transport and transformation losses in the electricity grid. These can amount to a sufficient percentage to decrease the need for grid capacity. Figure 3 contains the energy saving principle of CHP, using a power plant and a natural gas boiler for reference. In this numerical example the energy saving based on primary energy (for example natural gas) is 25%. Depending on the reference and the CHP technology used, savings are usually between 15% and 35%. CO2 greenhouse gas emissions are part and parcel of burning fossil fuels, including natural gas. However, CHP reduces CO2 emissions due to its net fossil fuel saving. When comparing CHP to a reference based on natural gas, the reduction percentage is equal to the savings percentage. When CHP is compared to the fuel mixture in the Netherlands, the reduction is larger, since the average emission in the Netherlands is higher. CHP averages 230g CO2 /kWh (the CO2 reduction here is attributed entirely to electricity) and a natural gas power plant averages 360g CO2 / kWh, whereas the average power plant in the Netherlands averages 500g CO2 /kWh. Proper integration of CHP installations is required for substantial savings in energy use and energy costs. The future development of heat and electricity demands of the projected customer must be taken duly into account in the design phase, possibly through savings in the business process itself.
16
The ‘Trias Energetica’ must be followed in this case. This means that energy is saved firstly in the process itself, secondly that as much of the energy demand as possible is met by sustainable sources and finally, that primary energy is used as economically and efficiently as possible. Options chosen in the different steps of the Trias Energetica influence each other. Even though these steps are described separately, it is an integrated approach. CHP is situated in the outer layer of this model (Figure 4). Many sustainable energy applications can be combined with CHP to reach the highest possible conversion efficiency. If, for example, biomass is used to produce electricity it can best be used in a ‘bio CHP installation’. The same applies for the use of hydrogen for electricity production in a fuel cell. The dimensioning of CHP installations is discussed in the next chapter. CHP installations and heat pumps are a good combination. Heat pumps ‘pump’ heat from the environment to a higher (useful) temperature level. Heat pumps use electricity as its power source. From an energy efficiency viewpoint, heat pumps should be fed with electricity from a CHP installation. Conversely, heat should not be supplied by a boiler but by a CHP power plant or by a heat pump. For space heating, CHPs and heat pumps complement each other’s load. If a CHP installation supplies 100% of the heat a residential area must be equipped with an extra heavy duty electricity network and a transformer station to enable the transport of all generated electricity. In the same way, a residential area where 100% of the heat supply is delivered via heat pumps must also be equipped with an extra heavy duty electricity network in order to meet the electricity demand for the heat pumps. An optimum combination of CHP and heat pumps prevents an increased load on the network and the transformation station in the area and would therefore result in the most efficient conversion of primary fuels.
Conventional production Electricity 52 units
Fuel 81
Energy supply 100 units
CHP
Power plant 52%
Electricity 42
Boiler 96%
Heat 50
100
Loss 48 units
52
Heat 50%
Total 133
Total 100
Energy savings=
133 - 100 133
= 25 %
Expressed in primary energy (gas) units
Expressed in primary energy (gas) units
Figure 1 Diagram of power plant energy management.
Figure 3 Energy saving principle with CHP.
STEP 1: Limit the energy demand
Electricity 42 units
Energy supply 100 units
Fuel Electricity 42%
Heat (90°C) 50 units
1
2
3
STEP 2: Use sustainable fuels STEP 3: Use fossil fuels as cleanly as possible
Loss 8 units
Expressed in primary energy (gas) units
Figure 2 Diagram of CHP installation energy management.
Figure 4 Trias Energetica principle.
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Chapter 2 | CHP in the Netherlands
Heat and Power
2.2 Natural gas as a fuel for CHP The CHP conversion technology is in principle fuel independent. The majority of CHP installations in the Netherlands, however, are used for the conversion of natural gas. Out of a CHP total of more than 11,000 MWe in 2007, approximately 1,950 MWe consisted of installations based on coal and waste. Below is an overview of the installed capacity as per 1 January 2007:
Operational capacity per 1 January 2007 Industrial CHP ( > 30 MWe) Industrial CHP ( < 30 MWe)
2,850 MWe
(natural gas)
850 MWe
(natural gas)
District heating based on natural gas
1,850 MWe
District heating other
1,950 MWe
Gas engines in glasshouse cultivation Gas engines in buildings
(coal/waste/residual power)
2,500 MWe 750 MWe
(natural gas)
Of these approx. 500 MWe < 300kWe, or Mini CHP Total CHP capacity
10,750 MWe
Total CHP capacity on natural gas
Table 1 Installed capacity per 1 January 2007.
2,850
2,500 850
1,950
1,850
Glasshouse cultivation Buildings Mini CHP Industry > 30Mwe Industry < 30Mwe District heating natural gas District heating other
Figure 5 Installed CHP capacity in the Netherlands.
18
on CHP since the main concern is the relationship between the electricity price (the return) and the gas price (the cost), also called the ‘spark spread’ (see the next chapter). The availability of natural gas is occasionally mentioned as a future risk. However it is not that straightforward, as stated in the previous chapter and as discussed in the book entitled ‘Natural Gas as a Transition Fuel’, published by GasTerra in July 2008.
Natural gas has major benefits, the main advantages being: • Widely available; • Extremely reliable, more so than electricity or fuel transported by road; • No above ground transport (via land or water) is required; • No storage is required; • Is a flexible fuel, which can easily be used in processes and sub-processes (for example co-firing burners) and combined with other fuels (for instance residue gas or gas from water purification); • Can also be used successfully in small-scale high-efficiency installations (gas engines/turbines); • Is a clean fuel, with a modern burner technology and low NOx emission; • Is safe and enjoys a high acceptance level.
2.3 Benefits of CHP
Installations with the highest efficiency are specifically reliant on high quality fuels such as natural gas. This applies to large installations as well as but particularly to smaller installations in developed areas; the licensing body will certainly not permit any other fuel.
8,800 MWe
750
The fact that natural gas is so prominent in CHP in the Netherlands is, of course, related to the popular widespread use of this fuel. In contrast to other countries virtually all buildings and industrial estates are connected to the natural gas network system. The use of other fuels such as fuel oil or coal is strongly discouraged in the Netherlands. Furthermore, natural gas has proven to be an excellent fuel for most CHP technologies.
Natural gas for CHP installations is essential in glasshouse cultivation because flue gases must be clean enough to be recycled into the glasshouse. Plants use the CO2 contained in the flue gases for growth. This application is therefore also called CO2 fertilisation. Flue gases must be clean enough so as not to be harmful to humans or plants. Additional purification of flue gases is therefore required. The disadvantages of natural gas include its uncertain price development and/or the link between the market price and the oil price as well as the availability of gas in the long term. However the uncertain price development of natural gas has little impact
Most CHP users like to see energy savings translated into cost benefits. A substantially higher investment is required as compared to the ‘reference situation’, which only requires an investment in a boiler. The higher investment required by a CHP installation must be recovered by energy cost savings, and possibly also by the proceeds made from supply to third parties. The network connection is the same in both situations, or perhaps slightly larger for CHPs as production exceeds demand. Apart from cost benefits, CHP has other benefits for the user such as: • Energy and cost reduction; • Energy trading (Flexible / Programme Responsablity capacity); • CO2 reduction (long-term agreements / emission trading); • Generation of own power and therefore lower dependency on the purchase of grid electricity or third party steam; • Higher availability in combination with the grid; • Possible emergency power supply function; • Possible additional advantages through process integration; • Increased flexibility (sales, purchasing, stand-alone operation); • A good image (corporate social responsibility). In addition to cost saving, those who exploit CHP installations (operators) can benefit from energy trading by offering flexible capacity to the market. These installations can be put on the spot market (APX) or used by parties with Programme Responsibility (PR) for the production of regulating capacity. Benefits can also be achieved through the reduction of CO2 emissions. However this involves CO2 allocation so that this benefit shows up only partly if at all. A second effect of emission trading is the increased market price for electricity as a result of the CO2 emission trading. All power generators with CO2 savings (both CHPs and sustainable generators) could benefit from this effect.
For many companies, there are other arguments in addition to the (direct) financial ones. Increasing availability as compared to purchasing electricity from the grid and the possibility of supplying emergency power are important factors for energy intensive industries and hospitals, for example. Whether flexibility is increased by means of a CHP installation depends heavily on the integration and use of the installation. In the current energy market flexibility is an important means to increase income or reduce energy costs. CHP installations also have disadvantages for operators. These include higher investments and a requirement for trained operation and maintenance staff, which in some instances can be compensated by outsourcing the installation (also see chapter 3). In addition, the installation takes up more ambient space (noise emissions and additional emissions of, for instance, NOx, etc.). The latter is a factor to be considered when erecting CHPs on existing sites. This could be a bottleneck when limits set by environmental permits for noise, NOx, etc., have already been reached, in which case the technical and organisational aspects of the installation would be more complex than in the reference situation. This means that there will always be a certain barrier for companies to invest in CHP. To justify their higher investment costs CHP must have clear and structural economic benefits. The use of CHP provides advantages that serve the common good, the most important being energy savings, CO2 reduction, increased flexibility (regulating capacity, Programme Responsibility), no heat discharge (bottleneck for rivers), reduced electricity transport losses and costs, increased electricity grid stability and increased electricity production reliability due to an increase in production units in scattered locations. Without energy savings and CO2 reduction through CHP, it will not be possible to achieve national policy objectives in the short term. The flexible capacity of CHP installations also figures largely in offsetting variations in electricity supply caused by the unpredictability and limited regulating capacity of wind power. CHP can provide this regulating capacity, even though additional investments are required such as new or larger heat buffers,auxiliary boilers or CHP installation modifications, these extra investments must eventually be recovered.
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Chapter 2 | CHP in the Netherlands
Heat and Power
Capacity regulation and the monitoring of medium and high voltage networks require the attention of the grid operator. The electricity network can be monitored and its quality ensured by means of modern monitoring and communication technologies. CHP units of more than 5 MWe must be registered with TenneT, the high voltage grid operator, to safeguard the control of the electricity grid. The availability of these CHP units must also be reported to TenneT on an hourly basis, so that this company can monitor the available capacity.
as additions to the existing power plants (‘the combi power plant’) and later as a fully fledged Steam and Gas turbine power plant (STAG power plant, see chapter 3). Many district heating systems in the Netherlands were based on this type of central power plant in the 1970s and 1980s: a total of 42 different district heating systems were set up. The industrial sector has also built more CHP installations from the 1980s onwards but the real golden era for CHP began in the 1990s (also see the growth in Figure 6).
Because new natural gas or biogas CHP installations are currently used at locations where no attention was ever given to the technical structure of the electricity grid, these locations present technical bottlenecks with respect to the transport of electricity. Technical solutions to these bottlenecks require time and in some instances major investment. It is a short-term problem which can be solved by expanding and/or reinforcing the grid. It is important for both the long term development of decentralised CHPs and sustainable power generators that the electricity grid is designed to handle these technologies. A proper spread of CHPs generally reduces resistance and transformation losses, and grid reinforcement can in many cases be prevented.
Due to a concurrence of circumstances CHP was able to develop strongly in all sectors. The boom in the built environment and in the glasshouse cultivation sector, for example, was technically enabled by the arrival of CHPs based on natural gas engines. Apart from technological developments, the 1989 Electricity Act (Elektriciteitswet) was also an important political economic factor, allowing distribution companies to produce their own power and to bundle gas and electricity companies. The incentives policy also played an important part and the possibility of financing CHP installations by means of ‘off balance’ financing through joint ventures was discovered. Policy makers were very interested in CHPs and strongly promoted this technology via MJAs (MeerJarenAfspraken/ Long-Term Agreements) and the MAP (MilieuActiePlan/Environmental Action Plan (EAP)). Figure 7 contains the development of CHPs from 1987 up to the present day.
2.4 The development of CHP in the Netherlands At the beginning of the last century, many parties generated their own electricity for lack of a strong and reliable electricity grid. Many industrial companies generated their own power at that time, sometimes even using steam engines or steam turbines to directly power their machines. The generated steam could also be used for heating. From there, it was a small step to use back pressure steam turbines to convert high pressure steam into low pressure steam and at the same time produce electricity. We still find this concept today in many dairy and sugar factories, breweries and salt refineries. Except for industrial CHP installations,only the city of Utrecht used the residual heat from a power plant for district heating in those days. Only after 1945, during the post-war reconstruction, was district heating installed in Rotterdam as well. Gas turbines, derived from jet engines in aircraft, started to become popular for driving generators in the 1970s. These turbines were combined with conventional power plants – first
20
This rapid growth of CHP in the 1990s stagnated from 2000 onwards, mainly due to the liberalisation of the electricity market, which caused the fixed compensation for electricity fed back into the grid to lapse and the market price for electricity to fall. Despite the low gas price in those years, returns from CHP remained low because of the difference between the proceeds from electricity and natural gas costs (the spark spread, see chapter 3). CHP installations had difficulty running efficiently at marginal costs and the investment climate was not favourable. In off-peak hours, many installations would run with a negative margin and were shut down where possible. CHP installations whose economic lifespan had expired were not replaced by new installations. A positive trend with regard to CHP capacity was noticeable from the middle of 2005. Gas engines especially in glasshouse cultivation
increased, from 1,000 MWe in 2005 to approximately 2,750 MWe in 2007. This trend can be explained by a much improved result from the sale of electricity during the daytime peak, despite the high natural gas price. Investments became cost-effective again with these market prices. Profitability also increased through the use of CO2 and heat storage in buffers, so that flexible capacity could be offered on the electricity market. An increased interest in CHP is also noticeable in developed areas and in the industrial sector in 2008, which may lead to new capacity growth in these sectors.
2.5 CHP potential in the Netherlands CHP potential in the Netherlands can be divided into four different sectors, based on current technology: glasshouse cultivation, non-residential buildings, industrial sector and district heating. A fifth sector can be added, due to the development of micro CHP, namely the individual home sector. The following paragraphs give an estimate of CHP potential up to 2020. The method used was to first determine the technical potential capacity, followed by an estimate of the capacity components which can be realised by 2020 in which operational capacity, competing technologies, required build time, adaptation, etc. are taken into consideration.
2.5.1 CHP potential for glasshouse cultivation As a result of market saturation the strong increase of CHP in glasshouse cultivation will not continue in the coming years.
MWe 30,000
Assuming an operational capacity of 500 kWe per hectare for energy-intensive cultivation and an available area of 6,000 to 7,000 hectares, CHP capacity will eventually stabilise around 3,500 MWe. This is an increase of approximately 1,000 MWe compared to the current situation of 2,500 MWe operational capacity on 1 January 2008. This is shown in Figure 8 on page 22.
2.5.2 CHP potential for non-residential buildings Approximately 750 MWe of CHP is operational in 2008, mainly in larger building complexes, such as hospitals, university buildings and shopping malls. These CHP installations are usually based on gas engines. More than half of these installations have less than 300 kWe capacity. A total of ± 700 PJ (Peta Joules) of low quality heat (< 100 °C) is used in the Netherlands, an approximate ± 180 PJ of which is used in non-residential buildings. If all buildings were heated by CHP installations, assuming approximately 80% CHP heat supply and an operating time of approximately 5,000 hours per year, a CHP capacity of 7,000 MWe could be installed. When estimating the suitability of the different segments of nonresidential buildings, it becomes apparent that approximately 3,000 MWe of the theoretic potential could realistically be supplied with CHP. It is estimated that it should be possible to realise 50% of this capacity by 2020.
MWe E-power plants
CHP
Sustainable
Gas engines District heating Industrial CHP
9,000
25,000 20,000
6,000
15,000 10,000
3,000
5,000 0 1960
0
1970
1980
1990
2000
2008
Figure 6 G rowth of total operational capacity in the Netherlands (central capacity, CHP and sustainable power).
1987
1990
1993
1996
1999
2002
2005
2008
Figure 7 Increase of CHP capacity in the Netherlands (excl. coal and waste incinerators).
21
Chapter 2 | CHP in the Netherlands
Heat and Power
2.5.3 CHP potential for the industrial sector In the industrial sector, heat is used at different temperature levels and a total of approximately 4,000 MWe of CHP has already been installed, mainly in the 250 °C temperature range. The energy consumption in this range is approximately 150 PJ per year, which gives an approximate theoretic potential of 6,000 MWe. 3,700 MWe has been installed in this segment, with a potential of approximately 2,300 MWe. It is estimated that 80% of this capacity (1,800 MWe) could potentially be realised by 2020.
MWe 4,000 Glasshouse farmers own management Energy companies at glasshouse farmers
3,000
0
District heating has grown little since the late 1990s. Various projects were studied or prepared in 2008. They concern, for instance, expansions in Amsterdam (heat from Afval Energiebedrijf or Waste Energy Company), Leeuwarden, Almere, Arnhem-Nijmegen, Drechtsteden, Hengelo, Alkmaar, Leiden and Delft. Possible heat networks around the Botlek, to transport residual heat from the port area to homes and glasshouses, are also being considered. Also, existing heat networks are being compressed, which means that additional customers are added to the existing networks. The increased demand for domestic hot water counterbalances the reduced heat demand from existing customers due to milder weather and increased building quality.
22
‘92 ‘93 ‘94 ‘95 ‘96 ‘97 ‘98 ‘99 ‘00 ‘01 ‘02 ‘03 ‘04 ‘05 ‘06 ‘07 ‘08 ‘09 ‘10 ‘11 ‘12
Figure 8 Estimation of the increase of CHP in glasshouse cultivation.
The industrial sector also uses large quantities of cold generated largely by means of electricity. It consumes approximately 8% of industrial energy or 10 PJ per year. However, this cold can be supplied by CHP installations in combination with absorption chillers. The drive heat for absorption chillers is 90 °C to 120 °C. The technical potential for this type of CHP lies within a range of 1,000 to 2,000 MWe. An estimated 300MWe potential can be realised by 2020, amounting to a total industrial potential of 4,100 MWe by 2020.
2.5.4 CHP potential for district heating
of course, what capacity will actually be realised. This depends largely on environmental factors such as price development in the energy markets, the development of CO2 emission trading, government support policies and the general (economic) development in the various sectors. Local factors such as space occupancy, local permit requirements, the availability of (regional) network capacity, etc., are contributing factors.
Technically speaking, the number of CHP projects for district heating can definitely increase, if as much residual heat aspossible is distributed from existing power plants. However, these systems will not be built in a hurry, considering the issues involved with the installation of heat networks in existing built-up areas. ECN (Energieonderzoek Centrum Nederland / Energy Research Center of the Netherlands) sees virtually no growth in this sector in its reference estimations. Should the trend of the last few years continue district heating will only be expanded on a very limited scale. This book assumes a feasible limited growth potential of 1,000 MWe by 2020.
In its Schoon en Zuinig Werkprogramma (Clean and Efficient work programme), the Cabinet assumes an increase in CHP capacity of 50% of the current installed capacity. ECN subscribes to these large uncertainties and also estimates values to be around 50%, which would result in an increased in CHP capacity of 4,000 to 5,000 MWe to achieve 12,000 MWe by the year 2020.
2,000
1,000
There are some technical difficulties when it comes to the use of CHP for higher temperatures, for instance by preheating combustion air for furnaces, ovens and dryers. These uses require 377 PJ of energy. Considering the fact that this is a technically complicated application with capital intensive installations, whereby the impact on the product must also be examined, potential which could be realised by 2020 is estimated to be 10%. This still comes to 1,500 MWe.
As power plants are not always in the vicinity to supply heat, district heating in new builds will be restricted. A new district heating plant must compete with other concepts and will win this competition only in a limited number of cases. Examples of recent projects are the suburbs of Vathorst in Amersfoort and Ypenburg in The Hague, where district heating is provided via power plants with gas engines.
1,000
2.5.5 CHP potential for dwellings
750
1,500
750 1,000 300 3,300
Glasshouse cultivation Non-residential buildings Mini CHP Industry: heat IIndustry: cold District heating Micro CHP
Figure 9 Potential for CHP in the Netherlands by 2020 (MWe).
Micro CHPs are coming into focus for individual homes. The first version is based on Stirling technology and is expected to be marketed in 2010. Micro CHP installations based on fuel cells are expected in the longer term (see chapter 3). The largest Micro CHP potential is in existing homes; an approximate 6.6 million in the Netherlands. Micro CHP developers and boiler manufacturers, united in the Smart Power Foundation, expect that an approximate total of 1.5 million Micro CHP installations of 1 kWe with a total capacity of 1,500 MWe will be installed by 2020. This is the value used to determine the technical potential.
The realisation of this additional CHP capacity does not seem to be an issue, considering the estimated potential, and even a larger increase seems possible. A breakthrough of Micro or Mini CHPs opens up a whole new CHP segment and could result in a difference of 1,000 MWe or more. It is especially important that most of the savings and reduction objectives of most sectors be achieved through CHP.
2.6 Environmental impact of CHP in the Netherlands Energy savings realised by CHP were 95 PJ in 2005 (based on ECN data). ECN has determined the technical potential to be 160 to 200 PJ by 2020, whereas estimations assume savings of 130 PJ. This value is in line with the assumption that CHP capacity will increase by 50%.
750 MWe
1,500 MWe
2,250 MWe
2.5.6 Complete overview of CHP potential up to 2020
Industry: heat
3,700 MWe
3,300 MWe
7,000 MWe
Industry: cold
0 MWe
300 MWe
300 MWe
3,800 MWe
1,000 MWe
4,800 MWe
Figure 9 shows the technical potential for CHPs still to be realised for new builds by 2020. This potential can therefore be added to the potential for existing CHP installations.
Current CO2 reductions as a result of CHP amount to 6 to 8 Mtons per year (depending on references) and expectations are that this saving will increase by 3 Mtons by 2020. CHP therefore accounts for 16% of the national reduction objectives for greenhouse gas emissions by 2020 (from 214 Mtons in 1990 to 150 Mtons in 2020; see the Clean and Efficient work programme of the Ministry of Housing, Spatial Planning and the Environment (Ministerie van VROM).
0 MWe
1,500 MWe
1,500 MWe
10,750 MWe
8,600 MWe
19,350 MWe
The total estimate of over 19,000 MWe lies above the values stated by ECN in its reference estimations. ECN nevertheless also anticipates a 50% increase in CHP capacity. The big question is,
CHP based on natural gas involves NOx emissions, just like other combustion processes based on fossil fuels. This emission is not welcome, as it causes environmental acidification and unwanted
Glasshouse cultivation Non-residential buildings
District heating Micro CHP Total
Existing
Potential
Total
2,500 MWe
1,000 MWe
3,500 MWe
Table 2 Background data CHP potential.
23
Heat and Power
Chapter 2 | CHP in the Netherlands
nitrogen deposits (over-fertilisation) and has a negative influence on air quality. Emission levels for larger CHP installations based on gas turbine technology are equal to large power plants. The NOx emission of gas engines especially requires attention. This emission level is twice as high (140 g NOx/GJ) as for large power plants (45 to 65 g NOx/GJ). Government policy seems to be aiming for a required emission level of 30 g NOx/GJ for both larger installations (via emission trading) and gas engines from 2009. Gas engines can meet this requirement with the use of a catalytic flue gas cleaner. As soon as this requirement is enforced the CHP emission level with regards to fuel input (in GJ) will be entirely equal to that of other power generators. However, on a net basis emissions are substantially reduced as compared to a reference with separate generation, since 20% to 30% of the energy and related emissions is saved. ■
24
25
Chapter 3 | Cogeneration: from concept to realisation
Chapter 3
Cogeneration: from concept to realisation Cogeneration (also referred to as combined heat and power, CHP) is an exceptionally general broad term referring to various techniques and systems and can be found in various market segments. The objective of CHP is to make optimum use of electricity and heat released during the electricity generation process.
Several forms of cogeneration can be distinguished in terms of capacity: • Micro CHP for domestic purposes, with a capacity of 1 kWe to approximately 5 kWe; • Mini CHP for use in small and medium-sized enterprises or smallscale industry, in a capacity range of about 5 kWe to 300 kWe; • CHP for glasshouse cultivation, built environments and smallscale industries, with a capacity range of approximately 200 kWe to approximately 20 MWe; • Medium-sized CHP; • Large-scale CHP.
This technology, currently in a pilot phase, is aimed at anentirely different market segment than those of the other CHP types. Consequently, many of its design and economic issues call for their own unique approach. Micro CHP is therefore discussed in a dedicated section. Secondly, heat distribution is disregarded in this listing by capacity. In principle, all cogeneration variations enable the distribution of heat; the generated heat is distributed via a network to customers. The aspects involved in the construction and management of heat transport networks are not discussed in this document.
Two remarks can be made with respect to these forms of cogeneration. The first pertains to the micro CHP technology.
27
Paragraph 3.1 | Technology, design and use
Heat and Power
The structure of this chapter is in line with the four phases that must be completed in order to progress from initial
3.1 Technology, design and use
idea to concrete, running installation. These phases are described in sections 3.1 through 3.4. Section 3.5 deals with micro CHP.
Section 3.1 - Technology, design and use The possibilities for combining heat and power (CHP) are first analysed on the basis of theoretical knowledge. It is a casual thought process ‘Would it be possible to install a CHP system in our company in order to save energy?’ Basic knowledge is of particular importance in this phase. The most relevant aspects in this respect are the technology, one’s energy use and the wants of the user.
This section enters into the technological aspects of CHP installations – conversion technology, design and usage aspects – starting with a run through of the various components within CHP installations. Conventional as well as new technology is described. An analysis of the energy consumption profile is essential when designing a CHP installation. Section 3.1.2 opens with this analysis, followed by relevant design aspects such as levelling out peak demand and CO2 utilisation. Section 3.1
Section 3.2 - Economic analysis
closes with a description of the hydraulic, electrical and structural integration of CHP systems. The usage aspects of CHP
Once the technical options have been examined and the CHP system that best suits the specified wants has been determined, the project can proceed with an economic analysis of the CHP installation. It is important in this respect to thoroughly investigate the following points: • Basic principles of an economic analysis • Investment and maintenance costs • Energy market • Subsidies and support
installations are discussed in section 3.1.3.
Section 3.3 – Detailing and realisation After all options have been investigated and the CHP system with the highest cost-effectiveness has been identified, the implementation phase can commence. This phase includes the final design, legislation or permits, the decision-making process, and planning and realisation.
Section 3.4 – Management and maintenance Once the installation has been realised it must, of course, keep running. This requires a watchful eye on such matters as management, maintenance and control.
Section 3.5 – Micro CHP The micro CHP technologies are currently in a pilot phase. Section 3.5 discusses the development of this technology, whose main aspects and characteristics are being documented by means of various tests. The four steps that apply to the other CHP installations are followed here as well.
28
CHP installations Figure 1 contains a schematic depiction of a CHP installation as it is generally used. The figure depicts the CHP installation as a black box in which air and fuel are converted into electricity and heat. The CHP installation in this black box is a combination of the converter that produces mechanical energy in addition to heat, the heat transfer system and a generator. The generator converts the mechanical energy into electricity. The entire CHP system comprises the electricity and heat converter plus the required installation and connections. A gas connection is needed for the supply of gas. A connection to the electricity grid is essential for integrating the CHP installation and for the possibility of feeding electricity back into the grid. Generally speaking, the installation is required to have a security and a control system as well as an installation room designed to limit any nuisance (vibrations and noise). Other important aspects in the entire system are the electricity and gas connections. Often, more electricity is produced than is required for one’s own needs; therefore, the possibility of feeding electricity back into the electricity grid is essential for most CHP systems. The gas network’s pressure and capacity must also be taken into account.
The generator is an important part of the CHP installation. The entire electrical output of the installation depends on the efficiency of this generator and of the mechanical conversion. This efficiency is between 96% and 98% and hinges on the quality of the installation. This is an important point of consideration in deciding on the whole CHP installation, because it also establishes the generator losses during the installation’s entire life span. The highest efficiency of most generators is approximately 80% of their maximum load.
Flue gas Air Natural gas Gas connection
CHP: Converter Generator Heat production Control Safety Installation room
Steam / hot water Consumption
Electricity Consumption
Grid connection
Figure 1 Black box of a CHP installation running on natural gas.
29
Paragraph 3.1 | Technology, design and use
Heat and Power
3.1.1 Conversion technology Various technologies apply for CHP installations. The choice of technique is dependent on use and operating time, electricity and heat requirements, and desired temperature (steam or hot water). The most popularly used technologies at this point in time are gas engines, steam turbines, gas turbines and steam and gas (STAG) power plants. In addition to these favoured technologies, the following new technologies are already being used (to a limited extent) in CHP installations or promise to be used in the future: the Organic Rankine Cycle (ORC), fuel cells, the Solid Oxide Fuel Cell (SOFC) gas turbine system and trigeneration. Other technologies are used for micro CHP, such as the Stirling engine and the micro gas turbine. These techniques are described in section 3.5. Figure 2 provides an indication of the electrical output and the capacity of the various technologies. Obviously, small-scale CHP installations call for other techniques than those for large-scale installations.
Heat use In principle, there are two ways to remove heat created through the combustion process in the CHP installations. Firstly, by ‘direct’ cooling of the installation (such as machine or oil cooling) and secondly with flue gases. The ratio between both streams depends
80%
SOFC+gas turbine
70%
Electrical Efficiency
60% 50% 40%
HT fuel cells (SOFC, MCFC)
STAG
LT fuel cells (PAM, PEFC)
30%
Steam turbine
10%
0.1
1
10
100
1,000
Capacity (MW)
Figure 2 Field of application and output of various techniques.
30
Gas engines Gas engine is the generic term for piston engines that run on a gaseous fuel. In the Netherlands, most small-scale CHP applications are based on gas engines. Gas engines are used in CHP installations in various places. Examples can be found in greenhouses, the oil and gas industry, office buildings, swimming pools and hospitals. The performance range of engines lies roughly between 0.2 and 10 MWe. Occasionally, various CHP units are combined at one location to ensure controllability or operational security. The greatest benefit of gas engines is their relatively low cost and high electrical and thermal output. Gas engines are produced in series, are reliable and virtually at the top of their development. The required maintenance is relatively easy to learn and can therefore be performed to a large extent by the user and his technical staff, limiting whatever maintenance costs : (for activities carried out by an external party) remain. As the engines are produced in series, parts are usually readily available. Furthermore, integration into the gas and electricity network on site is taken into account during their production so that these costs too can be kept to a minimum. Of course, costs are still involved in connecting up to the grid of the grid operator. As an additional advantage gas engines can reach their maximum capacity relatively quickly, although special provisions are required to do so. This helps make them suitable for ‘emergency power’.
to approximately 110°C) it can be provided through the heat from an engine’s flue gases. However, this is at the expense of the total energy output. Also, the number of maintenance services is slightly higher than for gas turbines as they require more frequent fine-tuning, inspections and oil changes. Furthermore, gas engines emit more nitric oxide (NOx) and unburned hydrocarbons. This can be solved to some extent by using techniques such as catalytic reduction. Gas engines have a net electrical output of approximately 30% to 45% and a net thermal output of 45% to 55% (Figure 3, page 32), resulting in a total output of 85% to 95% (Figure 4, page 32). These values are based on the lower calorific value of natural gas. In principle, suppliers of gas engines for CHP installations can assemble any desired configuration, thus meeting the customer’s temperature and capacity needs as closely as possible.
Operating principle Gas engines for CHP applications run on the four-stroke principle; the process completes four steps in one cylinder. Figure 5 (page 32) contains a simplified depiction of a gas engine cylinder. • A mixture of fuel gas and air is drawn in upon the suction stroke. The inlet valve of the cylinder is then open. • This is followed by the compression stroke: the valves are closed and the mixture is compressed. Pressure and temperature rise and just before the end of the compression stroke a spark plug ignites the mixture. The mixture ignites (burns) and both the pressure and the temperature increase rapidly. • The mixture expands, making the piston drive the crankshaft. The actual energy is produced in this expansion stroke. • In the fourth stroke the piston drives the mixture through the open outlet valve to the exhaust system.
Gas engine installed at University Medical Centre Groningen.
Gas turbine Gas engine
20%
0% 0.01
heavily on the selected technique. For instance, machine cooling in the event of gas engines (of the engine block, the oil cooler and ‘intercoolers’) forms a considerable part of the total heat flow (approximately 50% of the total heat). In the event of gas turbines, on the other hand, virtually all heat in the exhaust is released in the form of flue gases.
A special point of attention with regard to gas engines is the noise and vibrations they produce. Installing a gas engine in the work space of a utility building, for instance, therefore requires ample consideration. Furthermore, the power density of gas engines is low as compared to that of gas turbines. In other words, gas engines with the same capacity are relatively bigger. Gas engines are particularly suitable for producing hot water up to approximately 100°C. If low pressure steam is required (up
31
Paragraph 3.1 | Technology, design and use
Heat and Power
50%
Spark plug 45%
Air inlet
Flue gas outlet
Electrical capacity
40%
Piston
36 %
35%
34 % 32 % 30 %
30%
28 % 26 % 24 %
25%
22 %
Crankshaft
20 %
0
20%
0
200
400
600
800
1,000
10
20
1,200
30
40
1,400
50
60
1,600
70
80
90
1,800
100
2,000
Electrical capacity in kW
Crankcase
Figure 3 Electrical output of gasengines as function of the volume. Source: Asue
Modern, large gas engines are usually equipped with a turbocharger. They are referred to as turbo charged engines. The engine’s hot exhaust fumes drive an air compressor in the inlet via an expansion turbine in the exhaust duct. By using a turbocharger the same engine produces considerably more power, increasing the electrical output. A turbocharger is usually not used for smaller gas engines (< 100 kWe) making them relatively less expensive to purchase. When using a gas engine a major part of the useful heat is released in the form of exhaust fumes. Furthermore, heat is released in the engine block’s cooling system, the lubricant and the compressed combustion air after the turbocharger (the intercooler). This forms a considerable part of a gas engine’s heat (approximately 50% of all heat). The heat is made available for use through a hot water system (Figure 6). A distinction is made between high temperature heat (temperature between approximately 90°C and 70°C) and low temperature heat (temperature between approximately 50°C and 30°C).
There are various ways to combine the cooling circuits. It is important in this respect that the cooling of the lubricant and the engine block is fed with cooling water below 70°C. If the inlet temperature of the cooling water is any higher the engine will stop running as the safety device will kick in. To keep the gas engine running when the temperature of the cooling water that goes into the machine is not cold enough (for emergency power, for instance) the inlet temperature of the cooling water must be kept below the permitted 70°C. This can be achieved by cooling the recycled water with a ‘dry horizontal cooler’ (see picture on page 33): a heat exchanger fitted with a ventilator to discharge the heat into the environment. Depending on the heat user’s desired temperature the heat from the flue gas condenser and from the cooling of the turbocharger can or cannot be used efficiently. A greenhouse grower, for instance, who has a gas engine CHP, will generally be able to make efficient
A horizontal cooler alongside a heat buffer.
Figure 5 Simplified depiction of a gas engine cylinder.
100%
Not used
90%
Exhaust 5%
Thermal LT
80%
Condensation 8%
Total Efficiency
70% 60%
Condenser
18%
Thermal
Exhaust cooler
p
50% 40% Natural gas 100%
30% 20%
Hot water 41% Radiation and Convection 4% Generator 2% Electricity 40%
Gas engine
Air
Electrical
Turbocharger
10% 15%
0% 35%
36%
37%
38%
39%
40%
41%
42%
43%
44%
45%
5%
Engine block cooler Oil cooler
3% Intercooler
Electrical Efficiency
Figure 4 R elation between electrical and thermal output of gasengines (LEI).
32
Figure 6 Diagram of a gas engine.
33
Paragraph 3.1 | Technology, design and use
Heat and Power
use of the low temperature (LT) heat as he has a large LT heating system. If no LT grid is available, the heat is not used efficiently. The temperature of the flue gases released from the gas engine is between 350°C and 500°C, which is much lower than the temperature of flue gases released from a gas turbine. The hot flue gases can be used directly in thermal processes such as dryers, or indirectly by means of heat exchangers. They can cool down in stages. It is possible to use the flue gases to produce both steam and hot water for central heating, and hot water for tap water, for instance. The successive heat exchangers are then called steam generator, economiser and flue gas condenser. In such a case the total system performance comes to 90% net heat. Modern gas engines with a high excess air factor are used to limit the emission of nitric oxides. This keeps the combustion temperature in the cylinder under control. As a result the flue gases still contain large amounts of unused oxygen. When an operation requires steam it is useful to conduct the flue gases through a heat recovery boiler (also called Heat Recovery Steam Generator (HRSG)) fitted with a gas burner in order to increase the temperature from 400°C to around 800°C. With this heat, steam, central heating water and low temperature heat can be produced with a very high boiler efficiency (almost 100%).
their long life span (25 to 35 years). A significant disadvantage is their installation period, which varies from 12 to 18 months for small-scale systems up to three years for large-scale systems. Depending on how their energy flows are utilised, steam turbines have an electrical output of 25% to 40% and a total output of approximately 85%.
Operating principle Installations based on steam turbines basically consist of four components: a steam boiler, a steam grid, a steam turbine and a heat consumer. The steam boiler or the heat recovery boiler generates water into superheated steam whose pressure in some systems exceeds 100 bars. This process takes place in a number of steps. The feed water is pressurised by boiler feed water pumps and enters the boiler via the economiser. In the economiser the water is heated to just below boiling point and flows from there into the steam drum. Water circulates from this steam drum through the evaporator by natural or forced circulation (the latter by means of pumps).
Fuel
Example of a steam turbine. Source: Corbis
Steam boiler
Turbine
Condensate from process
Figure 7 Simplified diagram of a back pressure steam turbine.
Generator Fuel
Turbines with reheaters are often connected in series to increase output. After the steam has expanded in the first high pressure turbine it is transported to reheaters that raise the temperature at the same pressure. The steam is then transported to a low pressure turbine. It is necessary to reheat or mix the steam with higher pressure steam because the turbines can only tolerate superheated steam. Should the steam condense in the turbine, drops of water are created that can cause significant damage to the turbine vanes which turn at such high velocities that the drops can create craters in the vanes. The humidity in a turbine may therefore not exceed 14%.
Steam boiler
Turbine Process steam Condenser
Cooling water
Condensate
This means that the steam in the last step of the turbine expands to conditions under the atmospheric pressure (Figure 8). The emphasis lies in this case on electricity production.
In this method a steam turbine is used to convert the potential energy from high pressure steam (40 to 80 bar) into electricity before using the low pressure steam at the outlet of the steam turbine for process heating (5 to 20 bar). This is a technique that is often applied in the industrial sector. Often, a gas turbine’s steam boiler or heat recovery boiler produces overheated high pressure steam (for instance 60 to 80 bars) which is then transported via a central steam grid. This steam is then used to drive a steam turbine with which electricity is generated. The reduced pressure steam at the outlet of the steam turbine can then be used for process purposes such as process heating and air humidification.
34
Generator
Process steam
In some systems the steam temperature reaches 540°C. The superheated steam is conducted from the boiler to a steam turbine where the steam expands and sets the vanes of the turbine axle in motion. In Figure 7 the steam does not condense but is used at a lower pressure as process steam. Consequently, it is referred to as a back pressure steam turbine. The heat from the flue gases of the steam boiler is cooled by the superheater, the evaporator and the economiser successively, after which a flue gas condenser can be linked if necessary. The feed water is preheated by means of the flue gas condenser before entering the boiler. In some cases the combustion air is preheated by the ‘last remaining heat’ in the flue gases by means of an air preheater. Configurations can also comprise various turbines connected in series. For this process or for district heating, for instance, steam is tapped off in between the turbines. Should some of the steam not be used for heating or as process steam, the steam turbine can also be used as a condensing unit
Steam turbines
Large steam turbines have several strong features including their high reliability, high availability percentage (less down time) and
In the evaporator, part of the water evaporates into steam. This steam and water mixture then flows back into the drum. In the drum, the steam and water are separated. The water flows together with water from the economisers back into the evaporator and the steam exits the drum in the direction of the superheater. In the superheater the steam is heated to the desired temperature.
Condensate drum
Figure 8 S implified diagram of a condensing steam turbine with draw-off.
Gas turbines Because of their high reliability and their ability to produce high pressure steam in the heat recovery boiler, gas turbines are often applied in the industrial sector. Furthermore, gas turbines are the most suitable option if they operate throughout the entire year. Gas turbines produce mechanical energy by injecting and burning gaseous or liquid fuel into compressed air which expands as a hot gas in the turbine. Part of the released
35
Paragraph 3.1 | Technology, design and use
Heat and Power
The flow of air in a radial turbine is changed 90 degrees. This technique is related to the turbo chargers that are used in gas and diesel engines. The use of micro turbines is described in more detail in section 3.5. A so-called heat recovery boiler (a heat exchanger placed in the flue gas exhaust outlet of the gas turbine) can make hot water or steam. The maximum steam temperature is 25°C to 40°C lower than the flue gas temperature at the turbine’s exhaust outlet while the steam pressure can reach an approximate maximum of 80 bars depending on its projected use. If a higher temperature and pressure is required, a heat recovery boiler with gas burner inserts can be used for additional combustion (co-firing). No additional air is generally needed because the flue gases of the gas turbine still contain an oxygen concentration of approximately 15% due to a large amount of excess air in the gas turbine’s supply of combustion air. Example of a gas turbine. Source: Corbis
mechanical energy is used to compress combustion air. Fuel must also be pressurised if it is not available at the required pressure. Advantages of gas turbines include low maintenance costs, clean flue gases and high fuel flexibility. Reliability and limited maintenance effort as compared with other systems are also major advantages. As a result gas turbines are very suitable for full year use (base load operations). Consequently, they are the preferred choice in the industrial sector. Disadvantages of gas turbines are their higher capital and component costs. Because of this gas turbines require many operating hours to counteract these disadvantages. Also, the number of starts and stops must be kept to a minimum (preferably fewer than 20 per year). Gas turbines can achieve an electrical efficiency of 25% to 40%; depending on their configuration and the heat reduction total efficiency comes to approximately 80% to 90% (Figure 9).
36
Operating principle Gas turbines comprise three main components: compressor, combustion chamber and (expansion) turbine. The compressor compresses indrawn air and feeds this into the combustion chamber where fuel is injected into the compressed air and burns as a hot gas. The increased temperature increases the gas volume. The subsequent hot combustion gases then expand in the turbine. Unlike gas engines, gas turbines run in a continuous process (Figure 10). Micro gas turbines (smaller than 5 kWe) and mini gas turbines (up to 100 kWe) are smaller scale options. The drawback of small capacities is their low conversion efficiency which is partially overcome by applying a recuperator. In this recuperator some of the heat from the flue gases is used to heat up the compressed air before it enters the combustion chamber. Also, the combustion
The efficiency of gas turbines is influenced by temperature and air density. These factors determine the required energy for compression, the amount of fuel that can be burned and the amount of fuel to reach the desired temperature for the turbine inlet. Part load operations can also lower a turbine’s efficiency. Figure 13 (page 39) provides an indication of the effect of part load and air inlet temperature on the efficiency of a gas turbine system. In gas turbines heat from the flue gases can be recovered and used to reheat combustion air that has already been compressed, thus significantly increasing efficiency. This is also referred to as recuperation (Figure 14). However, the use of recuperators has several disadvantages. Recuperators are often bulky and difficult to build in a way that will withstand major changes in temperature over long periods of time. Furthermore, these turbine installations are more complex. The maximum steam temperature drops when the heat from the
45
Electrical efficiency (%)
air in the compressor and the flue gases in the expansion turbine flow in a different direction than the larger gasturbines. Axial turbines are often used for larger capacities; their flow runs parallel to the axle. Figures 11 and 12 contain examples of both turbines (page 38).
40 35 30 25 20 15 10 5 0 1
10
100
1,000
Electrical capacity (MWe)
Figure 9 Electrical efficiency og gasturbines as a function of the capacity (based on ASUE).
Flue gas Process steam or heat
Fuel Compressor
Combustion chamber
Flue gas
Turbine Air inlet
Figure 10 S implified diagram of a gas turbine with heat recovery boiler.
flue gases is released to the compressed combustion air and the temperature of the exhaust fumes after the recuperator is significantly lower. Not many gas turbines have as yet been fitted with a recuperator. Those that have are generally small-scale gas turbines below 1 MWe. The steam produced in the heat recovery boiler can be used for process purposes as well as for injection into the combustion chamber: the so-called steam injected gas turbine (STIG, Figure 15). The steam lowers the combustion temperature thus
37
Paragraph 3.1 | Technology, design and use
Heat and Power
Steam and gas power plants (STAG) STAGs are a combined process of steam and gas turbines (combined Joule-Rankine cycle). These systems are costly, but they can reach very high electrical and thermal efficiencies. STAGs are therefore frequently applied in large-scale CHP installations in the industrial sector (30 to 400 MW). A gas turbine is used as a basis for the installation. The hot flue gases of the gas turbine are used in a heat recovery boiler to produce steam (as described previously). This steam is not supplied directly to the process but instead at higher pressure to a steam turbine. Steam then flows from the steam turbine at a lower pressure to the industrial processes. The expansion of the steam in the turbine produces energy with which a generator can produce electricity.
By connecting a gas turbine to a steam turbine a total efficiency of 80% to 90% can be reached if the residual steam is still used as process steam or for district heating. Electrical efficiency of STAG power plants varies between 42% and 58% depending on the heat supply. An electrical efficiency of 58% can only be achieved if all steam is expanded via turbines to below the atmospheric pressure. The principle diagram of the STAG in Figure 16 is one of many possible configurations. In the configuration chosen here all steam is supplied to the process after it has been expanded in the steam turbine. This kind of steam turbine is also called a back pressure turbine. When opting for maximum reliability of heat supply in addition to flexibility, a co-firing burner with additional combustion air ventilators can be installed. These ventilators start working only when the gas turbine malfunctions. Valves close the outlet of the gas turbine and open the inlet of the ventilators. This option is also referred to as ‘cold air operations’ (Figure 17, page 41). It is not commonly applied as the costs are high and the installation is more liable to malfunction due to the flue gas valves and other additional components.
32
Flue gas 30
Heat recovery boiler
Process steam Electrical efficiency (%)
preventing the formation of NOx. The total mass flow in the combustion chamber and the expansion turbine increases, thereby releasing more energy. On the other hand, additional energy is required because the back pressure for the compressor increases. Ultimately, the net electrical efficiency increases when steam injection is applied. However, in using the steam the thermal efficiency drops significantly.
28
(Steam injection) Fuel
26
Fuel
Combustion chamber
Compressor
24
Flue gas
T = 5 ºC T = 15 ºC
22
T = 25 ºC
Turbine Air inlet
T = 35 ºC 20 50
60
70
80
90
100
Part load (%)
Figure 13 Effect of part load and inlet temperature of air on the electrical efficiency of a gas turbine system.
Figure 15 Simplified diagram of a gas turbine with heat recovery boiler and steam injection.
Recuperator
Heat recovery boiler Process steam
Fuel
Compressor
Fuel
Combustion chamber
Flue gas
Verbrandingskamer
Flue gas Steam turbine
Compressor Turbine Air inlet
Figure 14 Simplified diagram of a recuperating gas turbine.
Figure 11 Cross-section of an axial gas turbine. Source: Asue
38
Air inlet
Gasturbine
Figure 16 Diagram of a possible STAG system (back pressure system).
Figure 12 Cross-section of a radial gas turbine. Source: Capstone Turbine Company
39
Paragraph 3.1 | Technology, design and use
Heat and Power
Another way to create more flexibility is a STAG with a drawoff steam turbine (Figure 18). With the gas turbine at constant capacity the heat supply can be adjusted to the customer’s demand with tapped steam. The heat/power ratio can therefore vary between 1 and 0. This creates a high-efficiency and high-flexibility installation. Most of the larger CHP plants in the industrial sector such as Delesto 2 in Delfzijl and Elsta in Terneuzen are of this type. STAGs can also be designed with a gas turbine that operates constantly even if there is no heat demand. To prevent unnecessary blow off or cooling of steam, a by-pass chimney can be installed (Figure 19) in which the turbine’s flue gases are blown off directly. From an energy point of view the use of the by-pass chimney is, of course, unwelcome. This option is applicable mainly when supply reliability is essential, such as when the installation also serves to provide emergency power. A frequently used option for increasing the efficiency of a STAG cycle is the use of a multi-pressure boiler. In this boiler, steam is produced at two, three and even four pressure levels. Because the construction is more expensive, the number of pressure systems generally increases as capacity increases. Installations of less than 30 MWe usually use one pressure. The largest STAG installations, with triple-pressure boilers or quadruple-pressure boilers can reach an electrical efficiency of approximately 60% if no heat is supplied. Figure 20 contains a diagram of a double-pressure boiler. Every pressure system has its own boiler feed water inlet, economiser, evaporator, steam drum and super-heater. These are arranged so as to make optimum use of the heat in the flue gases. The diagram also shows a separate hot water heat exchanger with which the last remaining heat is utilised (19 MWth). In this example, the flue gas is cooled to 75°C. The gas turbine and the steam turbine in a double-pressure boiler are connected to one axle. Both turbines therefore drive the same generator. The advantage of this system is that it requires a lower investment. On the other hand the operational management of the installation is more complex. Especially at industrial sites where various gas turbines with heat recovery boilers can be connected to one high-pressure steam grid. In their turn, one
40
or more steam turbines are connected to the steam grid. These steam turbines can even be distributed over the site and can drive machines, such as large compressors, directly.
Organic Rankine Cycles (ORC) Linking an Organic Rankine Cycle as a subsequent process to a CHP installation increases the electrical efficiency of the installation, but it does lower the thermal efficiency of the CHP installation. ORCs are able to generate electricity with ‘low-quality’ heat when a steam turbine no longer works properly. The ORCs currently available are characterised by major differences in price, maintenance and usage range (based on temperature). Calculations show that with an ORC linked to a gas engine the total electrical efficiency improves by 4 to 8 percent. An ORC linked to a gas turbine improves the electrical efficiency by 10 to 14 percent, for instance from 25% to 36%. The power/heat ratio can therefore increase by more than 25%.
Operating principle An ORC is a closed system in which an organic liquid (such as isobutene, pentane, hexane, toluene or ammonia) is evaporated in a heat exchanger placed in the flue gases of a gas engine, gas turbine or hot water boiler. The gas then expands in a turbine that drives a generator. In the condenser this gas must again condense, whereby it releases its heat either to a hot water system or unused into the environment. Natural cooling by means of horizontal coolers takes a lot of electrical energy which is disadvantageous for the electrical output (Figure 21, page 43). The type of ORC depends heavily on the temperature level of the heat source.
Fuel cells Fuel cells do not work on the basis of mechanical conversion into electricity, but are based on an electrochemical conversion technology in which hydrogen reacts with oxygen which produces electricity and steam. Unlike the other technologies the efficiency of the fuel cell is not limited by the maximum temperature difference in the cycle (the so-called Carnot efficiency). In practice, however, various losses occur in the components of the fuel cell system. Commercially obtainable fuel cells have an electrical efficiency of 37% to 45%, depending on the fuel
Chimney
Combustion air ventilator
Fuel
Chimney
By-pass chimney
Fuel
Fuel
Combustion air ventilator
Fuel
Steam turbine Gas turbine
Air inlet
Process steam
Figure 19
Figure 17 Co-firing with cold air operation.
Heat recovery boiler
Flue gas
Steam turbine
Compressor
STAG with by-pass chimney.
4
Medium pressure steam Condensor
Cooling water
5
3
2
5
3
1
HP steam
Figure 18 STAG with draw-off.
Flue gas ~ 75 °C
4
Low pressure steam Gasturbine
Air inlet
Steam turbine Process steam
Gas turbine
1: Feed water inlet 2: Economiser 3: Evaporator 4: Steam drum 5: Super-heater
Fuel Combustion chamber
Air inlet
2
1
Hot water
LP steam
Figure 20 Diagram of a double-pressure boiler.
41
Paragraph 3.1 | Technology, design and use
Heat and Power
rities such as sulphur compounds must be removed as they have a major impact on the life span of the stack. The temperature of high temperature fuel cells (MCFCs, SOFCs) is high enough to reform the natural gas in the fuel cell itself. Low temperature fuel cells (AFCs, PEFCs and PAFCs) require a separate reformer. Because of their low operating temperature the latter fuel cells are less vulnerable to start-stops than high temperature fuel cells.
SOFC / gas turbine hybrid systems By combining a Solid Oxide Fuel Cell (SOFC) with a micro/mini gas turbine electrical efficiencies of 60% to 70% can be achieved. A turbine-driven compressor pressurises the SOFC and keeps it at 4 bars or more (Figure 23, page 45). The cell’s efficiency improves at this increased pressure. The SOFC’s high temperature flue gases (approximately 1000°C) are co-fired with natural gas. These gases then expand in the turbine that drives not only the compressor but a generator as well, thereby producing even higher amounts of additional electricity.
Trigeneration Many industrial processes and utility complexes require cooling in addition to electricity, steam and hot water. Trigeneration is
an option in this respect. This is a concept whereby cooling is generated in addition to heat and electricity with the residual heat of the CHP installation. An absorption chiller is the device that uses the residual heat for cooling.
Operating principle of absorption chillers Absorption chillers operate in the same way as compression coolers. Pressure is increased in the liquid phase by means of a pump instead of a compressor (Figure 24). Heating occurs by means of residual heat. Absorption chillers generally contain three liquids: an internal solution of water with lithium and bromide, the liquid that is cooled and the cooling water that absorbs the heat. Then there is the heat source (steam or hot water) that drives the cycle. The energy from the steam or from the hot exhaust gases of the CHP installation is used to separate the components, such as water and lithium-bromide in the generator. When the separated water evaporates again (in the evaporator) after condensing and expanding at lower pressure the heat can be absorbed at low temperature (the cooling side). The heat released in the condenser and the absorber is transported in water to a cooling tower.
ORC fed with flue gases (Turboden).
quality and the operating conditions. Electrical efficiencies of over 50% are expected in the future. Even higher system efficiencies can be achieved by combining fuel cells with other technologies. On paper, the combination of a high temperature fuel cell with a gas turbine generates electrical efficiencies of over 70%.
Operating principle Fuel cells consist of two electrodes: an anode and a cathode separated by an electrolyte. An electrolyte is a conductive material whereby the electricity is produced by positively or negatively charged molecules, so-called ions (Figure 22). Hydrogen is added to the anode and oxygen from the air is added to the cathode. The hydrogen atom is split at the anode into protons and electrons. In the electrolyte, the protons (H+) diffuse to the cathode, while the electrons (e-) move to the cathode side via an external circuit. The electron current that flows via this external circuit
42
is a usable form of electricity. On the cathode side the protons and electrons come together again and react with the oxygen, creating a water molecule.
Heat in
eEvaporator
To achieve the required voltage and capacity the separate cells are placed in a modular arrangement. Usually, the cells are stacked in flat stacks. High temperature fuel cells are arranged in tubular stacks. Fuel cells are generally categorised by type of electrolyte. The choice of material for the electrolyte greatly determines the other design variables. Table 1 (page 44) lists the characteristics of the five main types: Alkaline Fuel Cells (AFCs), Phosphoric Acid Fuel Cells (PAFCs), Polymer Electrolyte Fuel Cells (PEFCs), Molten Carbonate Fuel Cells (MCFCs) and Solid Oxide Fuel Cells (SOFCs). To use natural gas in fuel cells, natural gas must be converted into hydrogen. This is referred to as reforming natural gas. Impu-
Fuel in
Oxidant in H2
Turbine
Heat out
Figure 21 Simplified diagram of an ORC.
½C2
or H2O
Condenser
Positive ion
Negative ion
Flue gasses
H2O
Oxidant out Anode
Electrolyte
Cathode
Figure 22 Diagram of a fuel cell (based on EG&G Technical Services).
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Paragraph 3.1 | Technology, design and use
Heat and Power
3.1.2 CHP design CHP installations must undergo a feasibility study prior to installation. The following aspects are important in this respect (Figure 25, page 46): • The energy savings that can be realised in advance; • The volume and duration of the electricity and heat demand; • Whether the heat demand can be met by CHP heat production (temperature levels); • Planned process changes (such as expansions) that could affect the heat or electricity demand; • The concurrence or non-concurrence of supply and demand; • The available space and the supporting surface area for the CHP system; • A possible link to the electricity grid; • The distance to the heat users or heat networks; • The integration of CHP in relation to other facilities such as boilers, emergency power generators and compression or absorption coolers. External factors, such as the rates during peak and off-peak hours, incentive schemes and the emission legislation apply in addition to the technical possibilities. Section 3.2 enters into the economic aspects in detail. The emission legislation is discussed in section 3.3.
Analysis of the energy consumption profile The first step in the design of a CHP installation is to analyse the energy consumption profile. An investment is based on a longterm perspective of at least 10 years. The analysis of the energy consumption profile must therefore include any expectations
for the future, such as increased use as well as energy savings measures. After these developments have been discounted, a net energy consumption remains to which the CHP installation can be geared. Gearing the energy supply of a CHP installation to the user’s electricity and heat (and cold) need is a complex matter. The number of energy streams differs per sector. For instance, the industrial sector often uses various steam types, cooling at various temperature levels, ventilation, tap water and space heating in addition to the provision of electricity. Glasshouse cultivation mainly requires greenhouse heating, electricity and CO2, whilst office buildings need heat, electricity and cooling. Besides the inventory of the various energy streams it is also important to know the capacity and exactly when demand occurs. Peak hours for electricity are between 7:00 am and 11:00 pm on working days. Off-peak hours are all other hours and weekends. The purchase and return supply rates can differ significantly as regards peak and off-peak hours. The desired temperature at which the heat is to be provided must also be considered. An analysis of the energy consumption profile is summarised on the basis of the number of full load hours and the load duration curve. The number of full load hours is the total energy use expressed in kWh divided by the installed capacity expressed in kW. A high number of full load hours is desirable for employing CHP. A low number of full load hours suggests a user that uses the installation for only part of the year. Figure 26 (page 46) shows that CHP is an interesting option in terms of demand for heat, particularly for hospitals and glasshouse cultivation.
Abbreviation
AFC
PEFC or PEM
PAFC
MCFC
SOFC
Type of Fuel Cell (FC)
Alkaline
Polymer Electrolyte (Membrane)
Phosphoric Acid
Molton Carbonate
Solid Oxide
Electrolyte
KOH
Fixed ion conducting membrane
Liquid
Li2CO3 en K2CO3
Ceramics Y2O3ZrO2
H3PO4
Li2CO3 and K2CO3
Ceramics Y2O3ZrO2
205 ºC
650 ºC
600 - 1,000 ºC
Operating temperature
65 – 220 °C
40 – 80 °C
205 °C
650 °C
600 – 1,000 °C
Cell efficiency
45 – 60%
30 – 60%
40%
45 – 60%
45 – 65%
Capacity
20 kW
> 1kW – 1 MW
50 kW – 1 MW
1 MW
5kW – 3 MW
Applications
Submarines, space travel
Transport small, idle
CHP
CHP
CHP
Table 1 Types of fuel cells and their characteristics (EG&G Technical Services).
44
MCFC unit. Source: CFC Solutions GmbH
98 oC
33 oC
85 oC
Cooling tower
Water vapour Fuel Combustor
Fuel
SOFC
DC/AC converter
Gas turbine
Generator Air inlet
Compressor
Weak solution
Strong solution
Condenser Condensation 31 oC
Absorber
Fuel
Evaporator Water vapour
Heat exchanger
Figure 23 Diagram of an SOFC / gas turbine hybrid system.
12 oC
6 oC
27 oC
Figure 24 Principle diagram of an absorption cooler.
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Paragraph 3.1 | Technology, design and use
Heat and Power
A quick preliminary estimate of the capacity of a CHP installation can be made by means of load duration curves. In the diagram in Figure 27 the capacity (the vertical axis) is plotted against the number of hours by which this capacity is exceeded (the horizontal axis). The surface area in the diagram (kW times hours) is an indication for the energy demand. The load duration curves for some sectors also show that CHP is less attractive for offices that are open for only five days per week. At 4,000 hours the curve intersects below 10% of the maximum capacity. However, this need not stand in the way if the office is large enough. CHP installations can be successfully implemented in offices if properly dimensioned and ingeniously combined with a heat buffer. CHP installations can be an especially attractive option from a financial perspective if they are integrated in the cooling
Analysis of the use profile: • Energy savings in advance • Volume and duration of electricity and heat demand • Temperature level of heat demand • Future energy demand • Non-concurrence of heat and electricity
and emergency power system (such as in buildings of the European Parliament). CHP installations can also be a reasonable alternative for smaller offices that are used seven days per week. Based on curves like these, rules of thumb can be drawn up for a preliminary estimate of the most efficient capacity. However, a preliminary estimate of the capacity of the planned CHP installation can be made on the basis of previous experience (Figure 28). Each load duration curve is unique and major differences can be seen within the sectors. Therefore, hourly energy consumption data must always be requested or measured first before assessing feasibility. In many cases a building’s installed thermal capacity does not correspond with the maximum thermal capacity it actually requires. Often approximately 40% excess thermal capacity is installed due to customary extra allowances and uncertainties in the heat requirement calculation. The method for determining the required scale of the CHP installation depends on the situation. In principle, two situations can be distinguished: • Buildings for which historical annual consumption data is available; • New buildings for which no energy consumption data is available.
Design aspects
These situations are worked out in more detail in Appendix 2 at the end of this book.
b) Heat buffering
Other wants and limitations: • Back-up facility or emergency power • Integration in and effect on the existing system • Available space and supporting surface area • Distance to users of heat networks • Distance to users of heat network
Another option is to buffer heat, for instance in the bulk of the building (concrete core activation) but also in hot water buffers or
What is leading: heat or electricity? The design of a CHP installation is largely determined by the installation’s specific application. Examples: • In the processing industry it is quite possible that a customer is interested only in steam, in which case the produced electricity is used on the spot or fed back into the grid. The grid is then used for ‘balancing’ purposes.
Indicative CHP capacities Maximum demand
Office 7 days/week
Capacity
Universities Shopping malls
Residential flats
Hospital with air treatment
New Additional for existing Cooling via ACM
Glasshouse cultivation
Sector
Offices
Hospital
Glasshouse cultivation
0 2,000
3,000
4,000
5,000
6,000
Figure 26 Full load heating hours in various sectors.
high low
Care centres
Hospitals
Office 5 days/ week
Housing
Glasshouse cultivation Glasshouse cultivation
Nursing homes
Offices
Full load hours per year
46
However, the higher peak rate for electricity applies up to 11:00 pm. Considering that the CHP installation can run cost-effectively during high peak rate hours, the fact that it stands idle after office hours is particularly unfavourable.
Heat demand can differ significantly as the seasons change. Long-term energy storage (LTES) in aquifers is a possible solution here. In this process excess heat is released to a closed circuit comprising two sources: a heat source and a cold source. In summer, water from the cold source is heated to a maximum temperature of 30°C and pumped to underground storage from where it can be pumped up as needed. This heat is absorbed by a heat pump, after which the cooled water is pumped back to the cold source. Heat loss deep underground (80 to 200 metres down) is minimal.
CHP area
1,000
Figure 25 Factors that figure in the design of a CHP installation.
In cases where there is a substantial peak in heat demand, solutions must be found for maintaining the net heat demand whilst increasing the number of CHP operating hours. One possibility is not to reduce or barely reduce temperatures at night in properly insulated buildings. Heating up the building in the mornings causes a peak in demand which the CHP installation can only partially cover. After office hours the CHP installation stands idle for several hours because the building cools down slowly.
Full load heating hours Hospitals
Possibilities: • Prime movers: - Field of application - Efficiency • Buffering • CO2 -utilisation • Trigeneration
a) Levelling off peak heat demand
100%
CHP design
External factors: • Tariff structures • Incentive scheme • Emissions legislation
The load duration curve is one point of departure in the design of a CHP installation. Other aspects also figure largely, namely those that extend the operating time or that can improve the cost-effectiveness of the CHP installation. Some examples are provided below.
in the hot tap water supply. By buffering, more CHP capacity can be installed and these larger systems can operate longer. Both aspects improve the financial feasibility of the CHP installation. In addition to levelling off the demand profile, buffering also serves to supply a maximum amount of electricity during peak hours for which considerably higher electricity rates apply. Figure 29 (page 48) contains an example of the effect of buffering on the capacity to be installed.
Sector
If we also consider cold production in the analysis then universities also qualify. CHP is suitable for shopping malls, offices and housing projects only if their scale is large enough. The number of full load hours is limited in these cases and therefore sufficient scale is required to lower the investment per kW to make CHP profitable.
Swimmingpools 1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Excess hours/year
Figure 27 Load duration curves for heat use in some sectors (examples).
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Heat capacity / maximum demand
Figure 28 R ules of thumb for a preliminary estimate of the CHP capacity to be installed.
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Paragraph 3.1 | Technology, design and use
Heat and Power
• The situation may be the exact opposite for a greenhouse grower with crop lighting, in which case electricity demand is leading. • When applied in a hospital, reliability of the energy supply is of particular importance. Various units can be installed to guarantee this reliability. Furthermore, it is important to know whether the production of heat and electricity is for one’s own use or for that of customers, or whether it will be fed back into the electricity grid.
CHP as a part of the energy supply CHP installations usually supply the base load. Supplementary boilers handle peak loads and serve as backups. The electricity grid covers peaks and also serves as a backup. In sectors in which reliability is essential, such as in hospitals, the entire energy installation is designed to produce sufficient electricity and heat in the event of a power failure or if one of the components breaks down. For instance, in University Medical Centre Utrecht one flue gas boiler can be linked to three gas engines that in principle can meet the hospital’s full heat and electricity demand. Two reserve boilers and a diesel engine have been installed as well. The integration of the CHP installation into the system is discussed in more detail later on in this chapter.
The influence of tariff structures Some companies purchase their electricity at rates per hour, in which case the time at which the electricity is produced is essential for managing the CHP installation efficiently. This also applies to a lesser extent to companies that purchase on the basis of peak and off-peak hours or on a weekly basis through other kinds of block purchasing. This is discussed in more detail in section 3.2.
heat. Also, systems can be tested with emergency coolers independent of heat demand.
Government incentives: tax exemption, subsidies The government has various incentive schemes in place that promote the use of CHP. Several national subsidies and financing options available in 2008 are discussed in section 3.2.
The utilisation of flue gases Heat from the flue gases of a CHP installation can be used in several ways, namely: • To produce steam and/or heat; • Directly for industrial processes such as ovens and dryers; • To evaporate LNG; • For CO2 fertilisation among greenhouse grower Flue gases often need to be purified before they can be used directly, such as in the case of CO2 fertilisation and for drying foodstuffs.
This is because some of the gas is converted into electricity. Consequently, less heat need be stored in the buffer per m3 of required CO2.
Integration of a CHP system Hydraulic, electrical and structural integration of a CHP system is no easy matter. With respect to hydraulics, things can go amiss if the supply temperature to the CHP installation is too high. As regards electricity, the system may not hinder one’s own network or the national grid, nor may the installation lead to unsafe situations. From a structural point of view, the following must be taken into account: noise, vibrations and ventilation of the CHP installation, chimney, outlet location vis-à-vis adjacent premises, volume and weight.
Hydraulic integration The hydraulic integration of a CHP installation for steam production is easier (but not necessarily safer) than the integration for hot
water production. For hot water production the following must be taken into account when determining the configuration: • The temperature of the water exiting the CHP installation must be as high as possible in connection with optimum heat transfer (less expensive heat exchangers) and the flow of water must be as small as possible (higher temperature difference between feed water and recycled water). • When combined with high efficiency boilers instead of conventional boilers, parallel connections are required in place of serial connections. High efficiency boilers fed with preheated water have no condensation effect and therefore do not achieve the desired efficiency. • The temperature of the recycled water entering the CHP installation may not exceed the specifications of the manufacturer (usually 70°C max). Furthermore, it must be decided whether a parallel or serial connection is required between CHP and boilers and whether
A greenhouse grower’s storage tank for buffering.
Flue gases from gas engines must be purified to reduce (in particular) the NOx and ethane (C2H4) content in order to make them suitable for CO2 fertilisation in greenhouses. By using a flue gas purification installation greenhouse growers can extend the operating time of their CHP installation by at least 1,500 hours. Their greenhouses will also contain more CO2 as CHP installations consume almost twice as much gas per unit of heat as boilers.
0.9 Central heating From buffer CHP to buffer CHP direct
0.8 0.7
48
Capacity
0.6
Whether electricity can be used on site (‘behind the meter’) or is fed back into the grid, is another essential question. During peak hours it can be beneficial to feed back into the grid, whereas this is not true during off-peak hours. For financial reasons it can be attractive to equip the CHP installation with emergency coolers so that it can supply electricity for a few hours per year in order to keep down any peaks or so that it can generate electricity during hours at which extremely high rates apply without utilising the
0.5 0.4 0.3 0.2 0.1 0 1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of the day
Figure 29 Effect of buffering on the capacity to be installed.
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Paragraph 3.1 | Technology, design and use
Heat and Power
or not to use a heat buffer. For parallel connection the required heat capacity is determined by measuring the amount of recycled water coming from the central heating system and the difference in temperature between inlet and outlet. Based on this heat capacity it can be determined when and at what capacity level (full load or partial load) the CHP installation must kick in. The control strategy is as follows (Figure 30): • If the capacity is smaller than the lower limit of what is supplied by the CHP installation, only the boiler is used. • If the capacity is larger than the lower limit of the CHP installation, only the CHP installation kicks in. • If the capacity exceeds the upper limit of the CHP installation, both the CHP installation and the boiler are used. Should there be any excess heat capacity a heat buffer can be used in parallel to the CHP installation. The CHP installation feeds the buffer with the excess hot water until the buffer is full. When the CHP installation cannot meet capacity demand, extra heat capacity can automatically be obtained from the buffer. The temperature is controlled wholly separately from the central heating control and the hydraulic control; the CHP installation and the heat buffer become an independent control unit (Figure 31). In a serial integration situation the recycled water from the central heating system is preheated before it is sent to the primary circuit. Here, too, it is recommended that preheating is activated by means of ‘forward control’ based on heat demand (amount of water and temperature difference). Activation of the heat boiler is delayed or set in such a way as to ensure a slight downward deviation in comparison to the desired value so that the CHP installation can continue to run. The benefit of serial integration is that CHP and boiler are controlled separately. Appendix 1 provides a detailed explanation of the hydraulic integration of both water and steam.
Electrical integration Various configurations are conceivable for the electrical integration of a CHP installation. Figure 32 (page 53) provides one example. The most popular configuration for small systems (up to 1 MWe) is a connection to the 400 V grid. For larger systems (over 2 MW) one
50
can opt for a low voltage or a medium voltage generator (10 kV). The required switch and control equipment for medium voltage is more expensive than the equipment that is mass produced for 400 V. So it is quite possible that there is no difference in investment costs. Also, the electrical efficiency of a 400 V generator in combination with a good step-up converter is still more appealing than a medium voltage generator. Furthermore, a highly skilled technician is required to operate and maintain a medium voltage installation and these technicians are scarce. In all cases one’s own use of peripherals such as pumps and ventilators must be taken into account. Because return supply to the grid is still not very profitable, as much of the electricity as possible is generally directed to one’s own requirements. This applies particularly to night-rate electricity (off-peak hours) during evenings and weekends. On the other hand an agreement with a power company for delivery at agreed times often produces extra benefit. If a CHP installation is deployed for emergency power the start-up load and fluctuations in electricity demand on the grid must be considered (Figure 33). With respect to the start-up procedure it is important that the CHP installation, after it is up to speed, does not immediately run at full load as the gas engine is unable to cope with this; the number of revolutions will drop and in the worst case the machine will fail. The preferential emergency power groups must be enabled in small steps, with no more than 25% of the full load capacity of the CHP installation per step. This is allowed up to a capacity of 50%, after which the steps become smaller, namely approximately 15% per step, until 85% of the full load capacity is reached. Modern gas engines are unable to cope with severe load fluctuations. Because of the length of the gas control system the response time of the fuel supply is too long, which means that an emergency power diesel engine must level off the load peaks or that the capacity demand must be limited in some other way. The use of large accumulator batteries as an emergency power buffer is costly; these batteries require a lot of maintenance and electricity when on standby. Suppliers are zealously searching for a suitable solution.
CO2 fertilisation is often used in glasshouse cultivation.
CHP combined with Central heating
Capacity coverage
CHP upper limit
Central heating
CHP Buffer
CHP lower limit
Central heating
Central heating
CHP
Pumps
Central heating Capacity demand
CHP upper llimit
Figure 30 Example of control strategy.
Figure 31 Example of parallel integration with a buffer.
51
Paragraph 3.1 | Technology, design and use
Heat and Power
To sum up: the hydraulic, electrical and structural integration of CHP installations requires due attention. The use of cogeneration is endangered if not properly supervised or implemented. High costs can be involved in reintegrating an installation’s hydraulics. In addition, integration into the surrounding area also requires attention. Vibration for instance can be a nuisance to people living in the vicinity and the solving of this problem is no sinecure. Removing structure-borne noise by means of flexible connections and/or contact separations is a specialised field. Also, exhaust pipe noises (chimneys) are a very sensitive point for people who sleep with their window open as they are sometimes known to be heard several blocks away. Remedying noise pollution by means of additional silencers is often very difficult due to lack of space. The outlet for discharging flue gases produced by CHP installations (if they involve a flue gas condenser in built up areas) also requires extra care, as the flue gases no longer have any upward force to rise; this causes fog formation resulting in reduced visibility during the day. Diluting the flue gases by means of air slightly relieves this problem. When properly executed the engineering (design, choice of technology and integration) of a CHP installation will guarantee the success of the CHP application, both from a technical and a financial perspective.
3.1.3 Usage aspects Commercial-economic aspects It is of the utmost importance for users that their CHP installation is cost effective. Various commercial-economic aspects feature in
52
250 GRID
400 V
M G
400 V
M G
Step - up
Surface area (m²)/MWe
Due attention must be paid to the integration of CHP installations in buildings. Noise and vibration feature largely as well as volume and weight (Figures 34 and 35). As with boilers the supply of combustion air, the necessary supply of ventilation air and the discharge of flue gas must be taken into account. In order to meet future environmental constraints it may be necessary to reserve extra space in the installation room for bulky flue gas cleaners and catalytic converters. Placing CHP installations in a container to limit the amount of noise makes them heavier and larger. CHP installations in excess of 1.5 MWe are too large to fit in a maritime container.
deciding on the type of CHP installation. The extra investment can be recovered by generating additional revenues in delivering electricity to the grid. However, CHP installations can also save costs by avoiding purchasing peaks and heavy-duty mains connections, in which case the installation is used to cover peak loads. To prevent overly high peak loads on the connection and thus high related costs as a result, the installation must be suitably reliable. By integrating the installation with other functions, such as emergency power, possible other investments such as in an emergency power aggregate can be avoided. These costs can then be attributed to the CHP installation, thus keeping down the total investment for achieving cost-effectiveness. Section 3.2 discusses the main aspects of the economic analysis, i.e., the exploitation calculation and the investment costs of CHP installations, in more detail.
10 kV
10 kV
M G
200
150
100
In container
50
Not confined
400 V 0
10 kV 400 V
500
1,000
1,500
2,000
2,500
Electrical capacity in kWe
Figure 34 R equired surface area for CHP installations based on a gas engine. Figure 32 Integration of the CHP installation into the electricity grid.
Reliability and availability Every year, CHP installations are shut down for several hours for maintenance and repairs. A maintenance schedule (number of hours and point in time) is planned in advance. A distinction can be made between installation availability and reliability. Availability is a criterion for the total number of hours that an installation is out of operation (downtime), including malfunctions and planned maintenance. Reliability indicates how long the installation is down outside planned maintenance hours. Section 3.4 discusses the nature of maintenance on and malfunctions in CHP installations. This section therefore touches only briefly on two different methods for calculating reliability and availability.
70 60
M
G
50
V
NSA
(stand by generator)
Tonnes/MWe
Integration into buildings and surroundings
IV
Pe III
GRID
30 20
II I
In container
40
10 mio m3 commercial
0.75
0.76
0.77
0.78 (1.18)
0.79 (0.79)
Table 3 Energy tax on gas during the past few years.
100
Peak next year €/MWh Off-peak next year €/MWh
80
€/MWh
Table 2 provides an indication of the average costs for capacity and transport of an off-take of 170,000 m3 and of 1 million m3 of natural gas in 2007. The difference between high and low is related to the region. The lowest costs apply to the Groningen region. The highest, due to the distance to the Groningen gas field, apply to the provinces of Zeeland and Limburg. The costs of the local grid operator are listed in the table in brackets. However, these apply only to connections of 8 bars and higher.
60
40
20
Year ahead forward electricity Platts/Endex 0
jan 02
jul 02
jan 03
jul 03
jan 04
jul 04
jan 05
jul 05
jan 06
jul 06
jan 07
jul 07
jan 08
Figure 8 Development of forward prices for electricity as from 2002.
63
Paragraph 3.2 | Economic analysis
Heat and Power
small-scale consumers from consumption (also for natural gas) and to change it into a fixed sum per year for purposes of simplifying administrative requirements. The aim is to compensate this unbundling in a similar way as the energy tax so that on balance the consumption-dependent costs for small-scale consumers will remain unchanged. Regulator DTe determines the network tariffs. The DTe is successfully striving to lower the costs via yardstick competition. On the other hand, substantial investments will be needed over the next few years mainly in the national grid, particularly to enable new generation by means of such technologies as CPH, wind farms and new power plants (coal-fired or otherwise). Significant savings can be realised on grid costs if the electricity generated by a CHP installation is used for one’s own use. However, the remaining amount of electricity to be purchased from the grid will be relatively much more expensive due to a lower operating time. If the operating time drops from, say, 4,000 to 2,500 hours the transport costs for low voltage bulk consumption will rise from 2.8 ct/kWh to 3 ct/kWh (Table 4). If the CHP installation supplies all electricity to one location a backup contract covers electricity demand while the installation is down for maintenance or due to a failure. Separate rates apply for higher voltage levels.
Energy tax on electricity As with natural gas, graduated tariffs apply to the energy tax on electricity. Table 5 contains an overview of the energy tax of the past few years (tariff in ct/kWh). The energy tax for electricity is also charged by the second last link in the supply process, i.e., the end user’s supplier.
An exemption applies for electricity if used for one’s own use and generated by a CHP installation at a Senter efficiency of at least 60%. This Senter efficiency calculation is based on the sum of the total electrical efficiency and two-thirds of the thermal efficiency. Only one’s own use is involved here; if supplied to third parties the normal energy tax is charged which subjects all customers to the various graduated tariffs.
Maintenance and management costs CHP systems require considerably more attention than boilers. Maintenance intervals apply for changing the lubricant, adjusting the valves, replacing spark plugs and filters, etc. The periods in which these activities must be carried out differ for each component. Each CHP installation has a preventive maintenance plan to prevent damage to the system and to anticipate malfunctions. It is comparable with maintenance on a car. As maintenance is a specialised activity it is often contracted out to the supplier who can also provide remote management services. The installation’s critical parameters (lubricant usage, engine temperature, vibration etc.) are read out and analysed from a remote location. There are also parties in the market who manage and finance the entire system (outsourcing). Joint ventures can be entered into for larger systems, in which case the user and the manager participate in a separate management company. In some situations the outsourcer offers a conversion contract, whereby the user offtakes electricity and heat, and purchases natural gas himself. The outsourcer guarantees an agreed minimum efficiency and a minimum availability percentage. Deviations can be compensated for by fines and
reimbursements. Section 3.4 contains more information on the management and maintenance of CHP installations. As an indication, Table 6 contains a rough estimate of the maintenance costs for the various types of CHP installations. The costs for machine breakdown insurance are not included. The reason is that factors on which these costs are based e.g. machine type, application and capacity volume, ancillary and preceding processes, the environment and possible combinations with other machines, may differ significantly between installations.
3.2.3 Required investments The cost price of a complete CHP installation is determined by its components as previously indicated in section 3.1. • CHP installation (prime mover) with generator; • Heat transfer system; • Soundproof housing and outlet; • Integration, electronics and installation room; • Investment in mains connections. Mains connections for fuel and electricity are often separate investment projects. This section discusses the costs for the mains connection for electricity but not the connection for natural gas.
Investment in the CPH installation The following is a run-down of the general investment costs for the most common CHP installation, including the costs for the heat transfer system. This is a turnkey investment, whereby the installation is delivered according to specifications. The costs for
Capacity range From
Operating time
LV bulk consumption
MV(10kV)
IV(50 kV)
Tranche
2004
2005
2006
2007
2008
Minimum
Investment in the connection to the electricity grid Depending on the situation, connecting the CHP installation to the electricity grid can lead to considerable costs, i.e., up to 50% of the cost of the entire installation. This means the way in which the connection is to be installed should be considered at an early stage of the project. The local grid operator is responsible for the physical connection of a CHP installation to the public grid. In 1998 the elements comprising the connection costs were regulated in Article 28 of the Electricity Act. These tariffs are drawn up Capacity range From
Maximum
250 MWe
0.45
0.65
Large STAG
80 MWe
15 MWe
80 MWe
0.80
1.20
Small-scale STAG
15 MWe
8 MWe
45 MWe
0.50
0.65
GT large
8 MWe
3.5 ct/kWh
3.5 ct/kWh
3.5 ct/kWh
0 – 10,000 kWh
6.54
6.99
7.05
7.16
7.27
2,500 hours
3.0 ct/kWh
2.0 ct/kWh
1.5 ct/kWh
10,000 – 50,000 kWh
2.12
2.63
3.43
3.69
3.75
GT large
4,000 hours
2.8 ct/kWh
1.6 ct/kWh
1,0 ct/kWh
50,000 – 10 mio kWh
0.65
0.86
0.94
1,02
1.04
GT small
8,000 hours
2.5 ct/kWh
1.3 ct/kWh
0,5 ct/kWh
> 10 GWh commercial
0.05
0.05
0.05
0.05
0.05
GE large
800 kWe
> 10 - GWh non -commercial
0.10
0.10
0.10
0.10
0.10
GE small
250 kWe
2 MWe
8 MWe
0.90
1.25
GT small
10 MWe
0.50
0.90
GE large
800 kWe
0.50
2.00
GE small
250 kWe
800 kWe
Table 6 Cost indication per kWh for management and maintenance.
Investment range (€/kWe)
80 MWe
1,000 hours
Table 5 Energy tax on electricity during the past few years.
To
On the other hand the investment costs for gas engines are very low for their capacity volume, due to extensive standardisation of the installations as well as large production volumes. For that reason overhead costs are relatively low and the integration costs are generally low as well. In Table 8 (page 66) a gas engine at a horticultural company is given as an overall example. The investment costs of a CHP system of over 1.5 MWe are virtually proportional to its capacity. Below 1.5 MWe the price per kWe increases exponentially with the drop in electrical capacity (see, for example, Figure 9). The same applies to the maintenance costs per kWhe.
Large STAG Small-scale STAG
Table 4 Indicative average transport costs per kWh.
Management and Maintenance (€ct/kWh)
the mains connections are not included here. The structure of the investment costs differs significantly per CHP category. For instance, engineering costs weigh heavily on the total investment costs of small-scale installations. The scale effect has a major impact. Large CHP installations are often made to order. These are generally industrial projects with many more or less unique installation components. Table 7 provides an overview of the investment costs per kWe.
2 MWe
To 400 MW
Minimum
Maximum
600
900
80 MWe
1,000
1,300
45 MWe
800
1,100
8 MWe
1,100
1,600
10 MWe
350
700
600
1,400
800 kWe
Table 7 Indication of the investment costs per kW. Source: ECN
Source: ECN
64
65
Paragraph 3.2 | Economic analysis
Heat and Power
according to a fixed formula and are determined on an annual basis by regulator DTe. Up to 10 MVA the connection is charged at standard rates, irrespective of the manner in which the connection is realised. From 10 MVA the connection is based on the project costs incurred on the basis of a cost estimate. As of 1 MVA the connection may be put out to tender, provided the local grid operator approves the plans with the technical specifications of the connection. Also as from 1 MVA, the standard connection can be changed upon the request of the customer or producer. According to the Electricity Act, all customers are entitled to a connection at their desired voltage level, unless for technical reasons this cannot be effected by the grid operator. Customers also have the right to be connected to the closest point in the grid with the desired voltage, regardless of the available capacity at that point. For connections of 10 MVA or higher, the closest point in the grid where capacity is available applies. Changes in the grid associated with the connection are at the expense of the grid operator who manages the relevant grid. Costs incurred by a grid operator for required investments in his high voltage grid due to new connections on lower grids may not be settled via connection costs but rather transport tariffs. The grid operator is obliged to transport electricity supplied by the customer to the grid at a rate and other conditions that are in conformity with the Electricity Act. This obligation applies only if the grid operator has available capacity for the requested transport. So the grid operator can apply restrictions to the capacity that is to be connected. After all, the operator must be given the opportunity to implement changes in the transport network. These must, however, be temporary restrictions. Legislation does not stipulate what may be considered as temporary in this respect. In exceptional cases, the restriction periods can be very protracted. The structure of and the payment method for the network tariffs, including the connection fee, are regulated in the Tariff Code. The connection fee is based on three tariffs in the form of a: • Non-recurrent contribution to cover the initial investment costs for the following: - The physical connection to the network;
66
- The safeguards at the transfer point; - The connection between the physical connection and the safeguards. • Periodic fee for the use of reusable assets (such as transformers); • A periodic fee for maintaining the connection. The standard amount for the connection includes 25 metres of cable. Any additional length is charged at a metre rate set by the DTe. The length of the cable is based on the distance between the safeguards and the relevant connection point, measured along the centre of the public road. Generally speaking, standard categories apply for the connection method, although grid operators can deviate from them. The categories are as follows: • Up to and including 60 kVA: low voltage cable; • 60 kVA through 0.3 MVA: MV/LV transformer station; • 0.3 MVA through 3 MVA: Medium voltage cable; • 3 MVA – 10 MVA: MV grid supply or distribution station; • > 10 MVA: Nearest point in the grid with sufficient capacity. Based on the above categories, a connection of 2.5 MVA and a connection of 3.5 MVA are taken as examples. The first can be connected to a MV cable running along the public road. The cable is 50 metres long, so 25 metres must be paid for. The second
Breakdown of investment costs for stand-alone CHP of 1,000 kWe (no grid connection) Basic price in € CHP installation (excl. condenser)
355,000
Telemetry system
2,300
Additional costs Foundation + concrete works
7,800
Roof/wall conduits
2,300
LV cable to internal distribution station
3,000
Gas network connection
7,300
Integration with existing central heating system
17,200
Permits and incidentals Total CHP investment costs (excl. condenser)
6,800 401,700
Costs per kWe capacity, in €/kWe
Table 8 Example of the investment costs for a gas engine.
402
example is based on a connection to the nearest HV/MV station and the connection cable is 4 km long. As an indication the rate for a medium voltage cable is approximately €60 per metre. An additional length of 4 km means €240,000 additional connection costs, excluding engineering works such as bridges over waterways (Figure 10).
3.2.4 Influence of the energy market and energy contracts
and several years. Trading occurs via dealers or directly between provider and customer. As an example, Figure 12 provides the movement of the electricity ‘forwards’ for one year ahead, in other words the prices at any point in time for supply throughout the entire following year. The price movement (in Figure 12 as from January 2002 to mid February 2008) shows that electricity prices are rising. The price movements of the past few years were provided in a previous section.
Movement of natural gas prices The main cost item for CHP installations is the purchase of energy, i.e., the purchase of natural gas. A substantial part of the natural gas is supplied by GasTerra via retailers or other parties. GasTerra links its prices to those of oil products but when fixing its formula it follows the price on the free market. This price is reflected by the TTF price listed on Endex. TTF stands for Title Transfer Facility, a volume of gas that has been placed on the network. Since 2006 gas can also be traded on a daily basis via the APX, which makes it possible to trade short-term gas shortages or excesses on a ‘dayahead’ basis. This short-term market gives customers an additional optimisation instrument based on gas; this book makes no further mention of this. Figure 11 (page 69) reflects the movement of the gas price for consumers and the industrial sector including transport and energy tax costs. As stated previously, the amount of these two items depends on the total offtake per year and on the maximum offtake peak during the year. Figure 11 assumes a consumption of approximately 2,600 m3 per year for households and 1.3 million m3 for the industrial sector.
1,200
Indication of the budget price of CHP gas engines (in € per kWe installed capacity)
900
600
300
0 25
750
1,475
2,200
2,925
Electrical capacity (kWe)
Figure 9 Development of costs of a gas engine package for CHP.
CHP 3.5 MVA
HV/MV station MV connection cable 4,000 metres
Sale of electricity Since the liberalisation of the energy market, electricity can be purchased and sold on various markets, the main ones being the long-term market, the short-term market and the balancing market.
Long-term market The long-term market (also referred to as Over The Counter (OTC)) is based on long-term contracts between producers and customers. The term of the contracts varies between a few weeks
50 metres
2.5 MVA
MV mains cable
CHP
Figure 10 Example of a connection to the electricity grid.
67
Paragraph 3.2 | Economic analysis
Heat and Power
There is also a balancing market in addition to the two term markets. On this market TenneT organises the regulating capacity of the national electricity grid. It is mandatory for large-scale electricity suppliers to participate actively on this market, whilst other suppliers can do so voluntarily. The total supplied capacity is divisible into three groups: • Regulating capacity. This capacity can be controlled continuously by the national frequency capacity regulation. The total volume is determined on the basis of the controlling signal. • Reserve capacity. This capacity is called up as needed; the volume is calculated on the basis of the offered call-up time. • Emergency capacity. The balancing market works two ways: on the one hand, additional capacity can be offered in order to ramp up the available capacity in the grid. On the other hand suppliers can switch off capacity or consume more capacity. Prices on this market fluctuate heavily, making it difficult to produce a forecast. As an example, Figure 14 contains the price movement of the balancing prices on 12 March 2008.
Models for electricity sales CHP installations can produce electricity for one’s own use or for supplying the grid. Supply can be directed at the afore-mentioned markets, depending on the type of installation. A PR (Programme
68
Besides the normal peak and off-peak hours, other sales schemes offer an extended peak rate (also referred to as super peak). This extended peak runs daily from 8 am to 8 pm during work days and weekends. This can be an advantageous scheme if the CHP installation is running to produce heat over the weekend in any case. Another way to sell electricity to the grid is to use the installation as a back-up, in other words to use it to trade on the electricity markets (such as the APX market). Operators specify in hours when their installation can supply to the grid. These hours are sold in advance to customers on the free market. If, however, electricity is offered via the APX at lower costs than the production costs of an operator’s own CHP installation during the previously specified hours there is no need for the operator to run his installation but can instead purchase the electricity on the APX market and subsequently supply it to the customer. This is shown in the example in Figure 15 (page 70).
900 800
50
700 600
40
€/MWh
In the simplest case, CHP operators provide their electricity on the basis of long-term contracts. This is profitable mainly during peak hours at which time the cost of producing electricity with a CHP installation is lower than the sales price. It is often unprofitable to supply to the grid during off-peak hours as revenues are then lower than production costs. In some instances, however, suppliers must nevertheless supply electricity due to supply obligations (‘must run capacity’) for power production, for instance. ‘Forwards’ are a good indication of the prices at which electricity is traded at a specific moment in time. When selling, dealers generally apply a trade margin vis-à-vis the forward prices.
1,000
Industrial sector
Households
60
30 20
500 400 300 200
10
100 0 1991
1993
1995
1997
1999
2001
2003
2005
Figure 11 N atural gas price movements from 1991 to 2007 (including transport and taxes). Source: www.energie.nl
100
Peak next year €/MWh Off-peak next year €/MWh
80
0
2007
Jan 06
60
40
Feb 06
Mar 06
Apr 06
May 06
Jun 06
Jul 06
Aug 06
Sep 06
Oct 06
Nov 06
Dec 06
Jan 07
Figure 13 APX electricity price movements in 2006.
Balancing price (€/MWh)
Balancing market
An MR (Measurement Responsible) party must also be appointed. This party ensures that meters are installed, checked and read. The MR party also validates read data and sends consumption data to the grid operators. ct/m 3
The short-term market (mainly the APX market) is based on next-day supply. Suppliers on this market state in advance at what price (per hour) they are willing to supply electricity the following day. Customers state at what price they wish to purchase electricity. These bids result in one market price for a specific hour with a fixed volume of electricity for that specific hour. This procedure is completed for all hours of the next day. The movement of the APX prices fluctuates heavily and is strongly influenced by short term excesses and shortages. The example in figure 13 shows the APX prices of 2006 in €/MWh. Prices on the long-term market show a limited response to fluctuations on the APX market.
Responsible) party must be involved in order to supply electricity to the grid. The PR party is responsible for settling differences between transactions and actual situations. These differences ensue from deviations between purchase and sales contracts and actual production or consumption.
€/MWh
Short-term market
Balancing prices 12-03-2008
600
Offtake
Feed-in
500 400 300 200
20
100
Year ahead forward electricity Platts/Endex
0 jan 02
jul 02
jan 03
jul 03
jan 04
jul 04
jan 05
jul 05
jan 06
jul 06
jan 07
jul 07
Figure 12 Electricity forward price movements as from 2002.
jan 08
0 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour
Figure 14 Electricity balancing price movements on 12 March 2008. Source: www.tennet.nl
69
Paragraph 3.2 | Economic analysis
Heat and Power
Calculation of trade between OTC and APX market Suppose an operator of a 1-MWe CHP installation sells all the electricity that was generated throughout the entire year between 8 am and 8 pm for € 78/ MWh. This is a total of 4,380 operating hours with the CHP installation and so 4,380 MWh. The sales revenues come to 78 x 4,380 = € 341,640.
APX also offers the possibility of purchasing electricity for one’s own requirement when the APX price is low, in which case the CHP installation does not operate for one’s own use. Playing with the operating hours carries the risk of more starts and stops which may generate additional maintenance costs. Another risk is that the installation does not run as many operating hours as planned, jeopardising the offtake of previously contracted amounts of gas.
The variable production price of electricity generated by the installation is set at € 60/MWh (including maintenance). The operating result comes to € 78,840 at the end of that year.
The CHP installation can also run in TenneT’s balancing pool and be switched on and off on an on-call basis, as indicated previously. If one’s own operations require a large amount of electricity the possibility exists of modifying the operating process and supplying the produced electricity to the grid.
The additional sales margin amounts to 60 – 38 = € 22/MWh during 1,200 hours.
If a CHP producer unexpectedly cannot meet his planned supply to the grid due to a failure or other problems he creates an imbalance in the grid. The costs (penalty) in this respect are in principle the balancing costs. However this also depends on the portfolio of the PR party. In the event of protracted inactivity, for instance due to a machine breakdown, the CHP producer may need to buy off his contract which obviously incurs extra costs.
Spark spread The financial returns of CHP installations are largely determined by the prices of electricity, gas and related heat. The relationship between gas price and electricity price can be expressed in a spark spread, which is the gross margin expressed in euros per produced MWh. This gross margin depends on the technical specifications of the CHP installation and must cover such matters as the installation’s depreciation and maintenance. As an example, Figure 16 contains the calculation of the spark spread of a gas turbine with a heat recovery boiler, an electrical output of 31.6% and a thermal output of 46%. The produced
70
including interest amount to approximately € 22 per MWh. Maintenance costs amount to approximately € 7/MWh. Therefore, the spark spread must be at least € 29 per MWh to fully cover the maintenance costs, interest and depreciation.
€ 0.27/m3
Gas price (commodity) Peak electricity price
€ 88.00/MWh
Off-peak electricity price
€ 50.00/MWh 54 %
Electricity production during peak hours
3.2.5 Subsidies and fiscal benefits € 70.50/MWh
Average electricity price
Table 9 Basis for calculating spark spread.
Now suppose that for 1,200 hours of those sold hours, the APX price is lower than the price of the electricity produced by the operator’s own CHP. The average APX price is, for instance, € 38/MWh. During those 1,200 hours the operator can purchase the electricity on the APX and supply it to the customer at that average purchase price (without having to run his CHP installation).
Gas
3.2 MWh
Electricity
1 MWh
Heat Boiler gas
1.5 MWh 188 m³
CHP
Gas in m³ Gas price Gas costs
The additional trade result is 22 x 1,200 = € 26,400 (8% additional sales revenues in rounded percentage), not taking any extra maintenance or service costs into account.
367 m³ 27 €ct/m³ € 99
Figure 15 Calculation example of optimisation with APX.
heat or steam is compared to a boiler with an output of 90%. This shows that 3.2 MWh of gas are needed to produce 1 MWh of electricity. Translated (at lower calorific value) to natural gas this equals approximately 367 m3 of gas. Heat is produced (approximately 1.5 MWh) in addition to electricity (1 MWh). This heat price is settled as if it had been generated by a boiler. The spark spread (the difference between income and expenses) in this example is 121 – 99 = € 22/MWh. Figure 17 shows the development of the spark spread over the past few years for that same gas turbine with a heat recovery boiler. The spread is calculated on the basis of wholesale commodity prices (with no uplifts) on the assumption that electricity and natural gas prices are fixed at the same point in time. Forward prices are used for supply in the next year. For that reason there are the occasional jumps at the beginning of the year. To put things in perspective: the investment costs for the installation in this spark spread amount to approximately € 1,250,000 per MWe (excluding subsidies). Taking 8,000 operating hours and a depreciation of 10 years at an interest rate of 7%, the depreciation costs
Figure 16 Illustration of a CHP spark spread for a gas turbine with heat recovery boiler.
40 35
Forwards 2003
Forwards 2004
Forwards 2005
Forwards 2006
Forwards 2007
Forwards 2008
25 20 15 10 5
2003
2004
2005
2006
2007
EIA has been in place since 1 January 1997. It is one of the government’s instruments for stimulating the business community in the Netherlands to opt for low-energy operating assets and sustainable energy. Entrepreneurs can deduct 44% of their investments in low-energy operating assets from their taxable profit (in addition to the normal depreciation) with a maximum CHP deduction of € 350/kW for gas engines and € 600/kWe for other installations. This maximum is substantially lower than actual investments, particularly for small-scale CHP installations. The scheme is an initiative of the Ministry of Economic Affairs. The Tax Department and SenterNovem (an agency of the Dutch Ministry of Economic Affairs promoting sustainable development and innovation) oversee the scheme’s implementation. As from 2008, EIA distinguishes between CHP installations driven by piston-engines and installations driven by other power units. CHP installations with a higher electrical capacity than 150 MWe are no longer eligible for EIA. This limit has been introduced in order to focus EIA on small-scale and decentralised generation of heat and power.
30
0 2002
Various incentive schemes help promote the use of CHP installations. This section discusses a number of nationwide subsidies and financing possibilities that applied in the Netherlands in 2008. Many sectors already use CHP installations. Other than standard schemes such as EIA and SDE, these sectors enjoy little support in the form of subsidies. Obviously, additional support is available for front-runner projects for boosting the use of CHP in new sectors. Innovative CHP applications are also eligible for this type of support.
EIA / Energy Investment Deduction Scheme
Electricity proceeds € 71 Heat proceeds € 51 Total € 121 Sparkspread 22 €/Mwh
Spread in € /MWh
A limiting condition when optimising via the APX is that the heat consumer may not require any heat at that point in time or that he must postpone his heat demand. Also, if the customer needs his own electricity there is little flexibility to optimise the installation. Each CHP installation has its own level of flexibility.
2008
Electricity-natural gas spread based on forwards next calendar year
Figure 17 D evelopment of the spark spread of a typical gas turbine as from 2002.
Operating assets that are eligible for EIA can be found in the Energy List. Examples are purchasing and assembly costs and provisions that are technically required for or are beneficial to the
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Paragraph 3.2 | Economic analysis
Heat and Power
CHP installation, such as pipes and cables. Maintenance costs do not qualify for compensation and funds received through other subsidies must be deducted from the investment amount. Energy consultancy costs do qualify for EIA provided an investment in energy actually ensues from the advice given.
EOS / Energy Research Subsidies There are four kinds of EOS subsidies, of which the EOS-Demonstratie (EOS for pilot plants) can be particularly relevant. This subsidy is intended for the implementation of new energy technology in the surroundings in which it will actually be used. As a pre-condition for this scheme the project must be unprecedented in the Netherlands. Within EOS-Demonstratie the additional investment costs for materials, as compared to a reference situation, are eligible for a subsidy grant. Regional subsidy schemes are also available but differ for each Province. This book makes no further reference to these subsidies.
Green funding Green funding offers favourable rates for projects that benefit the environment. Green funding is provided when an investment is interesting as regards risks, environmental importance and economic return, and would be impossible to realise without such funding. The cost of the project must be at least €22,689. The interest rate for green funding can be 1% to 1.5% lower than normal. A green certificate is required to qualify for green funding. The Regeling Groenprojecten (Green Projects Scheme) decides which environmental projects in the Netherlands are accepted for certification. The Ministry of Housing, Spatial Planning and the Environment (VROM) issues the certificates. The banks’ Green Fund applies for the subsidy at the schemes department of the Ministry of Agriculture, Nature and Food Quality (LNV) or at SenterNovem. The application takes approximately eight weeks. Various banks provide green funding; each applies their own rules with respect to interest percentages, credit risks, etc.
value over time. Their internal interest sets the worth of future cash flows at a lower value. An annual cash flow of €1,000 with a term of 10 years is used here as an example. In 10 years time this cash flow produces a contribution of € 1,000 ÷ (1+r)10 = € 385 (at 10% interest (r)). The sum of all NPVs of all years within the term minus the initial investment (this is a negative cash flow) equals the total NPV at the end of the term. In many cases, the internal interest (or discount rate) is set at 10%. In principle, the IRR method works in the same way as the NPV method, except that the interest is calculated in such a way that the NPV is exactly nil at the end of the term. Subsequently, the IRR is compared to a criterion used within the company. An IRR of 15% is normal and can also be found, for instance, in the environmental license that applies for energy saving measures. An IRR of 15% (before taxes) corresponds approximately with a SPOT of five years (for equal annual cash flows). Table 10 contains examples based on the NPV and IRR methods. Besides the profitability, companies also consider their investment capacity. Environmental legislation requires companies, where technically possible, to install a CHP installation if IRR exceeds 15%. Third-party funding is an option if the company itself does not wish to invest. Based on the economic data it can also be assessed whether a CHP installation can run profitably in part load. It is important to check carefully that the returns are not too low and maintenance costs on the installation are not too high. This helps to determine the marginal result. If profits at a certain load do not offset the yield the system must be shut down, provided this does occur too frequently. Running on part load is often not feasible, for instance in the event of high maintenance costs.
A project requires an investment of €500 and produces an annual saving of €100 on operating costs. The discount rate is 10% with a term of 10 years.
3.2.6 Determining profitability To determine the profitability of the investment in the CHP installation more precisely the previously mentioned SPOT is not sufficient. Companies usually determine the profitability on the basis of the Net Present Value (NPV) or the Internal Rate of Return (IRR). The NPV method is based on the principle that money drops in
72
NPV:
(100 ÷ 1 + 0.1) + 100 ÷ (1 + 0.1)2 + .. etc.. + (100 ÷ (1 + 0.1)10) – 500 = 113 IRR (the result is the interest rate):
(100 ÷ (1+i) + (100 ÷ (1+i)2 + .. etc .. + (100 ÷ (1+i)10 = 500 => i = 15%
Table 10 Example of Net Present Value and IRR.
3.2.7 Feasibility calculations This section contains some examples of feasibility calculations based on the year 2007. These examples relate to three cases: • A large STAG of 255 MWe; • A gas turbine with a heat recovery boiler (GT/HRB) of 7 MWe; • A gas engine of 1,500 kWe installed at a greenhouse grower. Cases 1 and 2 assume a back-up contract of six weeks; case 3 assumes no back-up contract. All installations are depreciated over 10 years. The STAG and GT/HRB in these cases supply steam to an industrial customer. The gas engine produces heat for the greenhouse and uses a buffer in order to run as many operating hours as possible during peak hours. The energy prices are those that would have been set in the fourth quarter of 2006 for offtake in 2007: • Gas price level: Q4 2006 forward prices for 2007 (21.7 ct/m3) and services rates in accordance with the entry/exit system in 2007; • Market price for electricity: € 93.9/MWh for peak hours and €39.8/MWh for off-peak hours. When fed back into the grid a discount of 10% applies.
Operating Productime in tion % hours during peak hours
Own electricity off-take
Investment Mainte(€/kWe) nance (ct/kWH)
1. STAG
6800
54%
25%
634
0.49
2. GT/HRB
6100
60%
25%
1412
1.04
3. Gas engine
4200
90%
0%
470
0.65
Table 11 Bases for calculation examples. Pay-back period (year)
IRR
1. STAG
5.6
12.3%
2. GT/HRB
> project
-4.2%
3. Gas engine
2.5
34%
Table 12 Results of calculation examples.
An 11.2% EIA benefit is assumed for investment subsidies insofar as the Senter efficiency exceeds 65% (this applies only to the gas engine case). The financial results in each instance are calculated in terms of pay-back period and internal return rate – both after settlement of interest and taxes. The results are listed in the tables opposite. Particularly notable is the very short payback period and thus high IRR (Internal Rate of Return) in the gas engine case. This could be because the engine in this example is economic to purchase and maintain and by using a heat buffer it can run during peak hours. With its high output (both thermal and electrical) the gas engine is ideal for saving energy in relatively small locations. The detailed results are presented on page 74 and 75. The payback period for the STAG case is 5.6 years as the STAG also runs during off-peak hours in order to supply steam. Its pay-back period is so high partly because the Senter efficiency is too low to be eligible for EIA. The pay-back period for the gas turbine plus heat recovery boiler falls outside the project period. Cost savings achieved through the CHP are not high enough to recover the investment in the CHP installation before the end of the depreciation period.
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Paragraph 3.2 | Economic analysis
Heat and Power
Gas turbine with heat recovery boiler
STAG
Thermal output Electrical capacity Reference boiler
Energy management Purchase of gas (m3)
43.9 28.5 255,000 90
%
Electrical output
%
Thermal output
kWe
Electrical capacity
%
Reference boiler
Reference CHP
Energy management
Sale of electricity during peak hours (kWh)
Gas costs Energy tax on gas Electricity costs Energy tax on electricity
-
Reference
Reference
CHP
883,086
1,747,775
-
-
-
-
-
11,830,000
Sale of electricity during off-peak hours (kWh)
-
630,000
17,745,000
Sale of electricity during peak hours (kWh)
-
5,670,000
572,921,250 682,953,750
Sale of electricity during off-peak hours (kWh) Sale of electricity during peak hours (kWh)
Exploitation in €
101,035,203
Gas costs Energy tax on gas Electricity costs
-
Reference
Exploitation in €
CHP
1,925,676
3,869,988
142,083
-
1,289,688
127,516
Gas costs Energy tax on gas
Reference
CHP
214,819
424,757
17,181
-
Electricity costs
-
-
103,483
10,048
Energy tax on electricity
-
-
8,496,600
Heat discount
-
198,119
Maintenance
-
40,925
Maintenance
-
444,763
Heat discount
-
-
Sale of electricity
-
1,891,440
Sale of electricity
-
472,257
MEP support
-
-
MEP support
-
49,392
-3,460,930
-2,759,354
103,483
3,203,600 76,691,573
MEP support
-
-
-39,524,869
33,293,586 161,670,000
Energy tax on electricity
Result
Difference CHP vs boiler Investment
Pay-back period (after taxes)
5.59
Pay-back period (after taxes)
IRR (%)
12.3
IRR (%)
74
Purchase of gas (m3)
Purchase of electricity during peak hours (kWh)
-
Table 13 Calculation example for a 255 MW STAG.
Energy management
CHP
%
Purchase of electricity during off-peak hours (kWh)
-
Investment
Reference
95
525,000
Heat discount
Difference CHP vs boiler
Reference boiler
350,000
-
-72,818,455
%
% kW
8,400,000
Sale of electricity
Result
90
48.0 1,500
5,600,000
3,377,556
-
Electrical capacity
Purchase of electricity during peak hours (kWh)
1,191,697
103,483
Thermal output
Purchase of electricity during off-peak hours (kWh)
39,536,753
Maintenance
% kW
%
16,893,750
CHP
31,986,523
44.8 7,000
41.0
14,981,250
Purchase of electricity during off-peak hours (kWh) 239,700,000
-
Electrical output
17,041,656
Purchase of electricity during peak hours (kWh) Sale of electricity during off-peak hours (kWh)
%
8,482,958
449,276,145
270,300,000
28.5
Purchase of gas (m3)
142,270,779
Exploitation in €
CHP characteristic
CHP characteristic
CHP characteristic Electrical output
Gas engine installed in a greenhouse
701,576 9,886,240 >project period
Table 14 Calculation example for a 7 MWe gas turbine with heat recovery boiler.
-4.2
Result
-232,000
55,968
Difference CHP vs boiler
287,968
Investment
705,600
Pay-back period (after taxes)
2.45
IRR (%)
34.0
Table 15 Calculation example for a 1,500 kW gas engine installed in a greenhouse.
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Paragraph 3.3 | Detailing and realisation
Heat and Power
3.3 Detailing and realisation
Once the CHP possibilities have been investigated and the CHP system that best matches requirements has been identified, the project can progress to the final investment decision stage. This section covers the main points for actual project realisation, such as tendering, current legislation, permits and financing, followed by the realisation and commissioning of the installation.
3.3.1 Final design and tendering The final design can be approached in various ways depending on the contract type. It is customary for clients to order the main components (gas turbine, steam turbine and boiler or gas engine) as a partial delivery from suppliers and to see to the engineering of the CHP installation themselves. Clients also control the building design, the foundations (civil engineering), connection pipework to all heat exchangers and pumps (referred to as piping or ‘balance of plant’), cabling (electrical and instrumentation), control system and finishing (miscellaneous). All this is usually done in conjunction with an engineering firm as the process demands considerable engineering capacity. The advantage of this approach is that the client decides on the entire design and therefore has everything under control. This approach lends itself especially to unique installations. The main disadvantage is that the client is responsible for the functioning of the installation, whereas the connections between the components and the control of the entire installation regularly fail to function. Furthermore, the client should not underestimate the magnitude of the work and the specialised knowledge required to bring it to successful completion.
76
As a second option, the supplier of the main components designs and delivers the complete CHP installation. This often applies to turn-key situations: the installation is designed and then delivered as a fully operating system. It is especially important that the client details the installation as accurately as possible in a specification (also referred to as a ‘bid book’), particularly with respect to the following aspects: • Minimum scope of delivery • Functional requirements (electrical capacity, heat supply, operating procedure, etc.) • Process conditions • Location, available space and equipment • Quality requirements for supplied materials and components • Applicable norms and standards • National and specific site requirements • Environmental and permit requirements • Necessary documentation included in quotation and delivery It is necessary to be precise here because any overlooked elements can lead to additional costs. For instance noise requirements that are increased later on always result in additional costs. In the tender the supplier includes important documents and calculations for acquiring a permit such as process diagrams, installation and aspect drawings, and noise calculations. The documents
enable the client to assess the tender with respect to scope of delivery and quality. A detailed diagram (P&ID or Piping and Instrumentation Diagram) gives a better indication than the specification of the number of pumps, instrumentation, heat exchangers etc., in the installation. This diagram should always be requested along with the tender. For large industrial CHP installations of over 50 MWe tenders are usually submitted in a consortium, spreading the risk among several suppliers. The design and supply procedure corresponds largely with the approach as described above. However, this construction is more complex from a legal point of view and requires great effort on the part of the client to oversee the implementation. As CHP installations are more standard than the average factory they can easily be placed as a complete (turnkey) delivery with one main contractor or consortium. The main contractor, usually the supplier of one of the main components, can draw on several standard configurations for the CHP installation including diagrams, controls, etc. Any previous errors are usually corrected in the design. The contact person and responsibility are clearly defined should any problems arise. So this construction is beneficial to the client. However, even in this situation the client must possess or contract a considerable amount of basic knowledge. Gas engine CHPs are mostly delivered as a complete package, including heat exchangers, generator, electrical switches, control and housing. Taking over any part of the delivery may result in technical problems and disputes as to liability. It is important that the client understands which elements are not delivered by the turn-key suppliers. These can be site preparations; metalling/asphalting of the grounds/roads; cooling water facilities; steam, water, natural gas and electricity connections; and procedural matters such as MER and additional studies. These components can produce considerable costs and are also critical in making the permit application. Virtually all industrial sites in the Netherlands are connected to the natural gas network but in many instances the connection
capacity is insufficient for the higher gas capacity required by CHP installations. A capacity shortage has developed in the transport and distribution network as well as in the electricity grid. It is therefore essential that the network company is consulted early in the project with respect to the available capacity of the two networks. For the final design of the installation it is important to know where the network connection is located, when the connection can be realised and - by way of a ‘hard’ quotation provided by the network company - how much the network connection will cost.
Tenders There are various tender procedures. This book restricts itself to the basics. Several steps must be taken to ensure smooth progress through a tender procedure. These require manpower, knowledge and time. Should one of these three components be lacking one runs the risk of encountering recurring problems throughout the entire project. Roughly speaking, the following steps apply: • Specify delivery and maintenance • Select tenderers • Request tenders • Evaluate the tenders • Negotiate and prepare to order Previous paragraphs describe how to specify the installation. It is advisable to ensure that the tender for the CHP installation includes long-term maintenance. The client must specify what the maintenance must cover, what maintenance activities the client will take upon himself and what conditions apply. Normally only a few maintenance parties are involved in a CHP installation. The customer is often obliged to have maintenance on the main components carried out by the supplier. The client is put in a commercially difficult position if a maintenance contract is only requested after the tender. It is usually a simple matter to select tenderers based on the specification. A pre-qualification is often carried out for large installations to keep the number of tender requests to a minimum. Drawing up a complete tender including design is a very costly process for tenderers. Tenderers must be given the time to submit
77
Paragraph 3.3 | Detailing and realisation
Heat and Power
a quotation. Three to four weeks suffices for a package such as a gas engine; twelve to sixteen weeks should be allowed for a largescale industrial CHP installation. Often, more time is involved in evaluating tenders than expected. It takes time to match up the tenders as additional questions must be asked and prices requested before the tenders fully meet the specifications and can be compared with each other. After that the evaluation is quickly done. Three to four weeks should be reserved for this phase for a gas engine and six to eight weeks for an industrial installation.
Guarantees and clauses It is prudent to demand guarantees at least for performance and output, availability and reliability, flue gas and noise emission, and delivery time, making sure that the definitions for all components are described correctly. Guarantees without penalty clauses count for little. That is why every guarantee must have a penalty scheme, with or without a bonus system (no claims bonus), if for instance output exceeds what is tendered. The minimum permit or statutory requirements apply to flue gas and noise emissions. If necessary, a bonus can be agreed for lower emissions which can have extra benefits for the installation. Once all tender details have been agreed the contract sum is fixed during final negotiations. Purchasing conditions such as instalments, warranties and penalty amounts are often agreed during those negotiations as well. All details of the discussions and negotiations should be recorded in writing and confirmed by the supplier. Only then is the installation ready to order.
3.3.2 Regulations and permits This section describes the relevant aspects of regulations and permits. For CHP installations running on natural gas the emission and noise requirements for each individual installation require particular attention. Various general requirements apply as well; these are described in the Decree on Facilities and Installations (Besluit Voorzieningen en Installaties). Large-scale industrial cogeneration plants and district heating plants may have to meet MER requirement. These are described below. CHP installations are often used by institutions that are obliged to participate in the CO2 and NO2 emissions trading scheme (the implications of which are discussed below). Generally speaking, an institution is a company or organi-
78
sation. ‘Institution’ is a central term in the Environmental Protection Act (Wet Milieubeheer).
Permit procedure Whether an institution requires a permit is regulated in the Decree on General Rules for Environmental Protection Institutions (Besluit algemene regels voor inrichtingen milieubeheer), better known as the Activities Decree (Law Gazette 415). This Decree came into force on 1 January 2008, replacing Order in Council 8.40 for various sectors. If an institution falls into a category to which the Activities Decree applies, notification to a designated authority – usually the local authority – generally suffices for a CHP installation. The Activities Decree refers to the underlying regulations with which the CHP installation must comply. Glasshouse horticulture is subject to both the Glasshouse Horticulture Decree (Order in Council 8.40) and the requirements as stated in chapter 3 of the Activities Decree. Institutions which require a permit in accordance with the Environmental Protection Act must follow the normal permit application procedure or permit change procedure, assuming that the installation fits within the zoning plan. If not, a change to the zoning plan can be requested by means of an Article 19.1 procedure. This takes approximately one year. A normal permit application or permit change takes about six months. It is important in the draft permit application phase to confer in depth with the proper officials so that any additional requirements can be dealt with in advance. After the final application has been submitted and a design order has been drawn up, it is published and available for public scrutiny for six weeks. Interested parties - such as persons living in the vicinity and environmental organisations - can make their standpoint on the application known or request a hearing with the Provincial authorities. After this procedure the final order is drawn up and again made available for a six week scrutiny period. During this time interested parties who had already made their standpoint known in the first round can lodge an appeal to the Council of State (Raad van State). If no appeal is lodged the permit comes into force after six further weeks. Once the permit has been granted a representative of the Council or Province is authorised to check the installation.
Designated authorities
MER (Environmental Impact Report)
The designated authority for the permits differs for each installation. In principle, the Province is the designated authority if a CHP installation is installed in an institution for which the Province is already the designated authority and whose fuel input exceeds 50 MW (~ 15 to 25 MWe). In all other instances the Council is the designated authority.
A MER may be required for large installations. Installations with a capacity of less than 10 MWe usually do not require a MER, but when installed in a vulnerable environment it may still be necessary. Whether a MER is required for installations with a capacity in excess of 10 MWe but with a fuel input of no more than 300 MWth (~ 90 to 150 MWe) depends on each separate installation. A MER is always required for larger installations. A MER extends lead times by approximately one year and raises project costs by approximately € 100,000 to € 150,000. A MER manual can be downloaded from the Infomil site: www.infomil.nl (> legislation & enforcement > MER).
Building permits A building permit is required if the CHP installation is installed outdoors, if the outside wall needs alterations, if certain work spaces are given a new designation and if structural or constructional elements must be built. Before submitting an application the relevant council official should be consulted. If a building permit is required it will be granted only after the environmental permit has been issued. For the building permit structural and visual aspects are assessed from which additional requirements may ensue. A building permit application for which a standard form applies can be submitted to the local council. The council must decide on a regular building permit within 12 weeks. This period can be extended by one additional period of six weeks if necessary. Charges are attached to the building permit and differ per municipality. More information can be provided by the local council or the Ministry of VROM (www.vrom.nl > building and renovating > building regulations).
IPPC (Integrated Pollution Prevention and Control) Institutions and installations in the Netherlands must comply with the IPPC directive (European Directive 96/61/EC regarding integrated pollution prevention and control). This means that permits must be based on the best available technology (BAT). The term BAT is somewhat subjective and also depends on local conditions. Among other things the definition of BAT covers the element of economic feasibility, which is important for new construction as well as for any mandatory alterations to existing installations. A BAT reference document has been drawn up as a guideline for determining BAT (BREF, see http://eippcb.jrc.es). In the Netherlands this guideline has been incorporated into the Environmental Protection Act and will also be included in the BEES (emission requirements). For CHP installations this generally means that BAT applies if they meet BEES A or B.
Decree on Facilities and Installations The Decree on Facilities and Installations (Besluit Voorzieningen en Installaties/BV&I or Activities Decree) applies to CHP installations with a motive power of less than 15 MWe. The decree refers to the Environmental Management (Establishments and Licences) Decree (Regeling algemene regels voor inrichtingen milieubeheer’) (Gazette 223) for regulations for installations. This decree contains rules for CHP installations and refers to the Decree on Facilities and Installations (Dutch law gazette 487). The latter decree applies only to establishments for which the local council acts as designated authority, the installation’s nominal electric power does not exceed 10 MWe and the installation uses no fuel other than natural gas, propane gas or calor gas. The following is a summary of the most relevant rules according to both decrees: The following applies to gas engines: • Must be installed in a screened off, safe and fireproof room; • The installation must be in conformity with the safety regulations for gas engines of the Safety Committee for Installations for Burning Natural Gas (Commissie Veiligheid Installaties voor het stoken van Aardgas / Visa, part C 1994); • Must have an average annual Senter efficiency of at least 60% (electrical output and two-thirds of thermal output); • A heat meter must be installed in the event of structural loss of heat; • The emission requirements must be in accordance with BEES-B; • Noise specifications apply (Table 1, page 80).
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Paragraph 3.3 | Detailing and realisation
Heat and Power
The following applies to gas turbines: • Must be installed in a screened off, safe and fireproof room; • This installation must be in conformity with the safety regulations for the use of natural gas in gas turbines of the Commissie Veiligheid Installaties voor het stoken van Aardgas (Safety Committee for Installations for Burning Natural Gas) (N.V. Nederlandse Gasunie, 1997 publication, 2nd edition); • Must have an average annual Senter efficiency of at least 60% (electrical output and two-thirds of thermal output); • The emission requirements must be in accordance with BEES-B (if the Council is the designated authority); • Noise specifications apply (Table 1). Installations over and above 15 MWe do not fall under the Activities Decree and a permit procedure must be followed. BEES-A applies instead of the Decree on Facilities and Installations. The designated authority can then follow BEES-A (or stricter) and determine itself within the legislative frameworks, what applies to the other requirements. In practice this usually means that the designated authority takes over the requirements as stated in the Activities Decree. Gas turbines are subject to BEES-A if the Provincial authority is the designated authority. Usually the establishment also has to deal with NOx emission trading (see the separate section on these topics). The Activities Decree also stipulates requirements for commissioning, management, maintenance and inspections. This book makes no further mention of these requirements. In addition to these requirements CHP installations must also meet current Dutch and European regulations for equipment, including the Pressure Vessel Decree (Drukvatenbesluit), the European directives for pressurised equipment (PED), the Machine Directive (CE label) and all requirements for electrical installations (NEN-EC, etc.). Various requirements also apply to the storage of hazardous substances (oil, fuel, etc., e.g. CPR 15).
BEES A/B The Decree on Emission Standards for Burners for Environmental Management (‘Besluit Emissie-Eisen Stookinstallaties’, in short BEES) is divided into an A version and a B version. BEES-B applies to installations with a fuel input lower than 50 MW (~ 15 MWe); BEES-A applies to larger installations. If an installation falls under BEES-A the Province is automatically the designated authority. Exceptions
80
Point in time
7 am – 7 pm
7 pm – 11 pm
11 pm – 7 am
Day/night average noise level assessment on house fronts
50 dB(A)
45 dB(A)
40 dB(A)
Day/night average noise level assessment in walled-in and adjacent dwellings
35 dB(A)
30 dB(A)
25 dB(A)
Max noise level assessment on house fronts
70 dB(A)
65 dB(A)
60 dB(A)
Max noise level assessment in walled-in and adjacent dwellings
55 dB(A)
50 dB(A)
45 dB(A)
Table 1 CHP noise specifications per block of time. Source: Decree on Facilities and Installations
are gas turbines with less than 1 MW shaft horsepower, gas turbines with less than 500 operating hours per year and piston engines that drive a pump or compressor for less than 5,000 hours per year. The same requirement applies to gas turbine installations, i.e., a combination with heat recovery boiler and possibly a co-firing burner – all requirements in conformity with ISO conditions. The same requirements apply to gas engines in BEES-A as in BEES-B. The requirement for new installations applies to gas turbines in accordance with Table 3. The same requirement applies to gas turbine installations and ISO conditions apply. Other requirements can apply to existing gas engines and gas turbines and to the use of other fuels. Please refer to the full BEES-A and B text. The current version of BEES-A and B can be found at www.overheid.nl. The designated authority may deviate from the BEES and prescribe a lower emission – all the more reason to place a final order for a CHP installation only when the permit is irrevocable.
Air Quality Act (Wet luchtkwaliteit) Legislation with respect to air quality is laid down in the Air Quality Act (law gazette 2007, 414). This act succeeds Air Quality Decree 2005 (Besluit luchtkwaliteit 2005) for the purpose of minimising the negative effects of excessive pollution levels and to have local air quality meet European limits. The Air Quality Act centres on fine particles and NOx. The latter requires particular attention for CHP installations. The old rules apply or transitional provisions in the
The Ministry of VROM is currently planning to update BEES-B with stricter emission requirements. The emission requirement for NOx will probably be 30 gr/GJ. A hydrocarbon emission requirement will also be included. Furthermore, separate requirements will be added for biomass. These requirements will be announced during the course of 2008 and come into force in 2009. As a consequence, many gas engines will require a DeNOx installation.
The current (mid 2008) BEES-B requirements for newly built installations running on natural gas are: Category
Nox requirement mid 2008
Gas engines < 50 shaft power
800 g/GJ *
Gas engines > 50 shaft power
140 g/GJ *
Gas turbines
65 g/GJ *
* An output adjustment applies (multiply by 1/30 of the electric output)
Table 2 Nox requirement in BEES-B mid 2008. Category
Nox requirement mid 2008
Gas turbines < 50 MW fuel
65 g/GJ *
Gas turbines > 50 MW fuel
45 g/GJ *
* An output adjustment applies (multiply by 1/30 of the electric output)
Table 3 Nox requirement for gas turbines in BEES-A mid 2008.
law apply to existing installations. With new CHP installations it is important to know to what extent their emissions add to local concentrations. It has been determined for certain projects with quantified limits that they may contribute ‘to no significant extent’ to air pollution. These projects may be implemented without being tested against the limits for air quality. Projects contribute ‘to no significant extent’ if they do not exceed the 1% limit. This 1% limit is defined as being 1% of the limit for the average annual concentration of NOx or 0.4 micrograms/m3. Whether the latter is the case depends on the current values – determining these values is specialist work. It is prudent to discuss this topic at the start of the permit application procedure with the relevant officials.
Noise requirements The Activities Decree refers to regulations pertaining to noise with which the relevant CHP installation must comply. Requirements
are stipulated for noise levels on facades, in the dwelling and in adjacent dwellings. These requirements are broken down into three blocks of time in a 24-hour period; see Table 1. Installations that require a permit must meet the requirements as stated in the Environmental Protection Act. Regulations for protecting the environment are attached to a permit. To some degree, the designated authority is free to judge what the protection level is and to which properties it applies. The Industrial Noise and Licensing Brochure (Handreiking industrielawaai en vergunningsverlening) (1998) is a tool to help determine the level of protection. In this respect, the Environmental Protection Act assumes the actual use of an establishment. The Noise Pollution Act (Wet geluidshinder/Wgh) applies in addition to the Environmental Protection Act. This Noise Pollution Act is based more on town and country planning. Both the Environmental Protection Act and the Noise Pollution Act apply to industries in zoned industrial estates in addition to test criteria. Technically speaking there are many ways to reduce the emission of noise into the surrounding area. Both gas engines and gas turbines are fitted with soundproof housing to muffle direct noise. 75 dB (A) at a distance of 1 metre is a standard requirement, but 70 or 65 dB (A) can also be achieved at additional cost. The standard requirement for ducts, ventilation grills, flue gas desulphurisers and chimneys is 75 dB (A) at a distance of 1 metre. Even stricter requirements, such as 65 dB (A), can apply. Additional dampers can be installed in chimneys and ventilation grills at extra costs. This low requirement can also be met by means of thicker noise insulation on the ducts. With these measures, a gas engine can even be used in a residential area. Roughly similar norms apply to the ducts, the boiler and the chimney of gas turbine installations. The main focus point for a new-build industrial CHP installation is its contribution to the noise level at the outer zone limits. The noise pressure levels as stated in Lp < = 75 dB (A) figure in this respect as well as the total volume (Lwr in dB(A), depending on the total surface area projecting the noise. A major point that requires attention is the case of several installations operating at the same time as their combined noise level can exceed the noise standard, whereas a single installation does meet the criteria. Excessive
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Paragraph 3.3 | Detailing and realisation
Heat and Power
values at the outer zone limits can be sufficient reason to impose stricter requirements on a CHP installation. Arbo (Occupational Safety & Health) requirements also apply in addition to the previously stated noise emission (permit) requirements. A noise requirement of 85 dB(A) applies to spaces where employees are permanently exposed to noise; noise protection is required over and above these requirements. The influence of a CHP installation on the total amount of noise in a space depends on the space itself and on many other factors. The maximum noise load of a new-build CHP installation can be derived from a noise calculation. The noise level within the noise enclosure will be too high for staff to enter without hearing protection. For further information see www.arbo.nl.
Emissions trading As from 2005, installations of over 20 MW fuel input fall under the CO2 emissions trading scheme. Both boilers and CHP installations are counted in the value of 20 MW. This value is easily exceeded by larger CHP operators.
CO2 emissions trading The CO2 emissions trading system officially became effective on 1 March 2005. Companies within this system need emission rights to emit a certain number of tons of CO2 per year. Participating companies are allocated rights every year by means of an allocation plan. The companies must apply for these rights themselves. Shortages or surpluses can be bought or sold via the emissions trading system. From 2005 through 2007 the distribution of rights had been incorporated in the National Allocation Plan. As from 2008 a new allocation cycle applies, requiring the participation of companies that had previously fallen under a special regulation as their CO2 emissions were less than 25 ktons. The government has issued fewer CO2 emission rights than the actual current CO2 emissions. This is creating a shortage resulting in CO2 emissions savings where they are most cost effective. CHP installations (realised before the end of 2002) of participating companies were allocated rights up to a maximum of 7% in excess of their actual emissions. For upcoming periods the allocation plans will be drawn up for a period of five years.
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At the beginning of every year the Netherlands Emission Authority (Nederlandse Emissieautoriteit / NEa) grants on behalf of the government a portion of the emission rights to the participants in the emissions trading scheme. These companies must measure their actual CO2 emissions according to specific protocols and report them every year to the NEa. To cover these emissions they must subsequently turn in to the NEa the equivalent number of CO2 emission rights. Because emission rights are marketable, companies can purchase rights in the event of an imminent shortage. Companies must have their CO2 rights for the previous year in April at the latest. The government imposes a penalty on companies that do not have sufficient rights. This penalty amounts to the highest market price for CO2 emission rights (this was € 40 per ton in 2008). Companies participating in the European CO2 trading scheme can also buy their emission rights in countries outside of the European Union by means of the Clean Development Mechanism CDM) and the Joint Implementation (JI). CDM and JI are instruments ensuing from the Kyoto Protocol. With the CDM companies can stimulate sustainable energy and clean technologies in developing countries; with JI they can reduce the emission of greenhouse gases in other industrial countries. More information on CDM and JI can be found in the Climate Change dossier. Companies can deduct the amount of CO2 that their investments have helped reduced in other countries from their own CO2 emissions. CDM and JI are only interesting if they are cheaper than buying emission rights on the market. CO2 emission trading is important for CHP installations because with a nominal thermal entrance capacity of more than 20 MW they fall under the scheme. An exception is made for installations that burn hazardous waste or town refuse. CO2 emissions trading affects the market price for electricity. The market price, and thus the proceeds of supply via the grid, has increased due to the CO2 costs. This is favourable for one’s own generation by means of CHP. In addition, rights for the CHP installation may need to be purchased and these costs influence the cost price of the electricity the installation produces. Emissions trading is supposed to reward the affect of CHP installations on energy savings and the CO2 reductions. Whether this occurs in practice depends on the net result of the
rights allocation, the possible purchase of additional rights and the additional proceeds due to the influence of electricity on the market price.
NOx emissions trading As for the trade in CO2 emissions a system has been set up for trading NOx emissions. Companies are obliged to join this system if they have a total thermal capacity of at least 20 MW (fuel). The Dutch government has implemented this system for three reasons. Firstly, the Netherlands has agreed on an international level to reduce the emission of NOx to a sustainable level, as have other European countries. Secondly, a trading system can be more economical for businesses than the present measures and thirdly, it is obvious that the agreed standards will not be achieved with the current policy instruments. Hence new mechanisms are required. In 2001 the member states of the European Union (EU) agreed on each country’s maximum NOx emissions in 2010. These have been recorded in the European NEC directive (National Emission Ceilings). According to this directive the Netherlands may emit
NOx Incineration plant Class Thermal capacity
1
2
3
4
From the government’s point of view, the industry can contribute to the emission tasks cost-effectively by trading in NOx emission rights. The advantage of emission trading is that NOx can be reduced in companies where it is comparatively the most economical to do so.
Determination of NOx load
Check and adjustment of determination of NOx load
Registration frequency of load calculations
Continuous measuring of the NOx concentration and continuous measuring or calculating of the fluegas output
Parallel measurement once a year; Verification test; and calibration once every three years; uncertainty < 20% of the annual average concentration and target inaccuracy < 15% for the fluegas output
Minimum hourly values
≥ 75 en
