Report On Energ Efficient

SUSTAINABLE ENERGY SYSTEMS

Report on Energy Efficient and Renewable Energy Systems Planning and Recommendations for their Successful Application

Organisation name of lead contractor for this deliverable: CREVER-URV

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Table of contents

TABLE OF CONTENTS ............................................................................................... 2 SUMMARY (CREVER) ................................................................................................ 5 1

DELIVERABLE OBJECTIVES (CREVER) ...................................................... 7

2 INNOVATIVE ENERGY EFFICIENT AND RENEWABLE ENERGY SYSTEMS ....................................................................................................................... 8 2.1 Solar thermal systems (CREVER)..............................................................................................8 2.1.1 Analysis of technical aspects.....................................................................................................8 2.1.1.1 Solar thermal collectors ...................................................................................................8 2.1.1.1.1 Flat plate collector (FPC, CPC, IRC)......................................................................9 2.1.1.1.2 CPC collector (Compound Parabolic Concentrator)...........................................10 2.1.1.1.3 IRC collector............................................................................................................12 2.1.1.1.4 ETC Collector..........................................................................................................12 2.1.1.2 Selection of solar thermal collectors..............................................................................16 2.1.1.3 Thermal Storage system.................................................................................................17 2.1.1.4 Control strategy..............................................................................................................18 2.1.1.5 Solar thermal collector array design ..............................................................................19 2.1.1.6 Maintenance...................................................................................................................21 2.1.2 Techno-economic aspects........................................................................................................22 2.1.2.1 Investments costs ...........................................................................................................22 2.1.3 Concepts for integration with other technologies and into networks ......................................25 2.1.4 Socio-economic aspects ..........................................................................................................26 2.1.5 Design, simulation and optimisation tools ..............................................................................31 2.2 Photovoltaic systems (PoliTo) ...................................................................................................33 2.2.1 Analysis of technical aspects...................................................................................................33 2.2.1.1 The photovoltaic cell .....................................................................................................33 2.2.1.2 Equivalent circuit...........................................................................................................34 2.2.1.3 Current-Voltage characteristics .....................................................................................36 2.2.1.4 Irradiance an temperature influence...............................................................................37 2.2.1.5 Yields.............................................................................................................................39 2.2.1.6 Cell adjusting to user parameters ...................................................................................40 2.2.1.6.1 Series of photovoltaic cells......................................................................................40 2.2.1.6.2 Parallel of photovoltaic cells...................................................................................41 2.2.1.7 Terminology ..................................................................................................................42 2.2.1.8 Photovoltaic system .......................................................................................................43 2.2.1.9 Stand-Alone PV systems ...............................................................................................43 2.2.1.9.1 Application...............................................................................................................45 2.2.1.10 Grid-connected PV systems...........................................................................................46 2.2.1.10.1 Islanding behaviour...............................................................................................48 2.2.2 Techno-economic aspects........................................................................................................48 2.2.2.1 PV system size from 1 to 20 kWp ..................................................................................49 2.2.2.2 PV system size from 20 to 50 kWp ................................................................................50 2.2.2.3 PV system size from 50 to 1000 kWp ............................................................................50 2.2.2.4 Economical evaluation...................................................................................................51 2.2.3 Concepts for integration with other technologies and into networks ......................................51 2.2.4 Socio-economic aspects ..........................................................................................................52 2.2.5 Design, simulation and optimisation tools ..............................................................................53

POLYCITY – DR 1.1 2.2.5.1 2.2.5.2 2.2.5.3 2.2.5.4

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Optimal module orientation ...........................................................................................53 Shading effect ................................................................................................................54 Electrical layout .............................................................................................................55 Conclusion .....................................................................................................................57

2.3 Biomass technologies (CREVER) .............................................................................................58 2.3.1 Analysis of Technical Aspects ................................................................................................60 2.3.1.1 Combustion of biomass .................................................................................................60 2.3.1.2 Co-combustion...............................................................................................................63 2.3.1.3 Biogas ............................................................................................................................65 2.3.1.4 LANDFILL GAS...........................................................................................................67 2.3.1.5 GASIFICATION ...........................................................................................................70 2.3.2 ENVIRONMENTAL IMPACT ..............................................................................................74 2.3.3 TECHNO-ECONOMIC ASPECTS ........................................................................................75 2.3.4 SOCIO-ECONOMIC ASPECTS ............................................................................................76 2.3.5 SIMULATION AND OPTIMIZATION TOOLS ...................................................................77 2.3.6 REFERENCES........................................................................................................................79 2.4 Thermal Cooling systems (CREVER) ......................................................................................80 2.4.1 Analysis of technical aspects...................................................................................................80 2.4.1.1 Absorption Chillers........................................................................................................80 2.4.1.2 Absorption heat pumps (Type I and II)..........................................................................83 2.4.1.3 Solid sorption systems ...................................................................................................84 2.4.1.4 Desiccant systems ..........................................................................................................84 2.4.1.5 Advantages and disadvantages ......................................................................................86 2.4.1.6 Current status, manufacturers and installations .............................................................86 2.4.1.7 Future R&D, expectations and timeline.........................................................................89 2.4.1.8 Performance summary ...................................................................................................90 2.4.1.9 Carbon intensity.............................................................................................................90 2.4.1.10 Critical aspects...............................................................................................................91 2.4.2 Techno-economic aspects........................................................................................................93 2.4.3 Concepts for integration with other technologies and into networks ......................................94 2.4.4 Socio-economic aspects ..........................................................................................................96 2.4.5 Design, simulation and optimisation tools ..............................................................................97 2.5 Hydropower systems (Zafh.net)................................................................................................98 2.5.1 Analysis of technical aspects...................................................................................................98 2.5.2 Concepts for integration with other technologies and into networks ....................................101 2.5.3 Socio-economic aspects ........................................................................................................101 2.5.4 Design, simulation and optimisation tools ............................................................................102 Gas Cogeneration (CREVER, CRF).....................................................................................................105 2.5.5 Analysis of technical aspects.................................................................................................105 2.5.5.1 Description of the units and selection of components..................................................105 2.5.5.1.1 Reciprocating Engines ..........................................................................................105 2.5.5.1.2 Gas Turbines .........................................................................................................111 2.5.5.1.3 Steam Turbine .......................................................................................................120 2.5.5.1.4 Combined Cycle Cogeneration System ...............................................................126 2.5.5.1.5 Micro Gas Turbines ..............................................................................................128 2.5.5.1.6 Fuel Cells................................................................................................................130 2.5.5.1.7 Stirling Engines .....................................................................................................134 2.5.5.2 Efficiencies ..................................................................................................................137 2.5.5.3 Compatibility with demand..........................................................................................139 2.5.5.4 Barriers for their implementation.................................................................................139 2.5.6 Techno-economic aspects......................................................................................................140 2.5.6.1 Internal Combustion Engines.......................................................................................141 2.5.6.1.1 Gas turbines...........................................................................................................144 2.5.6.2 Steam Turbines ............................................................................................................145 2.5.6.2.1 Micro gas turbines ................................................................................................146 2.5.6.2.2 Stirling engines ......................................................................................................147

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2.5.6.2.3 Fuel Cells................................................................................................................148 2.5.7 Concepts for integration with other technologies and into networks ....................................149 2.5.7.1 Site Appraisal...............................................................................................................154 2.5.8 Socio-economic aspects ........................................................................................................156 2.5.9 Design, simulation and optimisation tools ............................................................................158 2.5.10 References ........................................................................................................................162

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ECO-BUILDING CONCEPTS (CREVER)..................................................... 163

3.1 Analysis of technical aspects....................................................................................................163 3.1.1 Passive measures for reduction of the energy demand ..........................................................163 3.1.2 Active measures for efficient energy supply .........................................................................166 3.1.3 Consideration of embodied energy........................................................................................167 3.1.4 Others measures of reduction of environmental impact ........................................................167 3.2

Techno-economic aspects.........................................................................................................167

3.3

Socio-economic aspects ............................................................................................................168

3.4 Design, simulation and optimisation tools..............................................................................168 3.4.1 References .............................................................................................................................174

4 CONCEPTS FOR TECHNOLOGY INTEGRATION INTO DISTRICT COOLING AND HEATING NETWORKS (CREVER) ........................................ 175 4.1

Description of network configurations and characteristics ..................................................175

4.2 Characteristics of the network according to the alternative distribution fluids.................176 4.2.1 Circulating fluid (steam, hot or cold water) ..........................................................................176 4.2.2 Heating capacity ....................................................................................................................176 4.2.3 Sizing of tubes.......................................................................................................................177 4.3 Pressure and temperature in District Heating systems.........................................................177 4.3.1 Pressure and temperature demands........................................................................................177 4.3.2 Operating level of pressure and temperature .........................................................................178 4.3.3 Comparison of systems at low and high temperature ............................................................179 4.4 Pressure constraints .................................................................................................................180 4.4.1 Differential pressure constraints............................................................................................180 4.4.2 Maximum absolute pressure constraints................................................................................181 4.4.3 Minimum absolute pressure constraints ................................................................................181 4.5

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Temperatures in District Cooling (DC) systems....................................................................181

REPLICABILITY (IC) ...................................................................................... 182

5.1

Introduction..............................................................................................................................182

5.2

Decision Process of an energetic project ................................................................................183

5.3

Methodology of work ...............................................................................................................184

5.4

Checklist for an energy prediagnosis......................................................................................185

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Summary (CREVER) The objective of deliverable DR 1.1 is to report on the different options on energy efficiency and renewable energy systems planning. The solar collector field is the most important part of the solar thermal plant. It is basically made up of the solar thermal collectors, which transform solar energy into heat. There are several solar thermal technologies available on the market for different applications and temperatures. These are mainly the following: FPC: CPC: IRC: ETC: ETC – CPC:

Standard Flat Plate Collector Compound Parabolic Concentrator Collector Integrated Roof Flat Plate Collector Evacuated Tube Collector Compound Parabolic Collector with Evacuated Tube Collector

Design of solar systems involves the evaluation of the solar collector system and the heat storage unit. There are several design and optimisation methods, starting with a simply approach with a minimum of available information, until the more complex procedures involving more information or design tools and optimisation tools. There are two big categories of photovoltaic (PV) systems: -

Stand-alone PV system Grid-connected PV system

A centralized grid connected PV system is characterised from a big power (until some MWp) concentrated in on point. It is connected to the MV network. A decentralized PV system is instead destined to supply the LV network and residential loads. The economic aspects are the critical point of the photovoltaic technology. Although in the last ten years the price of the photovoltaic modules is strongly reduced further due to a market growing and a high development of the technology, they are still too high. Since the module price is high percentage of the PV systems the PV system convenience is tightly related to the economic incentives. Biomass combustion can burn many types of biomass fuel, including wood, agricultural residues, wood pulping liquor, municipal solid waste (MSW) and refuse-derived fuel. Combustion technologies convert biomass fuels using thermochemical and biochemical conversion into several forms of useful energy for commercial or industrial uses; hot air, hot water, steam and electricity. Combustion is the most developed and most frequently applied process use for solid biomass fuels because of its low costs and high reliability. The gasification process is one of the thermochemical conversions that can be used to transform the chemical energy contained in a solid fuel into thermal energy and electricity. The gasification process takes place at around 800-1000°C and needs a moderate supply of oxidant, less than required for a combustion process. The combined heat and power generation via biomass gasification techniques connected to gas-fired engines or gas turbines can achieve significantly higher electrical efficiencies between 22 % and 37 % compared to biomass combustion technologies with steam generation and steam turbine (15 % to 18 %). Biomass feedstock’s can be of many types from diverse sources. This diversity creates technical and economic challenges for biopower plant operators because each feedstocks has different physical and thermochemical characteristics and delivered costs. Increased feedstock flexibility and smaller scales relative to fossil-fuel power plants present opportunities for biopower market penetration.

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Thermally driven chillers and heat pumps are systems that use thermal energy to deliver cooling or heating at several temperature levels. There are various types of sorption cycles with different level of commercial development and availability: • • • • •

Absorption chillers Absorption heat pumps (types I and II) Compression/absorption heat pumps Solid sorption systems Desiccant systems

The dominating type of thermally driven cooling technology to produce chilled water is absorption cooling. Absorption chillers habe been in commercial use for many years, mainly in combination with cogeneration plants using waste heat or directly fired. For air conditioning applications absorption systems commonly use the water/lithium bromide working pair. For some small size and industrial applications ammonia/water machines are also widely used. Adsorption chillers based on solid sorption processes have a much lower market share. Cogeneration is the simultaneous production of power and heat, it is also known as Combined Heat and Power (CHP). The typical prime movers that can be used for cogeneration applications are mainly: Reciprocating engines, Gas turbines, Steam turbines, Combined cycles, Micro gas turbines, Fuel cells and Stirling engines. District heating (DH) is one of the applications of cogeneration. The heat provided by cogeneration is ideal for providing space heating and hot water for domestic, commercial or industrial use. Detailed CHP analysis is needed to calculate the measures of energy and economic performance. In order to assess the performances there is need to construct a model of the system, i.e. a mathematical description of the system consisting of data, rules, inferences and equations. Eco-buildings combine active energy supply systems based on renewable energy and/or polygeneration with passive techniques to reduce the energy demand of the building (bioclimatic architecture concept). The bioclimatic architecture adopts an approach based on building shape optimisation, building orientation, evaluation of climatic parameters such as direction of dominant winds, etc. Many different criterions can be chosen to design and classify the District Heating and Cooling (DHC) systems, according to the case that we face and the characteristics of the system that we want to accomplish. In this project a document is being developed to give guidelines to decision makers who mainly are municipal agents (technicians, politicians,…).

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1 Deliverable objectives (CREVER) The objective of deliverable DR 1.1 is to report on the different options on energy efficiency and renewable energy systems planning and to provide criteria and recommendations to identify and assess the most viable and interesting options for their successful implementation in district energy applications. This report provides an answer to the most frequent and important questions on energy generation technologies faced at the design and energy planning stages of a district energy project. The first part of this report is a comprehensive review of the state of the art of innovative energy efficient and renewable energy technologies: • • • • • •

Solar thermal systems Photovoltaic systems Biomass technologies Thermal cooling systems Hydropower systems Gas cogeneration

Next, eco-building concepts including passive and active measures are briefly reviewed (section 3). The review of all these technologies includes several aspects: technical, economic, integration with other technologies, socio-economic, modelling and optimisation tools. The last two sections of this report dealt with the integration of the presented technologies in District Cooling and Heating (DHC) networks and with their replicability.

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2 Innovative energy efficient and renewable energy systems 2.1 2.1.1

Solar thermal systems (CREVER) Analysis of technical aspects

Solar thermal systems convert solar energy into thermal energy. Usually the main components of the solar thermal plant are the solar collector field, the heat exchanger and the buffer storage tank. All these components and the design approaches are described in the following sections.

2.1.1.1 Solar thermal collectors The solar collector field is the most important part of the solar thermal plant. It is basically made up of the solar thermal collectors, which transform solar energy into heat. There are several solar thermal technologies available on the market for different applications and temperatures (figure 2.1.1). Hot water 40 ºC

Heating / Adsorption cooling 60 ºC

Heating / Absorption cooling 80 ºC

Glazed flat-plate Collector (FPC)

Standard FPC

Vacuum collector

Vacuum flat-plate collector

Evacuated tube collector (ETC)

Direct flow-through (ETC)

CPC collector

IRC collector

100 ºC

Heat Pipe (ETC)

Without reflector (ETC)

Dry connection (ETC)

With reflector (ETC – CPC)

Wet connection (ETC)

Figure 2.1.1 – Main types of solar thermal collectors. Just to avoid an extensive examination of different collectors’ types, the description of six main different type of collectors will be presented. These are the following: FPC:

Standard Flat Plate Collector

CPC:

Compound Parabolic Concentrator Collector

IRC:

Integrated Roof Flat Plate Collector

ETC:

Evacuated Tube Collector

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Compound Parabolic Collector with Evacuated Tube Collector

The variation of the performance of solar thermal collectors can be calculated using the characteristic performance equation:

η = k(Θ) · c 0 - c1 ·

(Tav - Tamb ) (T - T ) 2 - c 2 · av amb G⊥ G⊥

→ Ambient temperature (º C)

T amb

Tav → Average collector operation temperature (º C) k(Θ) → Incident angle modifier G ⊥ → Incident global solar radiation on the collector surface (W/m 2 ) c 0 → Optical efficiency value c1 → Linear thermal loss coefficient c 2 → Quadratic thermal loss coefficient According to this equation, the higher c1 and c2 values of the collector are, the lower is its efficiency with increasing temperatures. Therefore the best collectors from a technical point of view are the ones which present lower values of c1 and c2 coefficients. The collector characteristic values and characteristic curves are determined by recognised test institutes using standardised methods. Unfortunately several national and international standards are o have been in use, giving different characteristic values to the same collector. Thus there is a high risk to compare some collectors the parameters of which have been obtained with different procedures, situation that could lead to make important mistakes.

2.1.1.1.1 Flat plate collector (FPC, CPC, IRC) Standard flat plate collector Almost all the flat plate collectors consist of a metal absorber in a flat rectangular housing. The absorber converts the sunlight into heat, which is transferred to the fluid that flows through some small tubes welded below the absorber. This fluid transports the heat generated to the storage tank or consumer point. Just to capture as much solar energy as possible, some absorbers are covered with a dark spectral-selective coating, which permits a high light absorption capacity and a low thermal emissivity. Also the collector is thermally insulated on its back and edges, and is provided with a transparent cover on the upper surface. Two pipe connections for the supply and return of the heat transfer fluid are fitted, usually to the sides of the collector.

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Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss)

Figure 2.1.2 – Flate Plate Collector (FPC) (Solar Thermal Systems, Dr. Felix A. Peuser, KarlHeinz Remmers, Martin Schnauss) As the picture of figure 2.1.2 shows, different definitions of area are used in the manufactures’ literature to describe the geometry of the collectors, and it is very important not to confuse them. This also applies to all the other solar thermal collector technologies. Gross area: Is the product of the outside dimensions, and defines for example the minimum amount of roof area that is required for mounting. Aperture area: Corresponds to the light entry area of the collector, in other words, is the area through which the solar radiation passes to the collector itself. Absorber Area: Is the area of the actual absorber panel. When comparing different collectors and in the calculations, it is very important to indicate which is the area reference used to determine the characteristic performance equation. It should be noticed that the collector efficiency values can vary considerably depending on which of these areas is used as a reference Good glazed flat-plate collectors with spectral-selective absorbers usually have an optical efficiency around 0,8 and a first coefficient of thermal losses of less than 3 W/m2 K. The average annual efficiency of a complete system with glazed flat plate collectors is 35 – 45 %, depending on the geographical zone and the application. In sunnier zones as Barcelona, with a solar radiation of 1750 kWh/m2y, the annual energy yield ranges between 600 – 800 kWh/m2y. Due to the performance of standard flat plate collectors, selective flat-plate collectors can be used in combination with different cooling technologies. They are well suited for chilled water production using adsorption chillers and eventually single-effect absorption chillers. However, only high-quality collectors with a selective absorber coating are suitable because of the high driving temperatures for these cooling techniques.

2.1.1.1.2 CPC collector (Compound Parabolic Concentrator) An special design of flat plate collectors that reduce the heat losses of a solar collector consists in reducing the area of absorber with respect to the collecting area, since the heat losses are proportional to the absorber area and not to the collecting (aperture) area. This concentration can be obtained using reflectors that force the radiation incident within a certain angle into the collector aperture in direction to the absorber after one or more reflections (figure 2.1.3 and 2.1.4).

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Figure 2.1.3 - Compound Parabolic Concentrator (CPC). Source: Solargenix Winston Series CPC collector, www.solargenix.com This type of collector is characterised by the concentrating ratio, C, which is the ratio of the collector aperture area to the collector absorber area:

C=

A Aperture A Absorber

The acceptance angle, Θa, is another characteristic parameter of the collector and is defined as the maximum incidence angle of the direct solar radiation on the collector aperture that will reach the absorber without tracking.. It is clear that small acceptance angles are related to high concentration factors. For a certain acceptance angle, there is a maximum concentration factor than a collector can achieve, given by the equation:

Cmax =

1 sin (Θ a )

Stationary CPC collectors are used mainly for heating a liquid flow at low (50-70 ºC) an medium temperatures (80-100 ºC). They are provided with two orthogonal axes symmetry and are designed with acceptance angles greater than 30 º to avoid having to track the sun, which means that they usually have maximum concentration factors lower than 2.

Figure 2.1.4 – View of a CPC collector. Source: Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss)

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2.1.1.1.3 IRC collector Some flat plate collectors have the possibility to be integrated into a sloped roof (in-roof installation).

Figure 2.1.5 – View of a CPC collector. Source: Instalaciones solares térmicas, SODEAN – DGS LV Berlin-Brb (Editors). This is and has been an important demand of the professionals of Architecture. The great advantage of these collectors is that the specific and installation costs could be reduced appreciably, especially in large-scale systems. The advantages and disadvantages of FPC collectors are summarised in the next lines: Advantages of flat plate collectors: o o o

They are cheaper than vacuum collector They offer multiple mounting options (on roof, integrate on the roof (IRC), façade mounting and free installation). They have a good price / performance ratio.

Disadvantages: o o o o

They have a lower efficiency than vacuum collectors. A flat support is necessary for flat roof mounting. It is not suitable for generating higher temperatures, which are necessary for steam generation or heat supplies to absorption refrigerating machines. They require more roof space than vacuum collectors for the same amount of energy.

2.1.1.1.4 ETC Collector This collector is formed by some vacuum tubes of high transparent glass the air of which has been evacuated in order to reduce thermal losses from convection and thermal conduction. The inside pressure must be reduced considerably below atmospheric pressure (10-2 – 10-3 kPa) to obtain an important reduction of the thermal loss coefficients.

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Heat conduction Convection

Thermal radiation

Figure 2.1.6 – Evacuated tubes collector. Source: Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss) The absorber is a thin metallic (usually cooper) flat plate placed inside the tube. It receives the solar radiation and converts it into heat. Under the absorber is welded the tube by which flows the thermal fluid that transports the heat obtained to the storage tank (direct-flow vacuum tube) or the heat condenser (heat-pipe vacuum tube).

Figure 2.1.7 – Evacuated tubes collector. Source: Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss)

Direct-flow vacuum tube collector In this collector the fluid flows directly through the absorber in the vacuum tubes. A high performance is achieved due to the direct heat transmission. One of the advantages of this collector is that they can be mounted directly on flat roofs (but only in low-snow regions) and achieve the alignment to the sun turning the absorber to the necessary inclination. This means that the costs of the supporting structure can be minimised significantly.

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Figure 2.1.8 – Cross-section through a direct-flow vacuum tube. Source: Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss)

Heat pipe vacuum tube collector In vacuum tubes incorporating the heat pipe principle, the absorber contains a very slight amount of thermal fluid. This fluid is vaporised at partial vacuum, rises upward as a vapour in the absorber duct, condenses in the condenser and flows in liquid form back into the absorber. The condenser transfers heat to the heat transfer medium of the collector circulation.

Figure 2.1.9 - Heat-pipe vacuum pipe solar collector. Source: Solar Thermal Systems (Dr. Felix, A. Peuser, Karl-Heinz Remmers, Martin Schnauss)

ETC-CPC collector (Sydney) This is a particular design of direct flow-through ETC collector. It is formed by some vacuumsealed double tube placed over parabolic reflectors (see images below). The inner glass tube is provided with a selective coating of a metal carbon compound on a copper base. Into this evacuated double tube is plugged a thermal conducting plate in connection with a U-tube to which the heat is transferred. Several double-tubes are combined into one module (between 6 and 21, according to the supplier). To increase the radiation gain the collector is fitted with external reflectors in the sloping roof version. The flat roof version requires a light background such as gravel or reflective foil, as it does not have reflectors.

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Figure 2.1.10 – Cross-section through a “Sydney” tube with round absorber. Source: Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss)

Figure 2.1.11 – Areas at vacuum tube collector with reflectors. Source: Solar Thermal Systems (Dr. Felix A. Peuser, Karl-Heinz Remmers, Martin Schnauss) The advantages and disadvantages of ETC collectors are summarised in the next lines: Advantages: o o o o

Higher operating temperatures Reduced thermal losses Higher energy yield than flat plate collectors with the same effective absorber area, especially at high working temperatures. Close compact construction of the collector which requires no insulation material.

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Disadvantages: o o

o

High stagnation temperatures, achieved when the solar system is off in a sunny day. Higher specific costs (€ / m2) than with flat plate collectors. The increase in cost is not compensated if only low to medium temperatures are required, despite higher efficiency and reduced array area. Higher costs for available solar heat (€ / kWh) at medium operating temperatures.

2.1.1.2 Selection of solar thermal collectors As a first approach, the following guidelines should be taken into account, depending on the cooling technology: • • •

For double-effect absorption chillers, highly efficient ETC collectors are the only suitable type. For single-effect absorption chillers not only all types of ETC collectors can be considered but also stationary CPC collectors and highly efficient flat-plate collectors. For adsorption chillers FPC, stationary CPC collectors or ETC can be used.

It is important to mention that always a collector with a selectively coated absorber should be chosen in order to achieve sufficiently good performance during operating periods with relatively reduced solar radiation. All these guidelines are visualised in the figure 2.1.12.

Figure 2.1.12 – Collector efficiency and required temperatures for different thermal cooling technologies. Source: Planning and Installing Solar Thermal Systems (DGS LV Berlin BRB, Ecofys 2005

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It is assumed that the collector efficiency for the respective application should be at least 50%. Apart from efficiency curves, the following factors play an important role when choosing suitable collectors: •

Specific collector price. The price per installed square metre of collector field (see section 2.1.7.1) and the price per kW of thermal output, at the desired temperature, should be compared for different technologies.

Local shading situation. It is important to analyse the local shading situation. This can also considerably influence the choice of the collector type if, for example, there is insufficient area for the flat collectors because the intended rood area is partly shaded. Integration of solar collectors. This option should be checked in the project. In this case structural aspects and the appearance can be decisive in deciding for or against a specific collector technology. In such cases the possible substitution of façade components with the implementation of flat-plate collector or evacuated tube collectors is an important factor.

2.1.1.3 Thermal Storage system In general, in solar-assisted air conditioning systems the hot water storage unit fulfils several tasks: • • • • • • •

It decouples the mass flows between solar heat sources and heat sinks. It delivers sufficient energy to the heat sink. It stores heat from the fluctuating solar heat source It delivers sufficient energy to the heat sink. It extends the operation times for auxiliary heating devices. It reduces the needed heating capacity of auxiliary heating devices. It stores the heat at the appropriate temperature levels avoiding mixing in order to reduce energy losses.

In standard solar-assisted air conditioning systems the minimum required hot water volume is shown in the next graph as a function of kWh of cold. Normal values are between 30 and 150 L / (m2 collector). The usual necessary energy capacity in kWh of cold is equivalent to the energy consumed during a whole day with a peak cooling load. If the configuration of the solar-assisted cooling system has an ad/absorption chiller which operates 24 h per day equipped with a back-up heat source and it consumes almost immediately all the solar energy supplied (the cooling demand is much higher than the cooling capacity of the ad/absorption chillers), the volume of this unit is lower than usual. Such a system practically would not need a thermal storage. In the particular case of adsorption machines, it is recommended to install a heat storage unit between the load and the solar system, in order to level out the peaks in the return flow temperature, which generally occur during the chiller interchanging temperature. If storage is not integrated here, the peaks would cause control problems for both the solar collector and the back-up heating system.

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2.1.1.4 Control strategy Basically, in solar systems with buffer storages, two systems have to be controlled and regulated: • •

The collector circuit/buffer storage charging circuit The store discharge circuit

Figure 2.1.13 – Solar system with buffer storage. Source: SolarThermal Systems, Dr. Felix A. Peuser, Kart-Heinz Remmers, Martin Schnauss

1. The collector circuit / buffer storage charging circuit In this case it is recommended to use a control system by irradiation and temperature difference between the solar thermal field and the buffer thermal storage. Thus it is necessary to use a radiation meter (E in the figure above) aligned with the orientation of the collectors. Photo diodes, as the ones used for twilight switches for streetlights, are not suited for this task; it is better to use photovoltaic cells as radiation meters. When the irradiation exceeds a determined value (e.g. 150 – 200 W/m2), the collector circulating pump is switched on. Then, if Tac < 4 ºC (which occurs in very cold nights, especially in the fluid after collectors, just after the first diary activation of the solar circulating pump (Pc)), the bypass must be activated in order to avoid the freezing of the secondary side of the heat exchanger. If Tac > 4 ºC, the bypass must be closed and the collector’s fluid will pass through the heat exchanger. The charging pump (PB) must be activated when sufficient temperature difference (Tac – Tsl ≅ 5 - 7 K) has occurred and the circulating pump (Pc) is already in operation. If this temperature difference is not being reached during a period of time, the circulating pump switches off when the minimum operation time of the pump has run out or the irradiation has fallen below the specified minimum (120 – 170 W/m2). At the same time that the charging pump is activated (PB), the signal from the radiation meter will be deactivated. The deactivation of the switch-off signal from the radiation meter prevents a premature system shutdown when a dark cloud passes by or when during late afternoon in weak insolation, there is still usable residual heat in the collectors. Then, the shutdown of the charging pump (PB) and the circulating pump (Pc) is triggered only when the temperature difference Tac – Tsl becomes small enough (2-3 K typically) or the maximum allowable storage temperature (Tsu) is reached.

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In the particular case of solar-assisted cooling systems, which need a high temperature inside the buffer storage tank and thus also inside the collector, it is recommended to use a flow controlled pumps to vary the volumetric flow (matched-flow systems). Both pumps must be regulated accordingly. To reach a specified minimum temperature, both pumps should start to circulate slowly, until the lowest intended operational temperature is reached. Afterwards, both volumetric flows are increased gradually according to the irradiation rise, so that the difference temperature between collectors and the buffer storage would be maintained constant at about 10 ºC. Finally, the collector is operated in the high-flow mode (30 – 70 L/ h m2) at high levels of irradiation (600 – 1000 W/m2). The need for a high temperature inside the collector has the result that heat losses increase and the solar yield from the collector is reduced. Nevertheless, it is more sensible to produce less energy at a usable temperature, rather than to have more energy at an unusable low temperature. Finally, it must not be forgotten that it is necessary to protect this circuit against the risk of freezing. To avoid this undesirable phenomenon several methods have been developed: • • •

Using a mixture antifreeze-water as the thermal fluid. Using drain-back systems Using water as the thermal fluid and activating the primary circuit pump if temperature drops below < 4 ºC.

Drain-back technology is based on draining the water from the tilted collectors and outdoor collector pipes using the gravitational force and replacing the liquid with air from the top. When the water in the collector is replaced with air, ice cannot be formed and damage is therefore avoided. The water also drains back if the heat store is fully charged, thereby avoiding boiling of water and high pressures inside the system

2. The store discharge circuit In order to maintain high heat transfer coefficients in the generator, many manufacturers recommend keeping the hot-water flow rate of the thermal chiller constant. Under this condition, it is necessary to use a three-way hot water valve in the store discharge circuit, which is the main controlling device of the sorption chiller. It is active at any time that the chiller is active and controls the evaporator outlet temperature by adjusting the generator inlet temperature. In some cases, a variable hot water flow can be used, which lead to lower may return temperatures.

2.1.1.5 Solar thermal collector array design Hydraulic configuration Given that at high levels of irradiation the collector field must be operated on high-flow mode, its hydraulic design must be done according to Tichelmann connection mode, as the next figure shows. This configuration also maintains a good balancing of the hydraulic pressure drops between different points of the circuit.

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Figure 2.1.14 – Cirtuitry of a large collector field according to Tichelmann. Source: SolarThermal Systems, Dr. Felix A. Peuser, Kart-Heinz Remmers, Martin Schnauss

Orientation and tilt angles The orientation of the collector (collector azimuth) array must be south in order to capture as much solar energy as possible. Sometimes, due to integration reasons (solar roof collectors), 20 - 45 º deviations from the South are allowed, depending on the geographical site. On the other hand, the inclination angle of the solar collectors for installations that are working the whole year depends basically on the latitude according to the next simple mathematical expression: Optimal inclination = Latitude - 5 º

It should be noted that this expression is a first approximation because it does not take into account the weather of the zone in study, the energy consumption profile, the configuration of the system, etc. Therefore, to consider meteorological data, is very useful to draw some diagrams, in which the variation of the annual irradiation values with the tilt and orientation angles are displayed. To make such diagrams it is necessary to use the irradiation values obtained from the local meteorological stations, internet (www.soda-is.com), Solar Radiation Atlas, etc. The figure 2.1.15 shows an example of this diagram valid for central Spain (latitude 40.43 º)

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Figure 2.1.15 - Variation of the annual irradiation values with the tilt and orientation angles. Source: Viessmann

According to figure 2.1.15, the maximum irradiation value is achieved with collectors facing true South and a tilt angle of 35 º. Also it should noted that variations of ± 20 º in the tilt angle and ± 45 º in the azimuth, practically do not have an effect on the annual irradiation that strikes solar collectors. Finally, if the configuration of the system, energy consumption profile, thermal losses etc want to be considered, it would be necessary to perform some simulations with the appropriated software packages, the results of which could be also displayed in a diagram (figure below valid for a solar thermal system for heating purposes at central Europe). The efficiency of the system could be expressed in terms of the fractional energy savings, energy yield, etc.

2.1.1.6 Maintenance Solar heating systems require only low-level maintenance if they have been well designed and properly installed. For that reason it is necessary to use durable materials and reliable systems and components according to the standards (EN 12975-1:2001, EN 12975-2:2002, EN 129752:AC/2003, EN 12976-1:2001, EN 12976-2:2001, ENV 12977-1:2002, ENV 12977-2:2002, ENV 12977-3:2002, ISO/DIS 12592:1997, ISO/DIS 9495:1997, ISO 9808:1990, ISO 9553:1997). The most critical components are the connecting pipes between the collectors in the collector array. They must be able to resist high stagnation temperatures and mechanical strain due to absorber thermal expansion, without leaking. Also pipe insulation should be resistant to high temperatures (in some cases above 200 ºC) and protected against solar radiation, weather conditions and animals. Another important aspect is the heat fluid used in the collector loop. It should be chosen accordingly to the materials used in pipes, absorbers, pumps, gaskets, etc. and with a high

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durability. Improper combinations may result in internal corrosion or leaking. In case of doubt, one should consult the standard ISO/TR 10217:1989, which is a guide to materials selection with regard to internal corrosion. Wedel and Bezzel (2000) point out the most appropriate water/glycol mixtures and offer some practical guidelines about ‘stress-reducing’ system layouts. If a drain-back configuration is chosen or in case of warm climates, the thermal fluid could be water without antifreeze additives.

2.1.2

Techno-economic aspects

2.1.2.1 Investments costs Figure 2.1.16 shows that the specific cost of solar thermal collectors decreases with installed collector area. These cost values include the supporting structure and piping of the collectors, but do not include the cost for the heat storage and other systems components (safety valves, expansion vessel, pumps, etc.). According to this figure, it should be noted that evacuated tube collectors (ETC) are much more expensive per m2 than flat plate collectors, especially in small installations.

Figure 2.1.16 – Specific collector cost. Source: Solar-Assisted Air-Conditioning in Buildings, Hans-Martin Henning

Some similar curves are obtained for the total cost of the installation. Since the values greatly depend on the components selected, on the system structure, on the connection to the conventional system, on the installation conditions and on the local labour cost, a range was drawn in the figure 2.1.17.

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Figure 2.1.17 – Range of specific solar installation costs depending on installation size (costs incl. Planning and VAT). Source: SolarThermal Systems, Dr. Felix A. Peuser, Kart-Heinz Remmers, Martin Schnauss In principle, the specific cost of a solar installation decrease with increasing installation size, since components are no more expensive in a linear relationship to installation size and the reductions of the specific cost of the collectors. An example of the distribution of investments costs (including planning fees and sales tax) on the various components of medium and large solar thermal installations could be seen in figure 2.1.18.

Figure 2.1.18 – Distribution of the averaged specific cost of solar systems built within the “Solarthermie 2000” (part 2) programme; (control includes electronics, sensors, pumps and regulated valves). Source: SolarThermal Systems, Dr. Felix A. Peuser, Kart-Heinz Remmers, Martin Schnauss

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Although the collectors have the more costly part of the installation, they are only about one third of the total system cost. This means that, even if one is able to reduce the collector cost by 30 %, the total system price would fall by only 10 %. If one aims at larger cost reductions, the cost reduction potential of many other components has to be exploited as well. The cost fraction of the substructure is relatively high because most of the systems considered were assembled on flat roofs. Therefore, considerable cost saving potential could be achieved if integrated roof collectors (IRC) are used. Cost-saving developments can also be expected for outdoor pipe work. This is especially true for the large labour expense for the protection of pipe insulation against physical damage and environmental impact. Figure 2.1.19 shows the spread of the specific costs for all the parts of a solar thermal system. For the collectors, the variations around the average are fairly small. However those for the framework are rather large. If the collectors are integrated into sloping roofs, the cost for the attachment of the collectors is very small and additional savings can be made for the amount regular roof tiling of new buildings (10 – 35 € / m2). However, for flat roof installations, the cost varies strongly, between 50 and more than 200 €/m2.

Figure 2.1.19 – Spread of costs of large solar systems within the „Solarthermie 2000“ programme. Average values are marked with a dark dot. Source: SolarThermal Systems, Dr. Felix A. Peuser, Kart-Heinz Remmers, Martin Schnauss

The costs of other factors vary differentially. The expense for ‘other pipe work’ strongly depends on the distances involved. The variation in the cost for control is due to choice between simple controls or direct digital controls (DDC).

2.1.7.2 Costs of Usable Solar Heat The cost of the usable solar heat could be determined with a simplified scheme based on only four parameters namely:

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The system investment cost The service life of the complete system (20 years can be expected) Interest rate for the investment capital The annual yield of usable solar heat

From the interest rate and service life expectancy, it could be estimated an annuity factor. Then the cost of usable heat is calculated as follows: Cost of usable heat = (relative annuity · investment cost) / annual solar yield For simplicity, it is assumed that all system components have the same life expectancy. This simplified method does not account for: • •

Maintenance cost: 1 – 2% of the investment cost per year. Such maintenance cost would increase the solar heat cost by about 2 c€ / kWh, for example from 12 to 14 c€ / kWh Cost of electrical auxiliary power: the solar heat would increase by 0.26 c€ / kWh

2.1.3

Concepts for integration with other technologies and into networks

The most frequently used solar-assisted cooling configuration consists of a thermally driven chiller connected to a chiller-water distribution network. The driving heat for the sorption chiller comes from the solar heat production sub-system, which includes the collector, the buffer storage and the back-up heating system. In general, the back-up heat source can be installed in different ways. Either delivers heat to the heat storage unit or directly to the load. In the first case only one connection between heat sources and heat load (chiller generator) occurs, while in the latter case, two heat sources work in parallel, namely the solar storage sub-system and the back-up heat source (gas burner, cogeneration system, etc.). In the first case, the solar collector can work as a pre-heater, raising the return flow temperature from the heat load to an intermediate level, while the back-up heat raises it to the final temperature level that is actually required by the control system. In the second case, the solar storage sub-system can only provide heat, if the actual requested temperature level is achieved. As long as this is not the case, the back-up heat source is switched on. Each concept has some advantages and disadvantages. In the first case the temperature level to be achieved by the solar thermal system is somewhat lower. However, since the back-up heating system also uses the storage tank, the available volume for the solar system is reduced. In any case for both concepts, it is recommended to install a heat storage unit between the load and the solar system if an adsorption chiller is used, in order to level out the peaks in the return flow temperature, which generally occur during the chiller interchanging temperature. If storage is not integrated here, the peaks would cause control problems for both the solar collector and the back-up heating system.

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Socio-economic aspects

Solar thermal technologies transform solar energy into useful heat or cooling. On the current market are efficient and highly reliable products, providing solar energy for a wide range of applications. Applications Domestic hot water is currently the most frequent application, although solar thermal is also being increasingly used for space heating in residential and commercial buildings, swimming pool heating, industrial and agricultural process heat, solar assisted cooling, district heating, and other applications requiring heat or cold. Solar thermal collectors can also be used to produce electricity (solar thermal power). Economic benefits Solar thermal provides clean, safe and renewable energy. Solar radiation is free, maintenance costs are very low and the systems work for decades. Solar thermal increases the predictability of heating costs and reduces dependency on fuels imported from unstable regions. Security on energy supply The EU already imports 50% of its energy needs. This dependency will increase to over 70% by 2030, mainly due to the depletion of the North Sea oil and gas reservoirs.

Figure 2.1.20 - Imported energy: growing dependence of EU 15. Nearly two thirds of world oil reserves are concentrated in six countries around the Persian Gulf. Within the next two decades, their share of global oil production will be certain to show a strong increase, as reserves in other exporting countries simultaneously decrease. New discoveries of oil reserves have been declining since the 1960s. Since the 1980s, new discoveries are made at a lower rate than global oil is produced. The global oil output peak could be reached as early as 2006 (Oil & Gas Journal, 26 April 2004). However, after that peak, a long-term decline in oil production will be unavoidable. If alternative energy sources are not developed quickly enough, global economic and political instability, more conflicts and possibly shortages of energy supply are already on the agenda. For Europe, import dependency will become an increasing problem as large developing countries such as China and India increase their energy consumption. The main conventional alternatives are gas, coal and nuclear. Gas production will reach its peak a few decades after oil. A massive increase in coal usage would further boost climatic change.

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Most EU citizens are averse to nuclear power expansion, due to its incalculable risks for safety and health. Renewable energies and energy savings are the only real alternatives available to secure the energy supply. The development of renewables must be forced as soon as possible to avoid serious risks for Europe’s society. Solar thermal systems replace precious gas, oil and electricity used for heating or cooling purposes. In EU-15 alone, the potential usage of solar thermal equates to 58Mtoe per annum, i.e. 30% of the EU oil imports from the Middle East in 1999. Solar thermal contribution to renewables Solar Thermal has been underestimated for years. This is partly due to the fact that it usually does not show up in energy statistics. Each kWh produced by a windmill is metered by the grid operator, but the heat produced by a domestic hot water system is not reported to a statistics body. Thus, the contribution of solar thermal to our energy supply mix is less visible. Taking a look at the installed capacity of different renewables the picture becomes much clearer: Market development At the end of 2003 approx. 12million m2 of solar thermal collectors had been installed in the EU. These supply 4900GWh of heat each year. Up to 1.4billion m2 of solar thermal collectors could be realised in the EU countries (not including the new member states). These collectors would be able to provide up to 680,000GWh of heat energy. If the full potential of EU-15 were to be realised, the amount of energy produced by solar thermal would equate to 6% of final energy consumption. Combined with energy efficiency solar thermal could supply a substantial share of the energy demand for heating and cooling.

Figure 2.1.21 - Growth of solar thermal in the EU. The average annual growth rate in the past has been 11.7%. If this growth continues, there will be approx. 46million m2 of solar thermal collectors installed by the year 2015. Setting the right political conditions could significantly speed up the use of the technology. This could lead to an installed total of 200 million m2 of solar thermal collectors by the year 2015. The EU Whitepaper calls for 100 million m2 by 2010; were Europe as a whole to have the same per capita rate of Austria, this would easily be met by that deadline.

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Table 2.1.1 - Growth scenarios for solar thermal energy.

To achieve the 200 million m2 breakthrough, solar thermal will need to play an important role in all areas of building services. If similar political instruments were to be adopted for solar thermal as those used to develop wind energy, this could easily be achieved. The "strong regulation" scenario refers to the residential sector only, the single most important market segment for solar thermal. It is assumed that binding regulations require the installation of solar thermal on newly built residential buildings or those undergoing major renovations (such regulations would thus exceed the scope of the original "Barcelona Model", which only applies to new buildings). If all EU-15 members enacted such regulations between now and 2015, the collector area in operation by 2015 in the residential sector alone would amount to 199 million m2. Social effects If appropriate political and market conditions were to be developed, some 580,000 full-time jobs would be created by the year 2030. Solar thermal jobs create local income sources and are easily targeted for regional development.

Figure 2.1.22 - Solar thermal keeps Europe working. The number of jobs that would be created is much higher than the ones with other technologies. Per generated 1000GWh of supplied primary energy, the number of jobs in each industry is as follows: Hard coal: 90 jobs; Nuclear power: 72 jobs; Solar technology: 3960 jobs.

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Solar thermal could provide more than 6% of the total energy consumption throughout Europe, meaning that it could replace the hard coal from Germany (which provided 5.5% of Germany's total energy consumption in 2002, thus creating many new and more healthy jobs, as well as providing new changes for the coal miners) A mixture of job types would be created in the fields of manufacturing, engineering, installation and maintenance. A cross section of skill sets and economic rewards would be developed across several social economic groups within the workforce. The risk of job migration, to countries outside the EU, is low. Environmental benefits Solar thermal replaces polluting and imported fuels such as oil, coal, gas and nuclear, thus reducing the problems associated with those technologies. In particular, solar thermal: • helps to mitigate climatic change as it does not emit CO2 • reduces the risk of ecological catastrophes linked to oil transport • does not produce radioactive waste as in the case of nuclear energy Thousands of scientists around the world are currently conducting research into climate change. A broad majority of them consider it to be a proven fact that human influence is connected to the rapid warming of the earth’s atmosphere. We can derive from this that human influence is seen as the main cause of the increased frequency of climatic disasters.

Figure 2.1.23 - Damage due to climatic change. According to statements by large insurance companies, such as Münchener Rück in Germany, a direct correlation exists between the increased frequency of natural disasters and the human influenced warming of the earth's atmosphere. Thus, the immense damage caused in recent years could be reduced in the long term if CO2 emissions were to be cut back on a global level. Europe has felt the severe impact of climate change in the form of an increasing frequency of extreme weather conditions, such as storms and flooding. In some regions, climate change is causing droughts that lead to widespread famines. In other places, sudden deluges occur, with a high toll of dead and injured. All of these events cause massive economic damage for which the region in question has to foot the bill. These costs can be and often are crippling, especially for developing and emerging countries.

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Goals that can be achieved by solar thermal technology • • • • • • •

Replacement of conventional energies: 6% of EU final energy consumption (EU-15) could be replaced by solar thermal Security and diversity of energy supply, e.g. 30% of EU oil imports from Middle East (1999) can be replaced Reduction of greenhouse gas emissions Reduction of emissions causing urban pollution Reduction of other external costs caused by fossil fuels and nuclear power Creation of local jobs and SMEs development Export of know-how and equipment

Main barriers • • • • • • • • • • •

Higher upfront costs than conventional heating and cooling technologies Pay-back times often too long for commercial investment decisions Not yet perceived as a standard option for heating – therefore the decision-maker must be specially motivated Higher transaction costs (information, procurement, installation works) compared with the conventional heating (default option) Solar thermal not yet fully integrated into mainstream heating and construction sectors Low awareness of energy savings and environment Low awareness of solar thermal, especially among the relevant decision makers Lack of availability of motivated and specifically skilled installers Harmonised standards, certification and quality labels not yet widely recognised in the market and by public authorities – this barrier being solved through EN standards and Solar Keymark Applications with high potential not yet available in standard solutions (combisystems) or still in demonstration phase (solar cooling, process heat) Heating and cooling products do not have a high-tech image amongst most consumers and policy makers

Conditions required for successful solar thermal markets • • • • • • • • • • • •

Cohesive market structures Internalisation of external costs of conventional energies Regulations making the use of solar thermal mandatory Stable and well designed financial incentive schemes Public campaigns promoting solar thermal General awareness of energy savings and environment High awareness of solar thermal, especially among the relevant decision makers Highly visible demonstration projects - often with public authorities serving as model Availability of motivated and specifically skilled installers High trust through quality products and recognised quality label Availability of standard products and applications – showing the success of solar thermal Inclusion of solar thermal in R&D programmes

Strategies that can help to overcome the barriers • • • •

Set positive examples through the use of solar thermal in public buildings Raise awareness through the use of modern communication techniques Set national targets and initiate national/local support schemes Level the playing field through adequate financial incentives

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Help make solar thermal a mainstream technology through binding regulation Widen the cost-effective use of solar thermal through R&D programmes

2.1.5

Design, simulation and optimisation tools

Design of solar systems involves the evaluation of the solar collector system and the heat storage unit. But it has to be taken into account that the design of the solar collectors, the heat storage unit, and the solar character of the heat source, will influence in the design of the cold water storage system and the backup cooling chiller compression unit. There are several design and optimisation methods, starting with a simply approach with a minimum of available information, until the more complex procedures involving more information or design tools and optimisation tools. One of the most important aspects in the design and simulation process is the availability of meteorological data. Some of these methods are listed next: • • • • • •

Rules of thumb based on experience with installed systems (starting point). Comparison of solar collectors with regard to the necessary investment per heating power at a design point. Comparison of solar collectors with regard to the cost of produced heat for a given climate and a given operation temperature. Design of solar thermal system (collector, heat storage, back-up) for solar-assisted airconditioning with regard to possible solar contributions to the overall energy demand for a given climate and a given load. Computer design tools which allow the simulation of a selected system on whole-year basis. More complex simulation tools, for example TRNSYS.

Simplified design Rules of thumb The simplest method to size the solar system is starting from a design point, with a specified solar radiation power G, the nominal cooling capacity desired (Qdessign), the collector efficiency at design conditions (ηdessign) and the COP values of the absorption / adsorption chiller. The required collector area is defined by:

A=

Q dessign G ⊥ ⋅ η dessign ⋅ COP

Comparison of solar collectors •

Heating Power

To decide the convenience of the use of solar energy, and chose the suitable solar collector type, an evaluation between the different solar collector types is made for different operating conditions and collector types. The evaluation can be performed comparing the required area or the investment cost. Results from this method are show in the next figure, where a comparison between four different collectors is performed. The advantage of this method is that no information on the specific project is necessary, neither on the cooling load nor on the climatic data. The only required specific information is that of the

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operating temperature of the thermally driven cooling system at design conditions and the collector parameters. •

Gross heat production of the collector

Another approach for selecting a solar collector for a given application is the calculation of the annual gross heat production (Qgross) of the collector. Time series of hourly values of solar radiation and average ambient air temperatures are necessary. The gross heat production is then calculated in each time slice for a given operation parameters (average fluid temperature, orientation, tilt angle). The useful collector yield that is under real operating conditions is always below the calculated values because generally, not every unit of heat produced by the collector can be consumed by the application system. Only in the case of very small solar fraction, calculated gross heat production approaches the actual collector production. After calculating the solar thermal yield, the cost of the usable solar heat is then calculated for each type of collector as follows:

Cost of usable heat = (relative annuity · investment cost) / annual solar yield Then, these costs are displayed is some graphs and the collector which would have the lower cost would be the best one to the installation. More detailed approach The use of simulation tools helps to reduce the necessary time in the design stage and to perform several comparatives between different alternatives to choose the most reliable and efficient configuration. In addition, usually the simulation program includes meteorological data of the most important cities that is one of the most important information to take into account in the design process. If the meteorological data is not available for the city of interest, data from the nearest place can be used, or meteorological files for a concrete site can be obtained from others software or web services. Mainly, there are two types of simulations tools, one with pre-defined systems, and other that allow the modelling of any systems with an open simulation platform. The first type of program is those in which the user has to choose between several pre-defined configurations. Examples of software with pre-defined configurations are SACE, TASK 25. The most used program with open simulation platform is TRNSYS, where a library which contains models for many thermal components, enables the user to develop his own system. An special version of this platform is the TRANSOL package, which simulates some predefined common solar thermal systems. Other commercially available tools, which contain components, are MatlabSimulink with the Carnot package, ColSim or Smile.

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Photovoltaic systems (PoliTo) Analysis of technical aspects

2.2.1.1 The photovoltaic cell A photovoltaic cell is composed by two different semiconductor layer that create in the cell a fixed electrical field like in a diode. This electrical field allows an easy current passage in one direction and almost impossible on the other direction, figure 2.2.1. I Solar light

N Electrical field

External load

P

I

Figure 2.2.1 - Photovoltaic cell The electrical field is as near as possible to the device region which absorbs the solar light. Of course it is impossible to use all the solar energy, in fact the light which arrives on the photovoltaic cell surface can be reflected, cross the photovoltaic cell or absorbed. Only the last mentioned case generates the conversion of the solar energy in electrical energy. The absorbed photons can excite an electron on the valance band and bring it to the conduction band crossing the electrical field. The excited electron can not come back because the electrical field do not permit this passage. Therefore, if we connect a load to the terminal of the photovoltaic cell, we will appreciate an electrical current. In a photovoltaic cell the primary energy is the electromagnetic solar radiation, Figure . Like the human eye, also the photovoltaic cell is sensible only to a range of the solar spectrum. This range depends from the kind of photovoltaic cell and goes approximately from 0.4 to 1.1 µm. Out of the atmosphere solar radiation is characterized by the total power density of 1350 W/m2 (solar constant). On the earth ground this value is reduced in relation of the atmosphere thickness covered by the sun light. This is a parameter called air mass. With reference to Figure 2.2., supposing unitary the length covered by the sun light through the atmosphere on the sea level and whit the sun on the zenith (AM=1), we can see that in another condition of the sun elevation the air mass can be bigger than one, with α = 30° the air mass is double. In conclusion on the earth ground the atmosphere effect reduce the solar constant near to 1000 W/m2 (in AM=1 condition).

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AM=1

2000

AM0

1600

AM=2 AM1

1200 800

α=30°

400 0 0

0,5

1

1,5

2

2,5

λ [ µ m]

Figure 2.2.2 a - Electromagnetic solar irradiation

Figure 2.2.2 b - Air mass

2.2.1.2 Equivalent circuit The just mentioned process can be described by the following electrical circuit:

I Rs Iph

Ij

Uj

Ish

Rsh

U

Figure 2.2.1 - Photovoltaic cell equivalent circuit The photovoltaic cell is described by an ideal current generator with a diode in parallel which represents the straighten effect of the junction. The generated current Iph is proportional both to the lighted cell surface and the irradiance:

I ph = kGS

(1)

the diode current value is:

I j = I 0 (e

AU j

− 1)

(2)

with:

A=

q mKT

(3)

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where: -

I0 is the inverse polarization current, q is the electron charge, K is the Boltzman’s constant, T is the absolute junction temperature, m is coefficient used to consider the non ideal effect of the junction.

The circuit description is completed by: -

Rsh: resistance that models the dispersion current through the photovoltaic cell; RS: resistance that contains the semiconductor resistance, the electrodes resistance and the contacts resistance.

Look at the electrical equivalent circuit is it possible to derive some relations useful to study the photovoltaic generator. Considering the terminals of the photovoltaic cell it is possible to write:

I = I ph − I j −

Uj Rsh

U = U j − RS I

(4) (5)

By the equations (2), (4), (5) we can derive the following:

U=

1 I ph − (1 + RS Rsh ) I − U Rsh + I 0 ln − RS I A I0

(6)

This is an implicit equation, in fact U is in both members. Anyway we can note that Rsh >> RS so that we can neglect the term U/Rsh and derive an explicit equation:

U=

1 I ph − I + I 0 ln − RS I A I0

(7)

Imposing I = 0 in the last equation it is possible to derive the open circuit voltage:

U OC =

1 I ph + I 0 ln A I0

(8)

Proceeding at the same way, using the equations (2) and (5) in the equation (4) and neglecting the term U/Rsh we obtain:

I = I ph − I 0 − [e A(U + RS I ) − 1]

(9)

Imposing U=0 we can derive the short circuit current:

I = I ph − I 0 − (e ARS I − 1) Considering that RS in very little, we can do another simplification imposing RS = 0 to obtain:

(10)

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I SC ≅ I ph = kSG

(11)

Therefore the short circuit current is proportional to the irradiance and the surface of the cell.

2.2.1.3 Current-Voltage characteristics For a deeply knowledge of the photovoltaic cell we need to derive the Current-Voltage characteristic. We can draw the characteristic in three steps:

I

I

I a)

Iph

a)

b)

b)

c)

RSI

Ij

Uj /Rsh

U

U A)

U C)

B) Figure 2.2.2 – Characteristic graphical construction.

1. from the (4) we can draw the I(Uj) neglecting Uj/Rsh. It is the difference between the ideal generator characteristic and the diode characteristic. We obtain the curve a). Figure 2.2.2.A. 2. Then we subtract from the curve a) the contribute Uj/Rsh obtaining the curve b). It is decreasing where the curve a) is horizontal and its intersection with axis I = 0 is moved to the left. Figure 2.2.2.B. 3. Concluding we obtain the I(U) subtracting from the curve b), according to the (5), the contribute RSI obtaining the curve c) which is the Current-Voltage characteristic. Figure 2.2.2.C.

Now that we have derived the characteristic, Figure 2.2.3, we can do the following consideration:

I ISC IM

I(U)

PM

Q

G=const T=const

P(U)

UM

UOC

U

Figure 2.2.3 - Photovoltaic cell characteristic

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-

the coordinates of the characteristics gives power that the cell can supply. In particular UM and IM are the coordinates relative to the maximum power point. PM is situated on the knee of the curve;

-

we define fill factor the following parameters:

Kf =

-

UM ⋅ IM U OC ⋅ I SC

(12)

it represents the global effect of Rsh and RS on the characteristic. Usual value for the silicon are Kf = 0.7 ÷ 0.8. the short-circuit of the cell is not dangerous. In fact IM ≈ 0.8 ÷ 0.9 ISC.

Until this moment the photovoltaic has been considered just like a generator but in some anomalous cases it could work in other configurations. Therefore it is important to study the complete I-U characteristic, Figure 2.2.4.

I PM

PdM

G=const T=const

ISC

U

U

I

Ub

I

0

U0

U

U I

PdM

Figure 2.2.4 - Complete -U characteristic We can see that the characteristic is extendible on the quadrants II and IV. Inside these quadrants the photovoltaic cell works respectively as a load (U<0, I>0) and with inverse current (U>0, I<0). It is important to avoid these two work conditions, also if they are acceptable if the working point is inside the curve of maximum dissipable power, Pdm. Moreover the inverse voltage must be always under the break-down voltage, Ub.

2.2.1.4 Irradiance an temperature influence To understand how the irradiance and the temperature influence the characteristic of the cell we can use the equation derived in the paragraphs 2.2.1.2. With a reduction of irradiance the ISC decreases according to (11), while the UOC has a logarithmical decreasing; equations (8) and (1). These assertions can be summarized in Figure 2.2.5.

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With an increase of temperature there are a little increase of the Iph, therefore also of the ISC. Moreover there is an increase of the Ij that determines a reduction of the open circuit voltage, Figure 2.2.6.

I

I

T=25 °C G=1000 W/m2

PM

G=1000 W/m2

800

0,5

0,5

600 400

T= 0 °C T= 25 °C T= 60 °C

200

0,5

Figure 2.2.5 - Irradiance influence

U

0,5

Figure 2.2.6 - Temperature influence

Looking at Figure 2.2.5 it is obvious that a decrease of the irradiance is followed by a decrease of the maximum power point of the characteristic. Instead, also if it the same for an increase of temperature, this is not so evident. To better understand the entities of the temperature influence we report the following specific variations: -

dJ SC mA = 0.01 dT cm 2 °C

-

dU OC mV = −2.2 dT °C cell

-

(dPM PM ) % = −0.5 dT °C

Through Figure 2.2.5 and Figure 2.2.6 it is possible to derive the area described from the maximum power point in relation of the irradiance and temperature variation, Figure 2.2.7.

U

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I G

ISC

T1 T2 > T1

0,2 G

U

UOC Figure 2.2.7 - Maximum power point area

This is an important result because the photovoltaic generator works with primary power imposed (PS = GS), so the yield η = P/PS will have the same shape of the curves P(U). This means that it is recommended to work near the maximum power point because it is the point with the highest yield.

2.2.1.5 Yields In a photovoltaic cell the energy conversion is inevitably associated to some losses: -

reflection and masking of the cell surface, (∼10%), incident solar light with too much energy, (∼30%), incident solar light with not enough energy, (∼20%), recombination factor, i.e. not all the couples electron-hole are kept separated by the electrical field, (∼2%) shape factor, not all the produced energy is usable. There are some losses due to Rsh and RS, (∼20%)

Table 2.2.1 summarizes the solar cell yields differencing the laboratory condition from the production condition. Table 2.2.1 - Photovoltaic cell yields Photovoltaic cell

Laboratory yield

Production yield

Si mono-crystalline

0.23

0.18

Si poly-crystalline

0.18

0.15

Si amorphous

0.12

0.08

GaAs (for spatial applications)

0.26

0.19

The GaAs cell has the highest yield but their cost make their use possible only for the space application.

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2.2.1.6 Cell adjusting to user parameters Due to its limited output value of current and voltage a singular photovoltaic cell is not useful. To achieve the necessary levels of current and voltage we have to use more than one cell opportunely connected. To increase the voltage level we have to connect some cells in series, instead, if we want to increase the current we have to connect some cells in parallel. In the real applications the two solutions are used at the same time but now we will examine one solution at the time.

2.2.1.6.1 Series of photovoltaic cells We analyze a situation where there are NS cells in series. In normal conditions all the cells have the same characteristic but it could happen that one cell has a different characteristic, due to shading problems for example. This is called mismatching phenomenon. Whit reference to Figure 2.2.8, pink curve is relative to the NS-1 cells that operate on normal conditions, instead the green curve is relative to the shaded cell. The characteristic of the NS cell, curve red, is obtained adding the voltages of the two curves relative to the same current value. We can note that:

U OC =

∑U

(13)

OCi

i

I SC ≅ I SCmin

(14)

I b) P P' a) c) P''

a')

c') 0

Ub

UOC

U

Figure 2.2.8 - Characteristic of cells in series It is important to focus the attention on the working point of the shaded cell in relation to the load condition. If we connect to the NS cell a resistive load, grey line, the global working point is the intersection of the grey line with the red line. Starting from this point with an horizontal line, it intersects the green curves on the working point of the shaded cell, point P’. We note that it is in the II quadrant, this means that the shaded cell works as a load. The worst case for the shades cell is when the load is a short circuit. In this case we can have three situations: -

UP’ > Ub


immediately breaking of the shaded cell

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UP’ < Ub but PP’ > Pdm

-

UP’ < Ub but PP’ < Pdm

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possible creation of “hot spots” on the shaded cell depending on the anomalous situation duration. The “hot spots” causes the decrease of the cell performance
reduction of maximum power that the NS cells can provide.

We can note that the situation is better if the characteristic of the shaded cell is more different that the characteristic of the other cells because the maximum power point is reduced to a very low value. This case is represented by the blue curves and the orange curve. Of course we have to avoid the dangerous situations above described. To achieve this aim we can connect an anti-parallel diode for every cell, Figure 2.2.9. This diode, going in conduction state when the cell works with an inverse voltage, by-passes the cell and disperses the supplied power from the NS -1 cells.

Dp

Dp

Dp

Dp

I

Figure 2.2.9 - Anti-parallel diodes On the photovoltaic modules, we can not use an anti-parallel diode for every cell because it will be too much expensive. An anti-parallel diode is used to protect more that one cell in series configuration.

2.2.1.6.2 Parallel of photovoltaic cells This is the dual case of the precedent analysis; therefore we report only the main results. We consider NP cells in parallel configuration. The characteristics are represented in Figure 2.2.10. We can see the characteristic on the NP-1 cells that operate on normal conditions, pink curves; the characteristics of the shaded cell, green curves; and the global characteristic, red curves. We can note that: I SC = I OCi (15)

∑ i

U OC ≅ U OCmin

(16)

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c) b)

I SC (Np-1)ISCi

P a)

U P' Figure 2.2.10 - Characteristic of cells in parallel Now the worst situation for the shaded cell is open circuit configuration. In fact the shaded cell has to work with inverse current. Therefore the same considerations of the previous paragraph are valid. The solution in this case is to use a series diode. We can not use the diode series for a parallel of single cells, because the voltage drop on the diode is comparable with the voltage output of the cell. We have to use the diode series when there are a parallel of more cell in series configuration, Figure 2.2.11 DS

DS

DS I

Figure 2.2.11 – Series diodes

2.2.1.7 Terminology With analogy of what we have said for the cells, to obtain a photovoltaic system with the right voltage and current values it is necessary to connect more modules in series and parallel. Inside the photovoltaic generator there are all the elements previous mentioned. In Figure 2.2.12 we can see the terminology of the groups that constitute the photovoltaic generator.

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Photovoltaic field

Array

Panel

Module Photovoltaic cell

Figure 2.2.12 - Terminology The Current-Voltage characteristic of the photovoltaic generator is equal to the cell characteristic but on a different scale. This means that all the things just said for the cells are valid also for the photovoltaic generator.

2.2.1.8 Photovoltaic system There are two big categories of photovoltaic (PV) systems: - Stand-alone PV system - Grid-connected PV system We will examine one category at the time focussing more attention on the grid-connected PV system because this is the most used configuration.

2.2.1.9 Stand-Alone PV systems Inside this category there is again a subdivision: - without accumulation - with accumulation The PV systems without accumulation are usually applied to the water pumping. Really the accumulation of the energy is represented by a water container from which, for example through an hydraulic circuit, it is possible to irrigate a field, Figure 2.2.13.

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Container Hydraulic circuit

PV generator

electric engine + DC/AC conversion (if necessary)

pump

Bacino o corso d'acqua

Figure 2.2.13 - Blocks diagram of a stand alone PV system without accumulation This kind of application is a smallest percentage of the stand-alone PV systems visible in the world. Most of the PV systems stand-alone are instead with accumulation. Typically they have a little size and they are used to supply energy in rural places where it is hard, or too expensive, derive an electrical alimentation line from the national network. In Figure 2.2.14 is shown a schematically representation of this PV systems.

PV generator

Charge regulator

Load

inverter

Accumulator

Figure 2.2.14 - Blocks diagram of a stand alone PV system with accumulation It is substantially constituted by an electrochemical accumulator, which is a very important device of the installation because it makes the following functions: -

it ensures the energy continuity accumulating the energy surplus, it stabilizes the output voltage, it binds the PV system to work near the maximum power point (MPP).

The first and the second point are obvious but the third point needs an ulterior explanation. We have to remember that the MPP is contained in a vertical band for irradiance and temperature variation, Figure 2.2.7. Since the accumulator characteristic is a vertical line, if we set to the centre of the area this characteristic the PV generator will work always near the MPP, Figure 2.2.15

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I G

ISC

T1 T2 > T1

0,2 G

UOC

U

Figure 2.2.15 - I-U characteristic and accumulator characteristic Then we can see the charge regulator, this is necessary because in this kind of system the generated current is supplied from both sources (PV system and accumulator). The energy flow during the day is dependent from the irradiance; the energy deficit (or surplus) is compensated from the accumulator. It is possible to represent the characteristic of the accumulator “State Of Charge” (SOC) during the day,

Figure 2.2.16 - State of charge The charge regulator is important to avoid a damaging of the accumulator by an excessive charge of discharge. Finally we can see the inverter, we spend about it only a few words. It is necessary because most of the application requires an AC system, instead the PV system produces energy in DC current. Therefore we need for an inverter, i.e. am electrical device that makes a DC/AC conversion.

2.2.1.9.1 Application

It is growing the interest about this kind of PV systems in the public illumination field. In fact through them we can illuminate parking, roads, town parks, etc, avoiding expensive work for the electrification of these spaces and achieving significant energy savings.

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2.2.1.10 Grid-connected PV systems Also this kind of PV systems can be subdivided in two subcategories: - centralized grid connected PV systems, - decentralized grid connected PV systems. A centralized grid connected PV system is a really electrical power plant. It is characterized from a big power (until some MWp) concentred in on point. It is connected to the MV network and usually it is designed to produce the maximum energy when there is the most energy demand. In the design project it must consider that the PV system power has to be less than 20÷30% of the power network, this is important to avoid an excessive voltage rising. A decentralized PV system is instead destined to supply the LV network and the residential loads. The purpose of this PV systems is to achieve an energy saving. In Figure 2.2.17 we can see a block diagram of these installations. inverter MPPT

PV system

Interface

Network

Local load Algorithm control of: - MPPT - PWM modulation with cosϕ=1 - islanding and over-load protections - measure interface

Figure 2.2.17 - Blocks diagram of a grid-connected PV system In this case we don’t need for the accumulator because the network balances the surplus and deficit of power, Figure 2.2.18. PV production

Power [W]

SELLING

Energy demand BUYING 0

SAVING 12 Time [h]

BUYING 24

Figure 2.2.18 - Energy balance during a day Now we will focus the attention an important device shown in Figure 2.2.17, the Maximum Power Point Tracker (MPPT). This devise binds the PV system to work in the MPP, i.e. with the maximum yield. To explain the importance of this device we suppose to supply a resistive load directly with a PV system. With reference to Figure 2.2.19, we start with the conditions of irradiance G and working point A. If, for the environmental condition, the irradiance is reduced to a value G’, the new working point will be A’, that is far from the MPP in the actual condition. However, if we put a DC/DC converter between the PV systems and the load, we can set it to work with UM and IM as input values and UM’ and IM’ as output values. This means that the PV

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system is working in the MPP (point M) and, through the DC/DC converter, this maximum power is transferred to the load (point M’)

I

PM

G A

IM' I M G'

M' A'

M

UM'

O

UM

U

Figure 2.2.19 - Maximum power point tracker behaviour Of course to follow the MPP it is necessary a control algorithm that leads the DC/DC converter. The control algorithm and the DC/DC converter constitute the Maximum Power Point Tracker. They are subdivided in two big categories: -

static MPPT, dynamic MPPT.

To better understand the behaviour of the MPPT now we examine two examples of each category.

Static MPPT Their behaviour is very simple. It is based on the fact that the ratio of the UMPP and the UOC is almost constant when changes the working conditions:

U MPP ≅ K <1 U OC Therefore, when is defined the K factor, it is possible, measuring with a certain frequency the open circuit voltage, set the PV system working point on the MPP using the (17). This control algorithm reduces the global installation yield because, since K is not a really constant, the system will not work in the real MPP but only near to it. Then the open circuit voltage measure, also if it is fast, imply the disconnection of the PV system from the load. This is translated in losses for not transferred power.

Dynamic MPPT with “Incremental Conductance Algorithm “ This algorithm is based on the equation that describes the maximum of the characteristic P(U):

∂P ∂ (V ⋅ I ) ∂I = = I +V =0 ∂V ∂V ∂V

(17)

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From this equation we can achieve the possible situation:

∂P ∂I I
=0 =− ∂V ∂V V ∂I I ∂P >−
>0 ∂V V ∂V ∂I I ∂P <−
<0 ∂V V ∂V The values of voltage and current are measured by the control system, and then each measure is used with the previous measure to calculate ∂V and ∂I. Now the algorithm proceeds according to the following rules: 1. ∂V=0 e

∂I=0
no variations ∂I>0
increase voltage ∂I<0
decrease voltage

2. ∂V≠0 and

(18) satisfied
no variation (19) satisfied
increase voltage (20) satisfied
decrease voltage

This algorithm allows achieving best yield because it reaches the real MPP and there aren’t losses for not transferred power.

2.2.1.10.1 Islanding behaviour The islanding behaviour is the situation where, without the electrical network voltage, the PV system continues automatically to supply electrical energy. This situation is dangerous because for a planned maintenance of the electrical network, it could be intentionally sectioned and to be again supplied from the PV system. Another problems derive from the auto-closure of the switches finalized to checking if a fault is transitory on not. Between the open and the closure, the inverter can lose the synchronism; therefore the auto-closure can damage the inverter. To avoid these problems, the inverters for grid-connected PV system have to be equipped with the islanding protection, which understands if there isn’t the network with under/over voltage relays and under/over voltage frequency.

2.2.2

Techno-economic aspects

The economic aspects are the critical point of the photovoltaic technology. Although in the last ten years the price of the photovoltaic modules is strongly reduced further to a market growing and a developing of the technology, they are already too high. Since the module price is high percentage of the PV systems, Figure 2.2.20, the PV system convenience is tightly related to the economic incentives.

(18) (19) (20)

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12% 2% 6%

Modules Inverter Support Electronic devices Design Other

8% 56%

16%

Figure 2.2.20 – Subdivision of the investment prices A rough evaluation of the PV system total price is summarised in Table 2.2.2. Table 2.2.2 - PV system prices PV system

Price [€/kWp]

Stand-Alone

12000÷14000

Grid-connected

6000÷7000

The Italian situation of the incentives for the photovoltaic system is in a development phase. Less than a year ago, the PV systems were financed by the state with an amount of 75% of he whole PV system prices. The calculation of the payback time relative to the 25% of the PV system had to be done considering the energy savings coming from the PV system. Moreover the necessary bureaucracy to obtain the financing was very low and discriminant. Instead, since 28th July 2005 in Italy is started a new a new financing role for photovoltaic applications which is called “Conto Energia”. Now there is a funding for the energy produced from the PV system. The financing role is different in relation to the PV system size but it can be explained with reference to Figure 2.2.21 for all the size.

2.2.2.1 PV system size from 1 to 20 kWp -

Al the energy produced is remunerated 0.445 €/kWh It is possible to do the net-metering

This means that all the energy produced is remunerated and the instantaneous absorption of this energy is not seen from the bidirectional meter, therefore we have a cost saving, because we don’t have to buy this energy. Then, every years is calculated the energy balance by the bidirectional meter, and, if it is positive, it represents a credit usable in the following years if the energy balance will be negative.

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kWh

kWh

Meter

(measure of all the energy produced by PV)

Load PV system

Figure 2.2.21 - Layout connection of the PV system

2.2.2.2 PV system size from 20 to 50 kWp -

Al the energy produced is remunerated 0.46 €/kWh At the end of the years, if the production has been bigger than the consumption, this energy is remunerated as explained in Table 2.2.3. Table 2.2.3 - Energy prices Production [kWh]

€/kWh

Until 500000

0.095

From 5000000 to 1000000

0.08

From 1000000 to 2000000

0.07

2.2.2.3 PV system size from 50 to 1000 kWp -

-

All the energy is remunerated by with value determined from an offers process. When the request for the financing is done, it has also to be done one propose for the remuneration of the energy. The maximum value is fixed to 0.49€/kWh. Lower proposes has more possibilities to be accepted. At the end of the years, if the production has been bigger than the consumption, this energy is remunerated as explained in Table 2.2.3.

The financing will be released for 20 years, but all the reported remuneration energy tariffs are valid only for the requests that are done during the year 2006. Since year 2007, every year, 2% of reduction is done to every remuneration tariffs.

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2.2.2.4 Economical evaluation In this scenario it is possible to do a rough economical evaluation based on these hypotheses: -

50 kWp PV system installed in the year 2006 Installation cost : 6700 €/kWp Discount rate: 5% Average energy prices

With these conditions the payback time is situated between the tenth and the eleventh years like showed in Figure 2.2.22. 200000 100000

Van [€]

0 -100000 -200000 -300000 -400000 0

2

4

6

8

10

12

14

16

18

20

Years

Figure 2.2.22 - Payback time period of a 50 kWp PV system

2.2.3

Concepts for integration with other technologies and into networks

The photovoltaic systems are a not programmable energy sources because, of course they are dependent from the solar irradiation. This implies that they have to be always integrated with other technologies. The stand-alone PV systems, like already said, are integrated by an electrochemical accumulator that covers the energy deficit and absorbs the energy surplus. In this case the only prevention measure is to install the charge regulator. For the grid-connected PV systems instead, we have to spend some word about the parallel with the network. The Italian standards say that if a distributed generation unit causes a perturbation to the public electrical network, it has to be disconnected automatically and immediately. This means that there will be a control device that will make the disconnection if a perturbation will occur (interface block in Figure 2.2.17). The interface device is equipped usually with the following relays: • • • •

under voltage relay: over voltage relay: under frequency relay: over frequency relay:

threshold 0.8 Un threshold : 1.2 Un threshold: 49.7 or 49 Hz threshold: 50.3 or 51 Hz

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In some cases the interface device is equipped also with a relays that measure frequency derivative and a monitoring system of the network impedance. Usually this device is seen as the islanding protection but really it preserves also the PV systems from the possible external over voltage. The over/under frequency relays are the more important characteristics of the device, in fact the interface intervention is usually dictate from them. The functioning of the over/under voltage relays is easy to understand, on the contrary the functioning of the over/under frequency relays needs an ulterior explanation. During the parallel configuration the PV system inverters are bound to work at the network voltage level, which is a waveform with constant frequency. Instead, when there isn’t the parallel with the network, the inverter supplies a current depending on the irradiance, so the voltage is depending on both current and load. ( U = Z ⋅ I ). A typical voltage waveform without the parallel with the network is shown in Figure 2.2.23. 400

Voltage [V]

200

0

f > 50 Hz -200

-400 0.01

0.015

0.02

0.025

0.03

0.035

0.04

0.045

0.05

Time [s]

Figure 2.2.23 - Voltage waveform in islanding configuration This is a voltage measured during a check of the interface device intervention time. It is possible to se that, due to the conversion of the inverter, near the zero crossing the waveform has some discontinuities that cause the frequency variation.

2.2.4

Socio-economic aspects

In opposition with the techno-economic aspects, the socio-economic aspects are the strong point of the photovoltaic systems. In fact most of the time there aren’t problems of acceptance because the renewable sources have an almost null environmental impact. The PV systems can be considered the renewable source with more respect for the environment, in fact they make a static conversion of the energy, they don’t generate pollutant emission and thanks to their modularity they are adaptable to every kind of installation site morphology. Although this are good points, the photovoltaic system environmental impact are not null. The problems that can influence the acceptance of the PV systems can be summarised in: -

pollution deriving from the productive process, utilization of the territory, visual impact, impact on local climate, flora and fauna.

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The first point is more relevant now than in the past, when most of the necessary silicon for the solar cell production was derived from the electronic factory rejections. In these days the photovoltaic market is growing, so it is necessary a solar cell productive process bigger than some years ago. Instead the other three points are relevant only for the PV systems plants, which require a considerable extension of area to supply a significant contribute. Sometimes esthetical reasons have been the cause of the refusal of a PV system plant. The visual impact depends on the plant dimensions; it has related to from the PV system surface orientation respect with the possible observation points. The visual impact can be reducer respecting some minimum distance from the inhabited centre, from roads, etc; or shielding the observation points with some trees or other obstacle paying attention to avoid the shading of the PV system. Therefore also the technologies with a low environmental impact can come up against some difficulties about acceptance. So, especially for the PV system plant, it is necessary also an environmental analysis during the design step.

2.2.5

Design, simulation and optimisation tools

The PV system design is a not easy argument. The design step is strongly dependent from the PV system typology. Therefore we will see only some important points that will allow to understand the problems of the design step of the grid-connected PV systems.

2.2.5.1 Optimal module orientation The module orientation is defined by two angles: - module inclination (β), Figure 2.2.24.A - Azimuth angle (Ψ), Figure 2.2.24.B

Module orientation

β

W

Ψ S

N

E A)

B)

Figure 2.2.24 - Module orientation The best tilt angle is variable depending on the application. Generally, low tilt angle are used where is important to maximise PV system performances in summer months, on the contrary, high tilt angle are used in application where is important to maximise PV system performances in winter months. For PV systems grid-connected the most important goal is the maximisation of the energy generated during one year. The value of this angle is derivable looking at Figure 2.2.25 and Figure 2.2.26. In a site with latitude φ the module inclination that makes perpendicular the solar rays direction respect to the module inclination is equal to the latitude. This is only an approximate result

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because really the terrestrial axis is not perpendicular with the plane that contains the earth motion. Azimuth angle is a coordinate used in the study of planets motion. For our application best azimuth angle is zero degrees, this value is due to the sun motion.

terrestrial axis

Solar rays

Solar rays

π 2

φ equatorial plane

φ

Figure 2.2.25 – Latitude influence on the irradiation

Figure 2.2.26 – Optimal inclination

2.2.5.2 Shading effect This is a very important step of the PV system design. A deep study of this point can be done only with a simulation software because there are too many variables that have to be considered. Therefore we will suggest only an approximate method to calculate the minimal distances for PV systems on a plane surface and for PV system on façade. In some condition a string of modules can project its shadow on another sting. To avoid this negative condition it is necessary to respect some minimum distances: •

With reference to Figure 2.2.27, it is possible to derive the minimal distance between two strings for a PV system on a plane surface:

D ≥ L cos β +

β

Lsenβ tgα

α

Figure 2.2.27 – Minimal distance for a PV system on a plane surface

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With reference to Figure 2.2.28, it is possible to derive the minimal distance between two strings for a PV system on façade:

D ≥ Lsenβ +

L cos β π  tg  − α  2  

β

π 2

α

α

Figure 2.2.28 - Minimal distance for a PV system on façade

2.2.5.3 Electrical layout The electrical layout of a PV system is another point that is dependent from the situation considered. Therefore we will examine some different solutions emphasizing their propriety. In Figure 2.2.29 there are shown some possible electrical layouts.

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AC modules Central inverter

DC

DC AC

Network

DC

DC

AC

DC AC

AC

DC AC

DC

DC AC

AC

DC AC

Network

DC AC

AC

Multi string inverter MPP1 DC

String inverter

DC DC AC DC

Network

AC

MPP2 Network

DC

DC

DC AC

DC

AC

MPP3 DC DC

Figure 2.2.29 - PV systems configurations The Central inverter configuration consists in a field of modules all connected to the same inverter. The PV system efficiency is related to the inverter performance on high/low output power conditions. The Master-Slave configuration has the same electrical layout of the central inverter configuration, but the inverter is composed by more that one inverter in parallel configuration. These inverter can be turned on or off with reference to the output power condition. In this configuration the working inverter are always used near their nominal power achieving an high DC/AC conversion yield. The String inverter configuration uses an inverter for each string of the PV system. This configuration is made to minimize the mismatching losses; in fact every string can work near its MPP. In the AC modules configuration is used an inverter for every module. With this solution there aren’t mismatching losses but there are more AC losses and the maintenance is more onerous. Therefore this configuration is suitable only for PV systems with a small size. The multi string inverter configuration can be used when the PV system is composed by strings with different orientation. Every string can be connected to the same inverter through a dedicated DC/DC converter that allows to the string the reaching of its MPP.

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2.2.5.4 Conclusion Like already said, the design step is strongly dependent from many factors (available spaces, environment configuration near the PV systems, etc…). This implies that to deign a PV system with good performance, it is better to use some simulation software; especially to avoid and optimise the PV system configuration in relation to the shadowing problems.

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Biomass technologies (CREVER)

Biomass can provide thermal, electrical and mechanical energy services. Heat/steam is often given lowest value relative to electricity and transportation. Highest overall efficiency is often a result of capturing more than one service e.g. in combined heat and power plants. Table 2.3.1 and figure 2.3.1 shows the main processes of biofuels obtained from biomass.

Table 2.3.1 - Routes for converting biomass into energy products and services [1] Biomass Resources Processes Agriculture and Densification forestry residues Esterification Energy crops: Combustion biomass, sugar, oil Gasification Pyrolysis Fermentation/ Distillation Biomass processing Digestion wastes Hydrolysis Municipal Waste

Digestion Combustion Gasification

Biofuels Wood pellets Briquettes Biodiesel Char/Charcoal Fuel gas Bio-oil Bioethanol

Energy Services Heat Electricity Transport Heat Electricity Transport

Biogas Bioethanol Solvents Refuse-derived (RDF) Biogas

Transport

fuel Heat Electricity

Biomass (Energy Plants, Residues, Side Products, Waste) Raw Material Use Fossil Fuels

Thermochemical Conversion Co-firing

Direct Combustion

Carbonisation

Physic. – Chem. Conversion

Gasification

Pyrolysis

Synthesis

Pyrolysis

Gas

Oil

Transesterification

Charcoal

Biodiesel

Biochemical Conversion AlcoholFerment.

Ethanol

Anaerobic Degradat

Anaerobic Degradat

Biogas

Compost

Burning/Combustion

Cold

Heat

Electricity

Figure 2.3.1 - Biomass Conversion Processes into Energy

Mobility

2.3.1

Analysis of Technical Aspects

2.3.1.1 Combustion of biomass Biomass combustion can burn many types of biomass fuel, including wood, agricultural residues, wood pulping liquor, municipal solid waste (MSW) and refuse-derived fuel. Combustion technologies convert biomass fuels using thermochemical and biochemical conversion into several forms of useful energy for commercial or industrial uses; hot air, hot water, steam and electricity. Combustion is the most developed and most frequently applied process use for solid biomass fuels because of its low costs and high reliability. However, combustion technologies deserve continuous attention from developers in order to remain competitive with the other options. The direct combustion involves the biomass oxidation with excess air, producing hot flue gases, which in turn produce steam in the heat exchange sections of boilers. A biomass-fired boiler is a more adaptable direct combustion technology because a boiler transfers the heat of combustion into steam. Steam can be used for electricity, mechanical energy or heat. The steam used to generate electricity in a Rankine cycle. A boiler´s steam output contains 60 to 85 percent of the potential energy in biomass fuel. The major types of biomass combustion boilers are pile burners, stationary or traveling grate combustors and fluidized-bed combustors. Figure 2.3.2 shows a diagram shows a direct fired biomass system to produce electricity.

Figure 2.3.2 - Direct fired biomass electricity generating system schematic. [4]

The direct-fired technologies are described next: •

Pile Burners: Consist of cells, each having an upper and a lower combustion chamber and is typically used for wood combustion. It is a two-stage combustion chamber with a separate furnace and boiler located above the secondary combustion chamber [3]. This is separated into a lower pile section for primary combustion and an upper secondary combustion section. Biomass fuel burns on a grate in the lower chamber, releasing volatile gases. The gases burn in the upper (secondary) combustion chamber. Operators must shut down pile burners periodically to remove

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ash. The advantage of the pile burner of the pile burner is its simplicity and ability to handle wet, dirty fuels. Pile burners typically have low efficiencies (50% to 60%), have cyclic operating characteristics because of the ash removal and have combustion cycles that are erratic and difficult control. Because of the slow response time of the system and cyclic nature of operation, pile burners are not considered for load following operations. Although capable of handling high-moisture fuels and fuels mixed with dirt, pile burners have become obsolete with the development of more efficient combustion designs with automated ash removal systems [5]. •

Stocker Combustors: In this type of technology it is provided a moving grate which permits continuos ash collection, thus eliminating the cyclic operation characteristic of traditional pile burners. In addition, the fuel is spread more evenly, normally by a pneumatic stocker and in a thinner layer in the combustion zone, giving more efficient combustion. In the basic design, the bottom of the furnace is a moving grate which is cooled by underfire air that defines the maximum temperature of the grate an thus the allowable feed moisture content.

•

Fluidized bed: A stream of gas passes upward through a bed of free flowing granular materials. The gas velocity is high enough that the solid particles are widely separated and circulate freely, creating a “fluidized bed” that looks like a boiling liquid and has physical properties of a fluid. During circulation of the bed, transient streams of gas flow upwards in channels containing few solids and clumps or masses of solids flow downwards. In fluidized bed combustion biomass, the gas is air and the bed is usually sand or limestone. The air acts both as the fluidizing medium and as the oxidant for the biomass combustion. A fluidized bed combustor is a vessel with dimensions such that the superficial velocity of the gas maintains the bed in a fluidized condition at the bottom of the vessel. The cross sectional area changes above the bed and lowers the superficial gas velocity below fluidization velocity to maintain bed inventory and act as a disengaging zone. Overfire air is normally introduced in the disengaging zone. To obtain the total desired gas phase residence time for complete the combustion and heat transfer to the boiler walls, the larger cross sectional area zone is extended and is usually referred to as the freeboard. A cyclone is used to either return fine to the bed or to move ash rich fines from the system. The bed is fluidized by a gas distribution manifold or series of sparge tubes. If the air flow of a bubbling fluid bed is increased, the air bubbles become larger, forming large voids in the bed and entraining substantial amounts of solids. This type of bed is referred to as turbulent fluid bed [7]. In a circulating fluid bed, the turbulent bed solids are collected, separated from the gas and returned to the bed, forming a solids circulation loop. A circulating fluid bed can be differentiated form a bubbling fluid bed in that there is no distinct separation between the dense solids zone and the dilute solids zone. The residence time of the solids in a circulating fluid bed is determined by the solids circulation rate, the attritibility of the solids and the collection efficiency of the solids separation device [4]. Due to the good mixing achieved, fuel flexibility is high, although attention must be paid to particle size and impurities contained in the fuel. Fluid bed combustion plants usually operated at full load. Low NOx emissions can be achieved by good air-staging, good mixing, and a low requirement for excess air. Moreover, additives (e.g. limestone for sulphur removal) work well due to the good mixing conditions. The low excess amount required reduces the flue gas volume flow and increase combustion efficiency. This design increases heat transfer and allows for operating temperatures below 930°C, reducing nitrogen oxide (NOx) emissions. Fluidized-bed combustors can handle high-ash fuels and agricultural biomass residue [5].

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Biomass combustion facilities that produce electricity from steam-driven turbine-generators have a conversion efficiency of 17 to 25 percent. Using a boiler to produce both heat and electricity (cogeneration) improves overall system efficiency to as much as 85 percent. That is, cogeneration converts 85 percent of the fuel’s potential energy into useful energy in two forms: electricity and steam heat. Two cogeneration arrangements, or cycles, are possible for combining electric power generation with industrial steam production. Steam can be used in an industrial process first and then routed through a turbine or engine to generate electricity. This arrangement is called a bottom cycle. In the alternate arrangement, steam from the boiler passes first through a turbine to produce electric power. The steam exhaust from the turbine is then used for industrial processes or for space and water heating. This arrangement is called a topping cycle. Of the two-cogeneration arrangements, the topping cycle is more common. [5] Small-scale steam turbines are usually built with a single expansion stage or few expansion stages, and operated at quite low steam parameters as a result of the application of firetube boilers. Plants smaller than 1 MWe are usually operated as backpressure CHP plants and aim for electricity net efficiencies of typically 10% - 12%. The backpressure heat can be used as process heat. Steam piston engines can also be used for small-scale applications, enabling efficiencies of 6% - 10% in single-stage and 12% - 20% in multi-stage mode. Steam engines are relatively robust – even saturated steam can be used. Another technology for small-scale biomass power production is the externally fired Stirling engine. For large steam turbine plants, water tube boilers and superheathers are employed, thus enabling high steam parameters and use of multi-stage turbines. Furthermore, process measures such as feed water preheating and intermediate tapping are implemented for efficiency improvement. This result in electricity efficiencies of around 25% in plants of 5 –10 MWe. In plants around 50 MWe and larger, up to more than 30% is possible in cogeneration mode and up more than 40% if operated as condensing plant. As alternative to conventional steam plants in range 0,5 MW to 2 MW, Organic Rankine Cycles (ORC) using a thermal oil boiler instead of a costly steam boiler are also available, enabling operation at lower temperatures. ORC plants can be operated without a superheater due to the fact that expansion of the saturated steam of the organic medium leads to dry steam [6]. The direct-fired gas turbine is another combustion technology for converting biomass to electricity. In this technology, fuel pretreatment reduces biomass to a particle size of less than 2 millimetres and a moisture content of less than 25 percent. Then the fuel is burned with compressed air. Cleanup of the combustion gas reduces particulate matter before the gas expands through the turbine stage. The turbine drives a generator to produce electricity [5]. Design Biomass designs include reheat and regenerative steam cycles as well as supercritical steam turbines. The two common boiler configurations used for steam generation with biomass are stationary and traveling grate combustors (stokers) and atmospheric fluid bed combustors. All biomass combustion systems required feedstock storage and handling systems. Conventional combustion equipment is not designed for burning agricultural residues. Straws and grasses contain potassium and sodium compounds. These compounds (called alkali) are present in all annual crops and crop residues and in the annual growth of trees and plants. During combustion, alkali combines with silica, which is also present in agricultural residues. This reaction causes slagging and fouling problems in conventional combustion equipment designed for burning wood at higher temperatures.

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Volatile alkali lowers the fusion temperature of ash. In conventional combustion equipment having furnace gas exit temperatures above 790°C, combustion of agricultural residue causes slagging and deposits on heat transfer surfaces. Specially designed boilers with lower furnace exit temperatures could reduce slagging and fouling from combustion of these fuels. Low-temperature gasification may be another method of using these fuels for efficient energy production while avoiding the slagging and fouling problems encountered in direct combustion [5].

2.3.1.2 Co-combustion Co-combustion is a simultaneous combustion of different fuels in the same boiler. Co-firing is a fuel substitution option for existing capacity, and is not a capacity expansion option. The biomass cofiring consists in the substitution of a partial part of the habitual fossil fuel, between 2% to 20% of energy, by biomass. In different types of boilers including pulverized coal boilers, cyclones stokers and bubbling and circulating fluidized beds. The implantation of this long term technology takes to certain associate technical problems (had mainly to the type of used fuel or incorrect selection of the feeding point), as they can be the increase of the problems by fouling and corrosion, yield lost, ashes composition change or bad operation in the gases clean system (electrostatic precipitation, desulphurisation, etc.). The co-fired is applicable to all the types of boilers that traditionally use fossil fuels although, each type requires a different adaptation technology. When a boiler habitually uses coal exclusive, the fuel change does not have substantially to make worse the yield of the same one. For that reason in this type of boilers, it is necessary to put under the biomass to a series of pre-treatment with the intention of reaching requirements similar in particle size and the humidity content, although less restrictive than those of the fossil fuel. In the case of the biomass, the greater content in volatile and oxygen, causes that this is much reactive than the coal, reason why for the same time of residence the size of particle can be greater (the biomass is introduced generally between 1-8 mm). The following picture (figure 2.3.3) shows a co-firing system with a pulverised coal boiler.

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Figure 2.3.3 - Biomass co-firing retrofit schematic for a pulverised coal boiler system [4] Efficiency There is a little or no loss in total boiler efficiency after adjusting combustion output for the new fuel mixture. This implies that biomass combustion efficiency to electricity would be close to 33%-37% when co-fired with coal. Biomass energy can provide as much as 15% of the total energy input with only feed intake system and burner modifications [9]. Design The biomass fuels usually considered range from woody to grassy and straw-derived materials and include both residues and energy crops. The fuel properties differ significantly from those of coal and also show significantly greater variation as a class. Other properties of biomass which differ from those of coal are generally high moisture content, potentially high chlorine content, relatively low heating value, and low bulk density. These properties affect design, operation, and performance of cofiring systems [6]. There are two technologies in the biomass co-firing, the direct co-firing and the indirect co-firing. In the direct co-firing both fuels are fed in the same boiler without undergoing any previous chemical transformation. Different forms exist to feed the fuel, being limited, in each one of them, as the percentage of substitution as the rank in which it can vary the size of particle to obtain a correct operation of the plant. There are two ways to feed the biomass. The first one is feeding the biomass with fossil fuel (both combustible they are mixed previously and they are introduced jointly in the boiler) and in the second one the biomass introduces in the independent boiler the coal (both fuels are feed separate but they react jointly in the boiler). In the case of the fuels that are mixed previously, the mixture can become before the mills, for that reason there is not necessary a biomass although the percentage of substitution its limited around 2% in energy to avoid the appearance of problems in the coal mills. If the mixture is made after them, the

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percentage of substitution comes determined by the transport capacity of the existing system, since the power density of the biomass is much smaller than the coal and for the same load greater volumetric flow of biofuel is necessary. When the biomass is introduce in the boiler, independent of the coal, the percentage of substitution increases, varying between 5 - 20% in energy. In the case of the indirect combustion the biomass is transformed previously independently of the coal in an external equipment of combustion or gasifier, and later the products generated with each one of the processes and fuels is handled of jointly. Of this form, the possible problems that could appear in the boiler are reduced for the use of a different design fuel (loss of yield, increase of the corrosion, increase of the fouling, etc.). In the other hand, this option allows to work with greater percentages of substitution and to use biomass that could not be transformed correctly into a powdered fuel boiler if they were fed directly [10].

2.3.1.3 Biogas Anaerobic digestion is a method of treating the organic fraction organic wastes, including municipal solid waste (MSW). Anaerobic bacteria convert the biomass into a biogas or landfill gas that can be use to generate energy. In the absence of oxygen, anaerobic bacteria will ferment biodegradable matter into methane and carbon dioxide, a mixture called biogas. Approximately 90% of the energy from the degraded biomass is retained in the form of methane. Hence, very little excess sludge is produced. Biogas is formed solely through the activity of bacteria. The anaerobic degradation can take place over a wide temperature range from 10ºC to over 100ºC and at a variety of moisture contents from around 50% to more than 99%. Biogas produced in anaerobic digestion plants or landfill sites is primarily composed of methane (CH4) and carbon dioxide (CO2) with smaller amounts of hydrogen sulphide (H2S) and ammonia (NH3). Trace amounts of hydrogen (H2), nitrogen (N2), carbon monoxide (CO), saturated or halogenated carbohydrates, oxygen, and siloxanes are occasionally present in the biogas. Usually, the mixed gas is saturated with water vapour. Farm scale digestion plants treating primarily wastes have seen widespread use throughout the world, with plants in developing and technically advanced countries. In rural communities small-scale units are typical and these plants are generally used for providing gas for cooking and lighting for a single household. In more developed countries, farm-scale are generally larger and the gas is used to generate heat and electricity. These plants are simple stirred tank designs that use long retention times to provide the treatment required. Two designs are prevailing throughout Europe: the so-called rubber top digester and the concrete top digester usually built in the ground. Both have a cylindrical form with a height to diameter ratio of 1:3 to 1:4. They are intermittently mixed tank reactors with hydraulic retention time (HRT) of the waste in the digester of 15 to 50 days. The longer HRT applies where an energy crop is used as a co-substrate or even the only source of energy. There are digesters with a single and double membrane cover. The advantage of the rubber top digester is the price. A membrane is cheaper than a concrete cover. At the same time, the membrane serves as gas storage whereas concrete top digesters need additional gas storage. On the other hand, the latter are easy to insulate and can take high snow loads offering clear advantages in mountain areas. Often the rubber top digesters give problems of odour emission when the rubber (usually lack9 is inflated due to heating by the sun.

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Quite commonly, the manure is collected in a feed tank where other soluble substrates can be added such as distillery, and potato slops, whey, etc. Provided the feed tank is equipped with a strong macerator, solid substrates can also be added. However, the limitation is the pumping capacity, which usually ends at a dry matter content of around 12%. In newer plants the solid material is added directly to the digester either with screw feeders from the top or by piston pumps below the liquid level in the digester. Figure 2.3.4 shows a diagram of a typical biodigester with membrane.

Figure 2.3.4 - Digester with a rubber membrane cover which serves at the same time as gas storage. [2] In large-scale biogas production exists the concept where many farms cooperate to feed a single larger digestion plant, called Centralised Anaerobic Digestion (CAD). The wastes provided are principally agricultural manure and biogenic waste materials from industry, but some cases small amounts of industrial and municipal wastes are also treated. There are significant benefits from using these cooperative arrangements in the terms of nutrient management and economics, but these does required that barriers of confidence in quality control and sanitation are overcome. Today, CAD has become a standard technology, which is used in most European countries as well as in Asia and the USA. There are two major drivers, which helped to promote co-digestion: • •

Digesters in waste treatment plants are usually oversized. Addition of co-substrates helps to produce more gas and consequently more electricity at only marginal additional cost. The extra electricity produced covers the energy needs of waste water treatment at a reasonable cost. Agricultural biogas production from manure alone (which a relatively low gas yield) is economically not viable at current oil prices. Addition of co-substrates with a high methane potential not only increases gas yields but above all increases the income through tipping fees.

Generally co-digestion is applied in wet single-step processes such as intermittently stirred tank reactors. The substrate is normally diluted o dry solid contents of around 8 to 15%. Wet systems are particularly useful when the digestate can be directly applied on fields and green lands without the separation of solids. The merits of CAD are: • •

Improved nutrient balance for optimal digestion and good fertilizer quality. Homogenization of particulate, floating or setting wastes through mixing with animal manure or sewage sludge.

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Increased, steady biogas productions throughout the seasons. Higher income from gate fees for waste treatment. Additional fertilizer (soil conditioner)

In CHP the biogas is commonly used in internal combustion engines. A diesel engine can be rebuilt into a spark-ignited gas engine or a dual fuel engine where approximately 8-10% diesel is injected for ignition. In recent years new engines types have been developed such as hot fuel cells or micro turbines. Hot fuel cells have the potential to reach electric efficiencies of close to 50%. Molten carbonate (MCFC) or solid oxide fuel cells (SOFC) do no required CO2 to be removed from the raw gas.

2.3.1.4 LANDFILL GAS Description Landfill gas (LFG) is produced by the anaerobic decomposition of organic waste in a landfill. Organic waste include food waste, paper, wood, yard waste, and organic sludge. Municipal solid waste contains a relatively large organic waste fraction. Industrial wastes, and therefore industrial landfills, generally contain much smaller fractions of organic waste. LFG collection, control and utilisation are, as a consequence, focused almost exclusively on municipal solid waste landfills. LFG production begins shortly after waste is buried in a landfill and LFG will continue to be produced as long as organic waste is present. The decline in LFG production is gradual. In a dry climate, the rate of production will decline as little 2 percent per year. Moisture is a significant factor in the rate of LFG production. Landfills are designed to prevent the entry of water both during and after their active life; however, when the landfill is active, some water is inevitably added. The amount of water added is directly related to the precipitation in the region. LFG production can generally be correlated to the amount of annual precipitation in a region. The most important factors affecting the amount of LFG produced from a fixed quantity of waste at any point in time are: • • •

The quantity of waste (tons) Its age (in years) The annual precipitation at the landfill (in inches/cm3)

While moisture is an important variable governing variations in LFG production, other factors play a role, including waste temperature, pH and availability of nutrients. The bioreactor incorporates a series of cells of waste in which the principal parameters affecting waste decomposition are controlled with the intent of maintaining optimum conditions for waste degradation. There are several benefits from bioreators, including quicker production of additional air space to support higher waste disposal per surface area, and quicker stabilization of waste. The later benefit would reduce long-term, post-closure maintenance costs of a landfill. The addition of liquid and its recirculation are common features of most bioreactors projects. The increased rate of waste degradation associated with bioreactors will increase the rate of LFG production. In conventional landfills, it is assumed that the total amount of LFG produced by a given mass of waste is a fixed value. The fixed value is known as the ultimate generation rate, and expressed as m3/mg. LFG beneficial use can be grouped into three categories as follows: •

Medium-Btu Gas Production (sometimes called “Direct Use”)

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Electric Power Generation Pipeline Quality Gas Production (sometimes called “High-Btu Gas Production)

Medium-Btu gas utilisation is a concept through which the LFG is given minimal cleanup and is used to completely or partially displace a fossil fuel in boilers (commercial, institutional and industrial), furnaces and kilns. Co-firing of LFG with fossil fuel in conventional power plants is typically considered to be a medium-Btu LFG application, even though electric power is being produced. High-Btu gas production involves extensive cleanup of the LFG to a level of quality so that it can be introduced into existing pipelines as a direct substitute for natural gas. High-Btu gas can also be compressed or liquefied and be used for vehicle fuel. Technologies currently in use for production of high-Btu gas include the membrane process, the solvent absorption process, and the molecular sieve process. Technologies Electric power can be generated through the application of: • • • • •

Reciprocating engines Combustion turbines Steam cycle power plants Emerging technologies including microturbines, fuel cells and Stirling engines Co-firing of LFG whit fossil fuels in conventional electric power plants.

Reciprocating Engines: These are the most widely used prime movers for LFG-fired electric power generation. The capacity of individual engines proven in LFG service varies from 0,1 MW to 3,0 MW the principal advantage compared to the other power generation technologies is a better heat rate al lower capacities. An additional advantage of reciprocating engines is that the units are available in many different incremental capacities, which makes it easy to tailor the size of small plants to the specific rate of gas production at a landfill. Most LFG power plants employ reciprocating engines. Reciprocating engines generally required a relatively simple LFG pretreatment process consisting of compression and removal of tree moisture. Free moisture (water droplets) is removed by use of simple moisture separators (knockout drums), cooling of the LFG in ambient air-to-LFG heat exchangers, and coalescing-type filters. Moisture removal also removes particles; however, LFG is generally fairly particulate free. Engine manufactures place restrictions on the amount of sulphur bearing compounds and the total organic halide content which they will tolerate in the LFG. Combustion Turbines: Combustion turbines have seen widespread use as prime movers in LFG-fired electric power generation. The principal advantages of the combustion turbine as compared to a reciprocating engine are its lower air emissions and lower operation/maintenance costs. The principal drawback to the combustion turbine is its high net heat rate. The poor net heat rate owes itself to two factors. First, the station power for a combustion turbine based plant is about 15 percent of gross power output as compared to about 7 percent for a reciprocating engine-based plant. The combustion turbines require a much higher pressure, which increases the lower consumption of the fuel gas compressors. Second, the combustion turbines used in LFG electric power production are small, and are not as efficient as the larger units commonly employed in the electric power industry. Particulate in the LFG has sometimes caused problems with the combustion turbine’s fuel injection nozzles. A small water wash scrubber is normally provided in the pretreatment process to prevent this problem. Steam Cycle Power Plants: Conventional boilers with steam turbines seen limited application in LFGfired electric power production. It is believed that eight steam cycle power plants are operating on LFG worldwide. Most LFG-fired power plants are less than 10 MW in capacity, which puts the steam

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cycle at a cost disadvantage when compared against reciprocating engines and combustion turbines. The steam cycle power plant becomes more cost competitive as the size of the plant increases. The steam cycle power plant offers lower air emissions than either reciprocating engines or combustion turbines. As a consequence, steam cycles have been given preferential treatment in regions with stringent air quality regulations, even when the size of the plant was relatively small. LFG requires no pretreatment prior to firing in a conventional boiler. LFG is normally taken from the discharge side of the LFG blowers in the landfill’s flare station. Large water droplets and particulates have already been removed in the flare station’s moisture separator. Fuel Cells: The fuel cell is considered an opportunity for LFG utilisation since it contains methane, the feedstock for stationary fuel cell applications. There have been two relatively short-tern but successful fuel cell demonstration tests to date. There is one commercially operating unit. Fuel cells are nevertheless attractive to the LFG utilisation industry because: (1) they are available in small incremental capacities (making them applicable to projects smaller than possible with other power generation technologies; (2) they produce almost zero emissions of criteria pollutants and produce little noise; LFG cleanup system is an important issue and it would include: • • •

An adsorber for hydrogen sulphide removal Chilling and desiccation 8 to remove moisture and some hydrocarbons) Activated carbon to adsorb remaining trace organics.

Microturbines: typical LFG fired microturbine installation would have the following components: • • • • • •

LFG compresor(s) LFG pretreatment equipment Microturbine(s) Motor control center Switchgear Step-up transformer

Microturbines can operate on LFG with a methane content of 35 percent (and perhaps as low as 30 percent). Microturbines can be used at small landfills and at old landfills where LFG quality and quantity would not support more traditional LFG electric power generation technologies. Design The principal components of a LFG collection system are its extraction wells, the LFG collection piping (which allows the LFG to be drawn to a central location), and a blower/flare station (which contains vacuum blowers to pull the LFG to the blower/flare station and flare to burn the LFG) The extraction wells can consist of a horizontal wells (known as trench collectors or horizontal collectors) or vertical wells. Horizontal wells can only be installed as waste is being placed. Vertical wells can be installed as waste is being placed or after a section of a landfill (or an entire landfill) is closed. The LFG collection piping can be buried, laid on the surface or placed on pipe supports [15].

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2.3.1.5 GASIFICATION Description Gasification is a generic term under whose denomination all the processes in which an incomplete combustion with oxygen defect takes place and where the following gases are produced (monoxide of carbon, carbon dioxide, hydrogen, methane and hydrocarbons of small chain), in diverse proportions according to the composition of the raw material and the conditions of the process. The gasification process is one of the thermochemical conversions that can be used to transform the chemical energy contained in a solid fuel into thermal energy and electricity. The gasification process takes place at around 800-1000°C and needs a moderate supply of oxidant, less than required for a combustion process. The fuel, containing carbon, will react with the oxidant inside the gasification reactor and produce a gas that contains CO and H2 and therefore, a fuel gas and the remainders (ash) that reach values between 4 % and 12 % according to the used biomass. These remainder by-products are usable for different uses. In any case they can be put in landfills because his character of inert. The gas obtained, is a relatively clean gas that will require treatment or not, according to the use that will have. Possible uses of the gas: reagent in chemical processes and fuel in power processes such as boiler of gas, gas engine, gas turbine or steam generator.[3] The biomass gasification generally involves two processes. The first process, pyrolysis, releases the volatile components of the fuel at temperatures below 600ºC via a set a complex reactions. Included in these volatile vapours are hydrocarbon gases, hydrogen, carbon monoxide, carbon dioxide, tars and water vapour. Because biomass fuels tend to have more volatile components (70-86% on dry basis) than coal (30%), pyrolysis plays a proportionally larger role in biomass gasification than in coal gasification. The by-products of pyrolysis that are not vaporised are referred to as char and consist mainly of fixed carbon and ash. In the second gasification process, char conversion, the carbon remaining after pyrolysis undergoes the classic gasification reaction (i.e. steam + carbon) and/or combustion (carbon + oxygen). It is this latter combustion reaction that provides the heat energy required to drive the pyrolysis and char gasification reactions. Due to its high reactivity (as compared to coal and other solid fuels), all the biomass feed, including char, is normally converted to gasification products in a single pass through a gasifier system. [4] The following reactions are generated in the partial oxidation of gasification process: [14] C + H2O ↔ CO + H2 C + 2 H2 ↔ CH4 C + CO2 ↔ 2CO 2C + O2 ↔ 2CO2 CO + H2O ↔ CO2 + H2 CO + 3H2 ↔ CH4 + H2O In Cogeneration Plants where use gas from biomass, first of all occurs a cleaning treatment and cooling of the gas then, the gas is used like fuel in a gas engine, the engine fixed to the alternator by the axis produces electrical energy and the exhaust gases. These plants can eliminate biomass between 5.000 and 15.000 ton/year based on the moisture of the biomass, producing electrical energy between 600 and 1.200 KWe. In addition they provide a calorific energy whose good advantage allows power high performances. They are simple plants very automated and that require very little personal for their attention.

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Gasifiers Types: Fixed-bed: The different fixed-bed reactor types are often characterised by the direction of the gasflow through the reactor (upward, downward or horizontal) or by the direction of respectively the solid flow and the gas stream (co-current, counter-current or cross-current). For specific feedstocks a co-current gasifier is used with the advantage that the tar content in the producer gas is low. Additional gas cleaning -prior to fuelling a prime mover- is avoided. [3] • • • • •

Descending Flow: Both the solid and the gas have descendent flow. Gasifier in co-flow (downward). Ascending Flow: The solid flows in descendent direction and the gas in ascendant direction. Gasifier in contra-flow (upward). Co-flow: the solid and the gas go in the same direction. Counter-flow: The solid and the gas go in opposite directions . It is possible to have the opposite configurations that the upward. Crossed Flow: the solid has descendent flow and the gas goes perpendicular to the solid. [14]

Fluidized-bed: In a fluidized bed gasifier air and biomass are mixed up in a hot bed of solid material. Due to the intense mixing the different zones -drying, pyrolysis, oxidation, reduction- can not be distinguished; the temperature is uniform throughout the bed. Contrary to fixed bed gasifiers the airbiomass ratio can be changed, and as a result the bed temperature can be controlled. The producer gas will always contain certain amounts of tar, which need to be removed [3]. • • • •

Bubbling Bed: The gas has low speed. The inert solids (e.g. sand) remain within the reactor. Circulating bed: The inert solid is dragged by the gas flow. Out of the reactor is separated of the gas and it is given back to the reactor. Dragged Bed: Normally is not use inert solids. The gas speed is too high, for that reason the reaction speeds are very high. Double Reactor: The gasification with vapour and/or pyrolysis take place in the first fluidized-bed reactor. The coal produced along with the inert solid are dragged with the pyrolysis gas, then are separated and feed in the second reactor. The coal is burned with air and the inert solid is warmed and then recirculated to the first reactor.

Other gasifiers types are Rotatory Furnace where the contact between gas-liquid is very good; and the Cyclonal Reactors where high reaction speeds are obtained due the high speed of particle and by the effect of abrasion with the cyclone walls [14]. Figure 2.3.5 summarises the main gasifiers types and their typical operating ranges.

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Figure 2.3.5 - Gasifier Types [3]

Biomass gasification techniques can be connected to gas fired engines, gas turbines or fuel cells. Figure 2.3.6 summarises the products of gasification with the technologies process that are used.

GAS (MHV)

Gasification GAS (LHV)

TECHNOLOGY PROCESS

FINAL PRODUCTS

Turbine

Gasoline, diesel, etc.

Synthesis

Methanol

Engine

Fuel Alcohol

Boiler

Electricity

WGS + Fuel Cell

Ammonia

Figure 2.3.6 – Products of the gasification process [14].

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Selection Gasifiers operate at much lower temperatures than combustors, for that reason the selection of equipment allows a wider variety of feedstocks, such as high alkali fuels, than may be technically feasible for the direct combustion systems. High alkali fuels such as switchgrass, straws and other agricultural residues often cause severe corrosion, erosion and deposition problems on heat transfer surfaces in conventional combustion boilers. Gasification systems can easily remove some alkali species from the fuel gas before it is combusted. Design The are several practical implications of each gasifier type. Due to the diluent effect of the nitrogen in air, fuel gas from direct gasifier is of low heating value (5.6-7.5 MJ/Nm3) this low heat content in turn requires an increased fuel flow to the gas turbine. Consequently, in order to maintain the total (fuel + air) mass flow through the turbine within design limits, an air bleed is usually taken from the gas turbine compressor and use in the gasifer. This bleed air is either boosted slightly in pressure or expanded to near atmospheric pressure depending on the operating pressure of the direct gasifer. Since the fuel-producing reactions in an indirect gasifer take place in a separate vessel, the resulting fuel gas is free of nitrogen diluent and is of medium heating value (13-18.7 MJ/Nm3). This heat content is sufficiently close to that of natural gas (approx. 38 MJ/Nm3) that fuel gas form an indirect gasifer can be used an unmodified gas turbine without air bleed. Gasifier operating pressure affects not only equipment cost and size, but also the interfaces to the rest of the power plant including the necessary cleanup systems. Since gas turbines operated at elevated pressures, the fuel gas generated by low pressure gasifiers must be compressed. This favours low temperature gas cleaning since the fuel gas must be cooled prior to compression in any case. Air for a low pressure gasifier can be extracted from the gas turbine and reduce in pressure (direct, low pressure gasifier) or supplied independently (indirect gasifier). High pressure gasification favors hot, pressurized cleanup of the fuel gas and supply to the gas turbine combustor at high pressure (∼538ºC) and sufficiently high pressure for flow control and combustor pressure drop. Air for high pressure, direct gasifer is extracted from the gas turbine and boosted in pressure prior to introduction to the gasifier. Cooling, cold cleanup, and fuel gas compression add equipment to an indirect gasifer system and reduce its efficiency by up to 10%. Gasifier and gas cleanup vessels rated for high pressure operation and more elaborated feed system, however, add cost and complexity to high pressure gasification systems despite their higher efficiency. [4] Table 2.3.2 summarises the main operation parameters in gasifiers. Table 2.3.2 - Operation parameters in gasification. [14] Reaction Temp. (ºC) Fix-Bed Downward Upward Crossed Flow Fluidized-Bed Simple Reactor Rapid Fluid Circulating bed Dragged Bed Double Reactor Other Rotatory Furnace Cyclonal Reactors

1.000 1.000 900 850 850 850 1.000 800 800 900

Gas Temp. (ºC)

Tars

800 Very low 250 Very high 900 Very high 800 850 850 1.000 700

Moderate Low Low Low Low

800 High 900 Low

Particles

Scaled

Max. Capacity (t/h)

Min. Capacity (t/h)

Moderate Moderate High

Bad Good Good

0,5 10 1

0,1 1 0,1

High Very high Very high Very high High

Good Very good Very good Good Good

10 20 20 20 10

1 2 2 5 2

High Very high

Medium Medium

10 5

2 1

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Efficiencies Efficiencies of biomass based on gasification are much higher than the direct combustion systems. Process efficiencies are comparable to high efficiency coal based systems, but can be achieve at smaller scale of operation. The combined heat and power generation via biomass gasification techniques connected to gas-fired engines or gas turbines can achieve significantly higher electrical efficiencies between 22 % and 37 % compared to biomass combustion technologies with steam generation and steam turbine (15 % to 18 %). If the produced gas is used in fuel cells for power generation, an even higher overall electrical efficiency can be attained in the range between 25 % and 50 %, even in small scale biomass gasification plants and under partial load operation. Feed and Solids Handling [13] •

• • • • •

The capacity of the feed storage system should be sufficient for a tow-day continuos operation. This will be permit operation of the system while fixing any unexpected problems with the feed dryer, or any other feed handling equipment and also cover operations over weekends and short holidays. Carryover of dirt and rock with feed material hinders solids flow and may produce sparks leading to explosions. The presence of oversize biomass materials may cause jamming of rotary valves. For biomass feed bins, ultrasonic or radioactive level detectors are preferable compared to instruments that protrude into feed vessels and may obstruct solids flow. Condensation of moisture in feed silos may to solids sticking to walls. Therefore, care must be taken to prevent any condensables from flowing into the feed bin. System design to purge air from feed-bins must be designed to avoid complications due to dust explosion and to prevent condensation of fuel moisture.

Refractory Installation [13] •

•

Selection and sequential installation, curing and firing of gasifier refractories is important. Although the high-alumina refractories are wear resistant, they are prone to cracking. This could be a problem when the gasifier is subject to unscheduled high temperature, particularly during the start-up phase of a new gasification plant. Formation of alkali-silicates lead to expansion of refractories. This should be taken into consideration by proper scheduling of construction, curing, finishing the refractory lining work.

2.3.2

ENVIRONMENTAL IMPACT

The emissions of biomass processes vary depending upon the precise fuel and technology used. If wood is the primary biomass resource, very little SO2 comes out of the stack. NOx emissions vary significantly among combustion facilities depending on their design and controls. Some biomass power plants show a relatively high NOx emission rate per kilowatt-hour generated if compared to other combustion technologies. This high NOx rate, an effect of the high nitrogen content of many biomass fuels, is one of the top air quality concerns associated with biomass. Carbon monoxide (CO) is also emitted - sometimes at levels higher than those for coal plants. Biomass plants also release carbon dioxide (CO2), the primary greenhouse gas. However, the cycle of growing, processing and burning biomass recycles CO2 from the atmosphere. If this cycle is sustained, there is little or no net gain in atmospheric CO2. Given that short rotation woody crops (i.e., fast growing woody plant types) can be planted, matured and harvested in shorter periods of time than natural growth forests, the managed production of biomass fuels may recycle CO2 in one-third less time than natural processes.

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Biomass power plants also divert wood waste from landfills, which reduces the productions and atmospheric release of methane, another potent greenhouse gas. Another air quality concern associated with biomass plants is particulate. These emissions can be readily controlled through conventional technologies. To date, no biomass facilities have installed advanced particulate emission controls. Still, most particulate emissions are relatively large in size. Their impacts upon human health remain unclear. The collection of biomass fuels can have significant environmental impacts. Harvesting timber and growing agricultural products for fuel requires large volumes to be collected, transported, processed and stored. Biomass fuels may be obtained from supplies of clean, uncontaminated wood that otherwise would be landfilled or from sustainable harvests. In both of these fuel collection examples, the net environmental plusses of biomass are significant when compared to fossil fuel collection alternatives. On the other hand, the collection, processing and combustion of biomass fuels may cause environmental problems if, for example, the fuel source contains toxic contaminants, agricultural waste handling pollutes local water resources, or burning biomass deprives local ecosystems of nutrients that forest or agricultural waste may otherwise provide.[5] In the specific case of gasification and due to the improved electrical efficiency of the energy conversion via gasification, the potential reduction in CO2 per megawatt of power generated is greater than with combustion. Biomass is also lower in sulphur than coal, a typical biomass contains 0,05 to 0,20 weight percent of sulphur in dry basis. The biomass sulphur content translates to about 51 to 214 mg SO2/MJ. The formation of NOx compounds can also be largely prevented and the removal of pollutants is easier for various substances. The NOx advantage, however, may be partly lost if the gas is subsequently used in gas-fired engines or gas turbines. Significantly lower emissions of NOx, CO and hydrocarbons can be expected when the produced gas is used in fuel cells instead of using it in gas-fired engines or gas turbines.[4] In the case of combustion, the installation needs to be properly designed for a specific fuel type in order to guarantee adequate combustion quality and low emissions. Emissions caused by incomplete combustion are usually a result of either [6]: • • • • •

Poor mixing of combustion air and fuel in the combustion chamber, giving local fuel-rich combustion zones. An overall lack of available oxygen. Combustion temperatures that are too low. Residence times that are too short Radical concentrations that are too low

For co-combustion biomass with coal can have a substantial impact on emissions of sulphur and nitrous oxides. SOx emissions almost uniformly decrease when biomass is fired with coal, often in proportion to the biomass thermal load, because most biomass fuels contain far less sulphur than coal. An additional incremental reduction is sometimes observed due to sulphur retention by alkali and alkaline earth compounds in the biomass fuels. The effects of co-firing biomass with coal on NOx emissions are more difficult to anticipate. [6]

2.3.3

TECHNO-ECONOMIC ASPECTS

Biomass feedsotcks can be of many types from diverse sources. This diversity creates technical and economic challenges for biopower plant operators because each feedstocks has different physical and thermochemical characteristics and delivered costs. Increased feedstock flexibility and smaller scales relative to fossil-fuel power plants present opportunities for biopower market penetration. Feedstocks

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type and availability, proximity to users or transmision stations, and markets for potential by products will influence which biomass conversion technology is selected and its scale of operation. The biomass technologies depend on location, power plant type and the availability of low cost biomass fuels [4]. Three broad categories of biomass energy should be distinguished. Firstly, programs, which are presently commercial, can be analysed in both developing and developed countries. These analyses point to certain necessities: first, good yields, both in the production and conversion phases and second as consideration of all economic factors (such as import substitution, energy security, subsidies, export policy) as well as social and land use policies. The following are the technologies that can be included in this category: bioethanol, charcoal, electricity form waste and residues and possibly short rotation forestry (including fuelwood energy plantations in some instances). However, these technologies are not necessarily all sustainable in an environmental sense or viable without certain forms of subsidy. A second category of technologies is those such as biogas, stoves, gasification and briquetting. They can be considered as being at the “take off” stage but may not necessarily be successful either universally or in specific instances. Much will depend on local policies and on international energy factors. Third category is projects such as those to rehabilitate degraded areas and/or provide biomass in its various forms to local people (social forestry and agroforestry projects). The first category, is far easier to analyse, generally the debate revolves around the extent of subsidy (if any) that is required to make these biomass energy systems economically viable in the conventional sense. If “externalities” such as employment, import substitution, energy security, environment and so on, are also considered then the economics usually change in favor of the biomass systems. The technologies used in this category are often universally available so that technology transfer to optimize production and conversion can be quite easy – given the appropriate institutional structure and financial incentives – especially in comparison with fossil fuels. Indeed a number of developing countries could relatively easily adapt an improve technologies for these so called modern biofuels e.g. efficient ethanol distillation plants with low effluents and biomass gasifiers plus turbines for electricity. In the second category there are opportunities for entrepreneurs to operate and for costs to decline given technical improvements. Stoves, for instance, can be improved, their costs reduced and their marketing improved. Biogas digesters can be constructed with designs for lower cost and easier maintenance, and infrastructure for technicians and builders can be established. Such technologies still usually require some from of subsidy but the social costs and benefits are much more evident than in the third category. The policy and institutional changes required for wider dissemination are also more clearly discerned, and thus decisions are more easily taken and maintained. For projects in the third category, long term funding is essential if the techniques and technologies of project implementation are to be made sustainable and replicability is to encourage. Conventional economic paybacks are usually very tenuous, thus making it difficult to progress to the second category, where economic criteria are that much more important [11].

2.3.4

SOCIO-ECONOMIC ASPECTS

Many social issues impinge on biomass energy, local employment, and opportunities for entrepreneurs and development of skills, rural stability on an environmentally sound basis, local control of resources, and promotion of appropriate political and economic infrastructures. At the national level, development of institutions capable of R&D and integrated land use planing which encompasses the biomass dimension seems essential if biomass is not to remain forever the poor, rural relation. Modernisation of bioenergy production and use could bring very significant social and economic

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benefits to both rural and urban areas. Lack of access to a reasonable mount of energy, particularly modern energy carriers like electricity, gas and liquid fuels, limits the quality of life of many hundreds of million people throughout the world [11]. The increased use of bioenergy has stimulated a revival of cultural traditions. In boreal forest, many remote communities have no year-round road or connections to electricity grids, and are dependent on diesel generators supplied by forest flown or barged in at high cost. These communities are often surrounded by forest that could provide the necessary biomass for energy generation, making the community more self-sufficient, reducing the cost, providing employment, keeping wages and benefits within the community, and generally integrating ell with a forest-bases culture. Table 2.3.3 shows the principal factors to the social development. Table 2.3.3 - Indicators of socioeconomic sustainability within the context of modernized biomass energy for sustainable development. [2] Category

Impact

Basic needs

Improved access to the basic services

Income generating opportunities

Creation or displacement of jobs, livelihoods

Gender

Impacts on labour, power, access to resources

Land uses competition and land tenure

Changing patterns of land ownership. Altered access to common land resources. Emerging local and macroeconomic competition with other land uses.

Quantitative Indicators Number of families with access to energy services (cooking fuel, pumped water, electric lighting, milling, etc.) quality, reliability, accessibility, and cost. Volume of industry and small-scale enterprise promoted, jobs/money invested, salaries, seasonality, accessibility to the local labourers, local recycling of revenue (through wages, local expenditure, taxes) development of markets for local farm and non-farm products. Relative access to outputs of bioenergy project. Decision-making responsibility both within and outside of bioenergy project. Changes to former division of labour. Access to resources relating to bioenergy activities. Recent ownership patterns and trends (e.g. consolidation or distribution of landholdings, privatization, common enclosures, transferal of land rights/free rights). Price effects on alternative products. Simultaneous land uses (e.g. multipurpose crop production of other outputs such as traditional biofuel, fodder, food, artisanal, etc.

In addition, biomass energy systems should be perceived as providing substantial foreign exchange savings if they replace imported petroleum products; however, this issue is not always clear cut, and can depend on import substitution and export earnings [8].

2.3.5

SIMULATION AND OPTIMIZATION TOOLS

The following software packages presented can be used as simulation tools in biomass technologies.

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Table 2.3.4 - Simulation tools in biomass technologies Software ASPEN Plus© GateCycle™

Function Models continuous processes to obtain material and energy balances Performs detailed steady-state and off-design analyses of thermal power systems Performs detailed process plant cost estimates

Questimate© MATLAB® and Perform numeric calculations and mathematical solutions MathCAD® Operates within Microsoft Excel® and incorporates uncertainties in Crystal Ball® forecasting analysis results

Conducting full life-cycle assessments for biomass products, including electricity, biodiesel, and ethanol, is important for determining environmental benefits. These tools can be applied on a global, regional, local, or project basis. Biomass Feedstock Composition and Properties Database: It is the resulting data from analysis of more than 150 (as of 10/01) samples of potential biofuels feedstocks including corn stover, wheat straw, bagasse, switchgrass and other grasses, and poplars and other fast-growing trees. Biotracker Database: Program management work tracking tool. Standard Biomass Analytical Procedures: Provide tested and accepted methods for performing analyses commonly used in biofuels research. Theoretical Ethanol Yield Calculator: Allows you to calculate the theoretical ethanol yield of a particular biomass feedstock, based on its sugar content. Thermodynamic Data for Biomass Conversion and Waste Incineration: This National Bureau of Standards/NREL report provides heat of combustion and other useful data for biopower and biofuels research on a wide range of biomass and nonbiomass materials. Crosscutting Analytical Tools The following is a list of models and tools that can assist in learning more about our main renewable energy technologies and their uses. Most of these tools can be applied on a global, regional, local, or project basis. Cost Curves: The cost of energy (COE) from renewable technologies has steadily declined in the past quarter century. Energy-10: ENERGY-10 software can identify the best combination of energy-efficient strategies, including daylighting, passive solar heating, and high-efficiency mechanical systems. Using ENERGY-10 at a project's start takes less than an hour and can result in energy savings of 40%-70%, with little or no increase in construction cost. HOMER: The micropower optimization model, simplifies the task of evaluating design options for both off-grid and grid-connected power systems. The large number of technology options, range of technology costs, and variable availability of energy resources make these decisions difficult to make. HOMER's optimization and sensitivity analysis algorithms make it easier to evaluate the many possible system configurations. Hybrid2: The Hybrid2 code is a user-friendly tool to conduct detailed long-term performance and economic analysis on a wide variety of hybrid power systems. Real Options Analysis Center: (ROAC) features two online models for real options valuation of renewable energy R&D and valuation of distributed generation assets.

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Renewable Energy Technology Characterizations (1997): Describe the technical and economic status of the major emerging renewable energy options for electricity supply. These technology characterizations represent the best estimates of the U.S. Department of Energy (DOE) and the Electric Power Research Institute (EPRI) regarding the future performance and cost improvements expected for these technologies as a result of continuing research and development (R&D) and development of markets for renewable energy through the year 2030. The Renewable Energy Technology Characterizations are copyrighted, but permission is granted for unlimited copying for noncommercial use. ViPOR: The Village Power Optimization Model for Renewables, is a computational tool capable of designing an autonomous village electrification system using the lowest cost combination of centralized and isolated generation.

2.3.6 1. 2. 3. 4.

REFERENCES

Benefits of bioenergy. IEA Bioenergy, 2005 Biogas Production and utilization. IEA Bioenergy, 2005 http://btgworld.com Renewable Energy Technology Characterizations . EPRI and U.S. Department of Energy. December 1997. 5. Biomass Energy Technology. Oregon. http://www.oregon.gov 6. Biomass Combustion and co-firing: An Overview. IEA Bioenergy, 2002 7. Atmospheric Pressure Fluidized Bed Boilers. Ch 16 in Steam, 40th ed., Babcock and Wilcox, Barbeton, OH, 1992. 8. Electricity from Biomass. Power Scorecard TM. http://www.powerscorecard.org 9. Biomass Cofiring. A Renewable Alternative for Utilities. Biopower FtactSheet. National Renewable Energy Department. June, 2.000 10. Co-combustión de carbón y biomasa en calderas de combustible pulverizado. Royo, J and Sebastían,F. Fundación Circe. Univerisdad de Zaragoza. 11. Biomass. Hall, O., David. Development Economics The World Bank. August,1992 12. National Renewable energy laboratory . http://www.nrel.govb 13. Summary of Operational Experience with Recent Biomass gasification Demonstration Plants. Dr. Suresh P. Babu. IEA Bioenergy, 2.003. 14. Economic and Finacial Aspects of Landfill Gas to Energy project Development in Californa. California Energy Commission. April, 2.002

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Thermal Cooling systems (CREVER) Analysis of technical aspects

Thermally driven chillers and heat pumps are systems that use thermal energy to deliver cooling or heating at several temperature levels. This technology also called sorption technology covers the same working segment as mechanical compression systems: chillers, refrigerating machines and heat pumps. For chillers the heat extracted at a low temperature or in other words: ‘cooling’, is the main yield of the system. There are various types of sorption cycles with different level of commercial development and availability: • • • • •

Absorption chillers Absorption heat pumps (types I and II) Compression/absorption heat pumps Solid sorption systems Desiccant systems

2.4.1.1 Absorption Chillers The working principle of an absorption system is similar to that of a mechanical compression system with respect to the refrigerant path through the evaporator and condenser. A low pressure vaporising liquid extracts heat at a low temperature (cooling). Then the vapour is compressed to a higher pressure and condenses at a higher temperature (heating). After this, the pressure of the liquid is reduced after which the cycle can start from the beginning. The compression of the vapour is carried out by means of a “heat driven” compression cycle consisting of two main components, absorber and generator. Absorption cooling systems always work with a mixture, i.e. a working pair, consisting of a volatile component (refrigerant) and an absorbent. The most common working pairs are Water (refrigerant) / Lithium Bromide (absorbent) and Ammonia (refrigerant) / Water (absorbent). These two main types of mixtures are applied dependent of the required cooling temperature: • •

Cooling temperature > 5 °C: Water / Lithium Bromide (LiBr) absorption chiller. Cooling temperature < 5 °C: Ammonia / Water absorption refrigerator.

In the Water / LiBr machine, water is the refrigerant and cooling is based on the evaporation of water at very low pressures. Since water freezes at below 0 °C, at this level the chilling temperature meets a physical limit. LiBr is soluble in water if the LiBr mass fraction of the mixture is under about 70 %. This set a maximum to the temperature of the absorber. Appropriate controls will prevent crystallisation problems. In order to supply sufficient low temperatures to the absorber at high outside air-temperatures cooling towers are typically applied although a few recent advanced systems can use also air for dissipation of heat. Water/LiBr chillers are applied for air-conditioning. In the Ammonia/Water machine, Ammonia is the refrigerant. This offers opportunities to provide refrigeration at temperatures down to – 60 °C. In the generator besides ammonia vapour also a certain amount of water vapour will occur. In the evaporator, this will lead to problems, because the Ammonia will evaporate more easily than the water. This results into an accumulation of water in the evaporator, spoiling the chilling process. To prevent this, an extra device is added to the system to separate the water content from the vapour flow coming off the generator. This is called a rectifier, which cools the vapour produced in the generator, therefore demanding more heat. Therefore, rectification reduces the coefficient of performance (COP). Ammonia is soluble in water at all concentrations; therefore, dry air coolers can be easily applied in this case.

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Single effect chillers. The simplest design of an absorption chiller consists of an evaporator, a condenser, an absorber, a generator, a solution heat exchanger and a solution pump (Figure 2.4.1). Compressing the refrigerant vapour is effected by the absorber, the solution pump and the generator in combination, instead of a mechanical vapour compressor. Vapour generated in the evaporator is absorbed into a liquid absorbent in the absorber. The absorbent that has taken up refrigerant, the rich solution, is pumped to the generator with a previous preheating with the solution coming out of it. In the generator the refrigerant is released as a vapour, which vapour is to be condensed in the condenser. The regenerated or strong absorbent is then led back to the absorber to pick up refrigerant vapour. Heat is supplied to the generator at a comparatively high temperature and rejected from the absorber/condenser at a comparatively low level. Cold is produced in the evaporator.

Figure 2.4.1 - Single-effect absorption chiller Double effect chillers. The easiest way to describe a double-effect cycle is to consider two singleeffect cycles staged on top of each other. The cycle on top is driven either directly by a natural gas or oil burner, or indirectly by steam. Heat is added to the generator of the topping cycle (primary generator), which generates refrigerant vapour at a relatively higher temperature and pressure. The vapour is then condensed at this higher temperature and pressure and the heat of condensation is used to drive the generator of the bottoming cycle (secondary generator), which is at a lower temperature (Figure 2.4.2).

Figure 2.4.2 - Double effect absorption chiller

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The cooling capacity range for available water/LiBr absorption chillers goes from small units of just 4.5 kW developed for solar air conditioning applications to units of more than 5000 kW used for high demand applications such as district heating and cooling applications. The range for ammonia/water chillers goes from small gas-fired units of just 18 kW up to units of a few MWs for specific case designed industrial applications such as in the agro-food industry. Other chillers. There are also a number of advanced cycles such as half-effect, resorption cycle absorption power and triple-effect cycles. These technologies are however at development or experimental stages. The triple effect cycle is currently being developed by several leading absorption equipment manufacturers and a gas fired cooling COP in the order of 1.5 is expected. Chiller/heaters. Chiller/heaters can be used to provide both cooling and heating. These chillers, therefore, can be installed in systems to supplement, or even replace, primary heating or domestic hot water equipment. An auxiliary heating bundle can be added, allowing the chiller to make hot water as well as chilled water. The auxiliary heating bundle draws in a portion of the refrigerant vapour leaving the hightemperature generator that can be used for comfort heating, domestic hot water needs, or process heating loads. The key advantage of this design is that it can be configured to operate in cooling only, heating only, or simultaneous cooling/heating modes. An alternate method is to use the evaporator as a condenser in the heating mode. In this case, by switching the cooling/heating changeover valve the chiller switches to heating mode, and hot water can be delivered using the same piping system that was used to supply chilled water in the cooling mode. The cooling tower and refrigerant pumps can typically be shut off. The refrigerant vapour produced by the high-temperature generator flows into the evaporator. Heat is transferred from the hot refrigerant vapour to the water flowing inside the evaporator tubes, causing the refrigerant to condense on the tube bundle and fall into the evaporator pan. This condensed liquid refrigerant then overflows into the absorber section where it is absorbed by the lithium bromide solution. The resulting dilute absorbent solution is preheated and returned to the high temperature generator to repeat the cycle. The advantage of this design is that no additional bundle is required for heating mode. This chiller, however, can only operate in cooling mode or heating mode—no simultaneous operation is possible. GAX The GAX (Generator Absorber heat eXchanger) cycle as shown in Figure 2.4.3 is a heat-recuperating cycle in which absorber heat is used to heat the lower temperature section of the generator as well as the rich ammonia solution being pumped to the generator. The external power required by the generator will be reduced and so the efficiency of the machine improved. This cycle, like others capable of higher COPs, is more complex and diffcicult to develop than the ammonia-water cycle but its potential COPs of 0.9 in cooling mode and 1.8 in heating mode make it capable of significant energy savings on an annual basis. In addition to providing a more effective use of heat energy than the most efficient furnaces, the GAX heat pump is able to supply all the heat a house requires to outdoor temperatures below –18ºC without the use of supplemental heat.

Figure 2.4.3 - GAX cycle

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Hybrid compression/absorption systems A Compression - Absorption heat pump consists of a solution circuit incorporated in a vapour compression heat pump (Figure 2.4.4). The advantage of this system is the higher temperature of the heat delivery. In the cycle shown in Figure 4, the evaporation of the working pair solution in the desorber is incomplete. The solution can circulate between the desorber and the absorber by the use of a solution pump. If all of the solution is circulated by the solution pump, the cycle is called “the Osenbrück cycle”. When all of the solution is circulated through the compressor, avoiding the use of a solution pump, the cycle is called a “total wet compression cycle”. The total variation scale between these two cycles can be used. In the Absorption – Compression system the compressor is incorporated to boost the absorption cycle. The compressor is used to boost the pressure of the condenser or the pressure of the absorber. In the former case, this will enable the use of waste heat in a heat pump or will give a higher temperature of the heat produced by the absorber. In the later case, a compressor is boosting the pressure of the absorber. This is the same as lowering the pressure of the evaporator. By lowering the evaporator pressure, the heat pump can operate at lower temperatures of the sink.

Figure 2.4.4 - Compression – absorption cycle

2.4.1.2 Absorption heat pumps (Type I and II) An absorption heat pump type I is a device exactly similar to an absorption chiller. The only difference is the naming of the heat flows it operates on. Where a chiller provides cooling, a heat pump takes heat from a low temperature heat-source. Where a chiller rejects heat, a heat pump provides heating. Heat is lifted from a low temperature level in the evaporator, to a medium temperature level in the absorber and condenser. This is achieved by supplying heat at a high temperature level in the desorber or generator. There are three parameters of high interest. The COP determines the amount of heat that can be delivered in relation to the heat supplied. Second is the possible temperature lift that can be achieved at the three temperature levels, and third is the maximum possible temperature-level at which heat can be delivered. Absorption heat pump with LiBr/H2O can only be used for heat demands below 100 ºC, due to the risk of crystallisation. In absorption heat pumps type II (heat transformers), heat is supplied at a medium temperature level in the evaporator and desorber. One part of this heat is transformed to a high temperature level, and the other discharged at a low temperature. The highest temperature usable output is from the absorber, and the lowest temperature is the heat rejected in the condenser. The heat transformer is useful for recovering industrial waste heat at a medium temperature level, and replacing primary heat.

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2.4.1.3 Solid sorption systems Instead of absorption of refrigerant in an absorbing solution, it is also possible to adsorb refrigerant to a solid. Sorption to a solid is called adsorption. Typical examples of working pairs are Water – Silicagel, Water – Zeolite, Ammonia – Activated carbon, Methanol – Activated carbon etc. In absorption machines the ability of circulating the absorbing fluid between absorber and desorber results into a continuous loop. In adsorption machines the solid sorber has to be alternately cooled and heated to be able to adsorb and desorb. The loop therefore is cyclic by nature. To create a more uniform cooling effect two or more cycles can be connected to each other. This way there is always a sorber available to adsorb the vapour of the evaporator. Another advantage is the following: each loop energy is needed to heat the sorber to a level where the refrigerant releases from the sorber. This energy does not contribute to the cooling effect of the adsorption machine. In adsorption machines, the solid sorbent has to be alternately cooled and heated to be able to absorb and desorb the refrigerant. When the right compartment has been fully charged and the left compartment fully regenerated, their functions are interchanged. In between, the two chambers may be directly coupled in order to achieve some heat recovery, since the hot chamber has to be cooled in the next step and vice versa. So using multiple sorbers it is possible for the different sorbers to exchange heat with each other reducing the auxiliary energy to heat the sorbers and improving the efficiency of the cycle. Much research has been put into optimising this principle. The adsorption cycle (Figure 2.4.5) begins when the refrigerant is previously adsorbed in one adsorber and is driven off by the use of hot water (right compartment), the refrigerant condenses in the condenser and the heat is removed by cooling water. The condensed refrigerant is sprayed in the evaporator under low pressure generating the useful cooling effect (left compartment). The refrigerant vapour is adsorbed onto the other adsorber and the heat is removed by cooling water. Adsorption chillers capacity range starts from around 50 kW although a few systems in the range of 10 kW are being developed and ends at around 600 kW of cooling capacity.

Figure 2.4.5 - Adsorption Chiller

2.4.1.4 Desiccant systems All sorption systems described above are closed cycles. Contrarily desiccant systems are open cycles used to produce conditioned fresh air directly. The airflow consists of ambient air, which needs to be cooled and dehumidified in order to meet the required supply air conditions. Complementing combined evaporative cooling with desiccant dehumidification enhances the cooling capacity of the cycle and thus it is possible to reach even lower temperatures. If the outdoor air is properly pre-treated, the ventilation air can be cooled to lower temperatures via subsequent indirect and direct evaporative cooling. For this purpose, the pre-treatment involved is the desiccant dehumidification without obtaining a disproportionate high humidity ratio.

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The dehumidification process uses either liquid or solid desiccants. The first ones use air desiccant contactors in the form of packed towers or the like. In the second ones use either rotating wheels or periodically operated, fixed-bed systems. Regeneration heat must be supplied in order to remove the adsorbed water from the desiccant. The required heat is at the relatively low temperature, in the range of 50 to 100ºC, depending on the desiccant material and the degree of the dehumidification. The desiccant wheel is the most common type of sorption dehumidifier based on the used of a solid desiccant. The desiccant material is coated, impregnated or formed in place on a supporting rotor structure. This material is a mix of different fibres, including glass, ceramic binders and heat resistant plastics. This machine can operated either as a dehumidifier or as an enthalpy recovery component in desiccant cooling and heating respectively. The desiccant cooling process begins (figures 2.4.6 and 2.4.7) when the air (1) is dehumidified, causing the air temperature to increase; the process is nearly adiabatic (2) the regenerative heat recovery leads to cooling of the air inlet to the humidifier (3). Depending on the air inlet temperature and humidity supplied, the temperature is reduced by direct evaporative cooling in the humidifier, with a simultaneous increase in humidity up to condition (4). The coil on the supply stream is in operation only for heating conditions. The fan releases heat, leading to an increase in the temperature of the supply air (5), which brings about the supply air condition (6). An increase in temperature of up 1ºC is usually expected. The return air from the room is in state (8). The air is then humidified as close as possible to saturation (8). This state is the one, which guarantees the maximum potential for indirect cooling of the supply air stream through the heat exchanger for heat recovery. The heat recovery from (8) to (9) is subsequently leads to an increase in the temperature of the air, which is the use as regeneration air. The air is subsequently reheated in the coil until it reaches state (10). The temperature of the latter is adjusted such as to guarantee the regeneration of the sorption wheel (10 to 11).

Figure 2.4.6 - Desiccant system

Figure 2.4.7 - Typical desiccant cooling process (figure 2.4.6) in the T-x diagram

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2.4.1.5 Advantages and disadvantages Table 2.4.1 – Main advantages and disadvantages of the most applied sorption systems.

Advantages

Absorption heat pump (Types I and II) Practically no moving parts

Compressionabsorption heat pump

Practically no moving parts Simple construction

Good partial load behaviour if solution management system is provided

High temperature Good partial load lift behaviour if solution Cycle efficiency management system is provided

Corrosion at higher temperatures Very low market development

Desiccant Adsorption heat evaporative pump/chiller cooling system No moving parts

Simple construction

Low noise Slow starting Disadvantages

Absorption chiller

Low driving temperatures Easy regulation Lower of temperature and humidity condensing temperatures than in absorption systems are possible

Low noise Lower COP than absorption systems

Slow starting Corrosion at higher temperatures

Still in development

Higher volume and weight than absorption systems

Chilled air limited to 18ºC Ventilation system has to be well balanced

2.4.1.6 Current status, manufacturers and installations The dominating type of thermally driven cooling technology to produce chilled water is absorption cooling. Absorption chillers habe been in commercial use for many years, mainly in combination with cogeneration plants using waste heat or directly fired. For air conditioning applications absorption systems commonly use the water/lithium bromide working pair. For some small size and industrial applications ammonia/water machines are also widely used. Adsorption chillers have a much lower market share. Table 2.4.2 summarises the range of main parameters concerning absorption chillers. Triple effect chillers are not considered since the existing equipment workings under this effect are experimental machines. These machines have COPs above 1.6 and operate in the temperature range 170 to 200ºC.

Table 2.4.2 – Main performance characteristics of conventional absorption chillers. Parameters Effect Cooling capacity (kW) Thermal COP Temp. range (ºC)

NH3/water absorption Single 18 – 2500 0.6 (0.9 GAX cycle) 120 – 132

Water/LiBr absorption Single Double 300 - >5000 300 – >5000 0.7 0.9 – 1.3 90 – 120 120 – 170

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The water/LiBr absorption chiller market is strongest in Asia followed by the USA and Europe. Chiller sizes in Asia and in the USA are larger than those generally installed in Europe. The main reason why direct fired or boiler driven chillers have an important market share is solely due to difficulties with the electric supply for electric driven chillers in some areas. In Japan there is a policy of diversification of energy, and in China, Korea and India there is a lack of electricity infrastructure. Europe tends to use smaller capacity machines and have focussed more on waste heat, heat recovery and CHP applications; however, the electric infrastructure problem is also present. There are two categories of ammonia absorption chillers: packaged 18kW air cooled units, and industrial type. The small packaged chillers which, are used for residential and light commercial applications have a world market of approximately 4000 units per year, of which around half are sold in Europe and a quarter in the USA. This represents less than 4% of the cooling capacity of the LiBr chillers. Absorption heat pumps (AHP) and absorption heat transformers (AHT) compete mainly with boilers, and due to the big difference in initial plant costs, have a very poor market penetration. There are approximately 100 AHPs and 30 AHTs installed world-wide over the last decades. Adsorption chillers are having the most rapid growth of all. Although this is a relatively new technology, there are a total of more than one hundred of units already installed with cooling capacities ranging from 70 to 600kW. Their attractive feature is that although they have less thermodynamic efficiency, due to their cycling nature, they can be driven with lower hot water temperatures than most conventional absorption chillers. This makes them more suitable to cope with lower waste heat temperatures, which in turn favours their marketing possibilities. The tables below summarise the list of manufacturers. The list is certainly not exhaustive. Table 2.4.3 - Manufacturers of water/LiBr absorption equipment Manufacturers

Carrier Corporation (USA)

YORK International (USA)

The TRANE Company (USA)

Yazaki (Japan)

Sanyo (Japan)

Ebara Corporation (Japan)

Hitachi (Japan)

Products (Size) • Direct fired, double-effect chiller/heaters (475 – 3500 kW) • Steam fired, double-effect chillers (350 – 6000 kW) • Steam & hot water single-effect chillers (350 – 2400 kW) • Direct fired, double-effect chiller/heaters (400 – 5500 kW) • Steam fired, double-effect chillers (900 – 5500 kW) • Hot water single-effect chillers (400 – 5000 kW) • Direct fired, double effect chiller/heaters (350 – 4000 kW) • Direct fired, double-effect chillers (300 – 4000 kW) • Steam fired, double-effect chillers (1400 – 4000 kW) • Steam & hot water single-effect chillers (350-6000 kW) • Direct fired, double-effect chiller/heaters (105 – 352 kW) • Hot water single-effect chillers (10 – 105 kW) • Direct fired, double-effect chiller/heaters (350 – 5250 kW) • Steam fired, double-effect chillers (350 – 5250 kW) • Hot water single-effect chillers (105 – 1838 kW) • Direct fired, double-effect chillers (300 – 2000 kW) • Single-effect chillers (300 – 5000 kW) • Low level heat source chillers (100 – 900 kW) • Steam fired, double-effect chillers (400 – 6000 kW) • Direct fired, double-effect chiller/heaters (70 – 5000 kW)

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Thermax (India)

Entropie (France/Germany)

LG Machinery (Korea)

Kyung Won Century (Korea)

• • • • • • • • • • • • •

Broad (China)

• • Rotartica (Spain)

•

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Steam single-effect chillers (100 – 5000 kW) Direct fired, double-effect chiller/heaters (352 – 2710 kW) Steam fired, double-effect chillers (352 – 4928 kW) Steam & hot water single-effect chillers (352 – 4900 kW) Indirect fired, double-effect chillers (300 – 6000 kW) Hot water single-effect chillers (300 – 6000 kW) Double-effect heat pumps (300 – 6000 kW) Direct fired, double-effect chiller/heaters (350 – 1750 kW) Steam fired, double-effect chillers (350-1750 kW) Hot water single-effect chillers (100 – 3300 kW) Direct fired, double-effect chiller/heaters (350 – 5200 kW) Steam & hot water single-effect chillers (280 – 5200 kW) Direct fired, double-effect chiller/heaters (174 – 23260 kW) Indirect fired (steam, hot water), double-effect chiller/heaters (174 – 23260 kW) Indirect fired (steam, hot water, exhaust), singleeffect chiller/heaters (174 – 23000 kW) Cooling, heating, and power system (CHP) (70 – 11630 kW) Micro air conditioning unit (cooling, heating, hot water) (16, 23, 70, 115 kW) Air and water-cooled absorption chiller of 4.5 kW a directly driven system in development

Table 2.4.4 - Manufacturers of ammonia/water absorption equipment Colibri bv (The Netherlands)

• • •

Robur (Italy)

• •

Apina (Spain)

• •

Carrier Corporation (USA)

Direct fired single-effect heat pump, GAX (250 kW) Hot water single-effect chiller (700 kW) Direct fired, single-effect chiller/heaters (10 –17.4 kW) Direct fired, single-effect chillers (10 – 17.4 kW) Direct fired, single-effect chillers, GAX (10 – 17.4 kW) Industrial ammonia/water chillers from 500 kW. Direct fired, single-effect chiller/heaters (17.5 – 87.5 kW)

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Table 2.4.5 - Manufacturers of adsorption and desiccant Adsorption Nishiyodo (Japan) Mycom (Japan) DY Refrigeration (China) Jiangsu Shuangliang Air Conditioner Equipments (China) Solid desiccants

55 kW – 1000 kW 50 kW – 350 kW 14 – 30 kW 5 kW (from 5 – 200 kW in the future)

Munters (USA, Sweden) HB Dehumification Systems (Danemark) Seibu Giken (Japan) DRI (India) Klingenburg (Germany) Liquid desiccants Kathabar (USA) (LiCl solution)

2.4.1.7 Future R&D, expectations and timeline For sorption chillers R&D should focus on: • • • • •

Reducing costs (life cycle costs and capital) of integrated systems. Increasing the efficiency of generator at lower driving temperatures. Easy and flexible coupling with different CHP units (microturbines, fuel cells, reciprocating engines, etc). Small capacity units driven at low temperature to use thermal solar energy and waste heat at very low temperature. Development of advanced systems with a higher efficiency using new cycle configurations, working pairs, etc.

In the residential sector sorption heat pumps tend to compete mainly with boilers, thus R&D should focus on: • • •

Decreasing the size to be able to reduce capital costs. Using the same unit for cooling and heating. Increasing the temperature level to be able to deliver hot water.

Both absorption and adsorption systems should be considered for residential and light commercial applications.

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2.4.1.8 Performance summary Table 2.4.6 - Specifications of the most applied sorption systems: temperature ranges and COP (cooling) Source: Annex 24: Ab-sorption machines for heating and cooling in future energy systems, IEA, 2000 Absorption heat pump Type I water-LiBr Heating: <40 ºC Driving: 70-130 ºC Source: >5 ºC COP: 1.7 NH3-water Heating: <60 ºC Driving: 80-200 ºC Source: -15 - +5ºC COP: 1.5

Absorption chiller

Type II

Water-LiBr Rejection: 20-40 ºC Heating: <130 ºC Driving: 60-100 ºC COP: 0.45

Water-LiBr Chilling: >5ºC Driving: 70-130 ºC Rejecting: 20–40 ºC COP: Single 0.7 Double 1.2 NH3-water Chilling: -60 +10ºC Driving: 80-200 ºC Rejecting: 20-50 ºC COP: 0.6

Compression- Adsorption heat absorption pump/chiller heat pump

NH3-water Source: 20-50 ºC Driving: electric Heating: 80-120 ºC

water-silicagel Chilling: >5 ºC Heating: <35 ºC Driving: 60-80 ºC COP: Single 0.4-0.6 water-zeolite Chilling: >5 ºC Heating: <40 ºC Driving: 70-130 ºC COP: single 0.5-0.6

Desiccant evaporative cooling system

Air-desiccant Chilling: >18 ºC Heat rejection: <30 ºC Driving: 50-70 ºC COP: 0.6-1.0

2.4.1.9 Carbon intensity The potential of sorption systems for the reduction of CO2 emission in the conversion process of primary energy to electrical power and refrigeration is strongly dependent on parameters like the conversion method, efficiency of the power station and the COP of the chiller. A Total Equivalent Warming Impact (TEWI) analysis was carried out on absorption chillers1, in which the best selections were found to be heat recovery applications using double effect steam driven absorption chillers. The next best options were single effect hot water driven absorption chillers for short running hour applications and diversification where the absorption chillers were used for the peak loads. Within the same context, double effect direct fired chillers were found to be feasible for a very narrow and limited band of applications. From an environmental point of view of the primary energy requirements, currently produced absorption machines should only be promoted with integrated energy systems such as waste heat or CHP. Direct fired absorption chillers require more primary energy than compression systems. Although direct-fired absorption chillers offer lower running costs, they consume more primary energy. With current single and double effect absorption chillers, the benefit to the environment is in Ozone Depleting Potential (ODP). However if vapour compression systems use zero ODP refrigerants, there is no benefit. The improved efficiencies of the triple-effect absorption chillers and their integration with the new distributed power generation technologies will give absorption chillers a

place in the effort to reduce global warming potential.

1 Annex 24. Ab-sorption machines for heating and cooling in future energy systems – Final report. IEA Heat Pump Centre, 2000

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2.4.1.10 Critical aspects This paragraph summarises important aspects dealing with vacuum requirements, crystallisation, corrosion, and maintenance of sorption systems. The experiences reported and control measures that are highlighted refer to water/LiBr chillers, heat pumps and heat transformers. However, the majority of concerns and reports are related to absorption chillers since the number of heat pump installations is very limited to a few specific applications. Effect of non-condensables The pressure levels associated with LiBr absorption are quite low, and the sensitivity of the technology to leaks is very high. Absorption machines are sensitive to leaks both because air in the machine hurts performance and because of corrosion considerations. Pumping out the air and other gases from the vapour space initially attains the low pressures in the absorption system. Both some water vapour and unwanted gases are removed during the evacuation process. The amount of water vapour that is removed is very small and thus does not influence the absorption cycle. One effect of inert gases in such a machine is to reduce the performance of both the condenser and the absorber. The absorber is the most critical component in this context. Another important effect of these gases is that they reduce the effect of the evaporator due to their partial pressure, which increases the evaporator pressure. This results in a loss of cooling capacity. The manufacturers have somewhat different methods to purge the system: • • •

A direct method is to simply evacuate the vapour space periodically with a vacuum pump Palladium cells which forms a semi-permeable membrane in the system Ejector pumps which use the existing solution pump to collect the gas

In most designs, the operator must periodically purge the gas collection vessel with a vacuum pump. This is preferred over pumping the entire vapour space of the machine since the gas is concentrated and removed quickly and easy. Most purging systems utilise a palladium cell, but still require periodic manual purging. The palladium cell only removes hydrogen automatically, manual purging is needed to eliminate other non – condensables. The frequency at which purging of non - condensables has to be carried out is a sign of the chemical (health) stability within the chiller, i.e. low and controlled corrosion. Air leaks into the system can also cause unacceptable corrosion problems due to the oxygen. Therefore, a LiBr absorption machine must be essentially hermetic in design. The presence of hydrogen can cause poor performance. Hydrogen is essentially inert, non-absorbable in the temperature range of interest and has very low solubility in both liquid water and aqueous LiBrsolutions. Consequently, the produced hydrogen accumulates in the vapour space of the absorption machine. The hydrogen gas has a tendency to migrate from the high-pressure side to the low-pressure side due to the influence of pressure on solubility. The problems generated by leakage are normally related to corrosion problems. The purging procedure is normally not considered as a problem, although there are a few incidents reported on air leakage due to poor gaskets and valves. Crystallisation With the exception for crystallisation issues, absorption machines are today inherently stable and self – starting. However, because of problems with crystallisation, a number of controls are generally provided to deal with this issue. Unchecked inward air leakage of air causes the absorber effectiveness to deteriorate. Then, conventional controls that sense chilled water temperature rising call for increased heat input to the desorber. This in turn, tends to concentrate the salt solution and can cause crystallisation. One approach to avoid crystallisation is to ensure that the solution mass fraction never goes above some limiting value. As long as the machine stays in the expected temperature range of operation, this

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restriction is enough to guarantee no crystals. A method of inferring the concentration is used by some manufacturers based on a known initial charge of solution with known LiBr mass fraction. The refrigerant level in the evaporator is monitored and when it is too high, it is inferred that the solution is too highly concentrated. This scheme is relatively simple to automate and can be implemented using widely available level-sensing transducers. Some manufacturers also have automatic decrystallisation controls so that in the unlikely event of a problem caused by extreme conditions, the problem is automatically solved. Although crystallisation was a major problem in the 70s and 80s, this has been practically overcome since the introduction of modern controls. The exception is mainly power failure interrupting shut down cycles. This is normally not considered as a problem with the new generation of absorption machines. The main reasons for crystallisation reported are: • Interruption of shut down cycles due to power failures or poor controls • Insufficient purging of non- condensables together with unreliable controls • Poor controls of cooling tower water temperature and of steam valves Corrosion In the presence of dissolved oxygen, aqueous LiBr is highly aggressive to many metals including carbon steel and copper. However, in the hermetic environment inside the absorption machine, very little oxygen is present and corrosion rates are much slower. For the temperature range of a typical single-effect unit, carbon steel and copper are the preferred materials of construction. Over the extended life of a machine, significant corrosion can still occur and care must be taken to minimise the effects. The primary measures available are: • •

pH control Corrosion inhibitors

Corrosion of steel (or copper) in the presence of an electrolyte is an oxidation-reduction reaction. The oxidation potential of the solution is a strong function of the pH level in the acidic range. By controlling the solution to be only slightly basic, the hydroxyl radicals are in excess and this tends to cause oxide formation directly on the solid surface (passivation of the metal). However, over time alkality tends to increase as hydrogen gas is formed and it is preferable to keep pH close to neutral. Corrosion inhibitors provide complementary reduction in corrosion rates. Various corrosion additives have been tested over the years including lithium chromate, lithium molybdate and lithium nitrate. These salts are added to the LiBr solution in amounts on the order of 1% by weight. These inhibitors reduce corrosion rates apparently by reacting with the metal surface and forming relatively stable oxide coating (passivation). High temperature applications, including some components in double-effect machines, require special materials to maintain long life. Copper – nickel (CuNi) alloys resists corrosion at high temperatures better than copper and are customarily used. If copper tubes are used, especially in the absorber where oxygen tends to migrate, the oxygen will react quite rapidly with the copper surfaces to form copper oxide, which is soluble in aqueous LiBr solutions. This results in corrosion of the absorber copper tubes. Although CuNi alloy is more expensive, it is also preferred when the external environment is corrosive. The new generation of absorption machines are very safe as regards corrosion but there might be some differences between different manufacturers. Maintenance Normal maintenance for water-LiBr technology includes: • • •

Periodically purging of non-absorbable gases Periodic addition of heat and mass transfer enhancement Periodic addition of corrosion inhibitor

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Periodic addition of pH buffer. Monitoring of the H2O-LiBr solution

The appropriate period for performing these tasks depends on a number of variables, including size of the machine and the purging system, and is generally specified by the manufacturer of the machine. The necessary chemicals are relatively inexpensive and readily available from suppliers. Along with the maintenance procedures, an assessment of cycle performance against norms should be made on a regular basis to help diagnose any potential problems. The ultimate failure mode of a LiBr absorption machine is usually corrosion induced. For long life, attention must be paid to avoid air leakage into the machine and to ensure that the corrosion inhibition regime is strictly followed. Regularly samplings of the LiBr solution are important in order to check the concentration, the inhibitors and other components (e.g. corrosion products). Suggested intervals for testing are once per year for comfort cooling applications and twice per year for units in continuous service (i.e. heating and cooling). Analysis of refrigerant water is normally also suggested. These considerations apply to both absorption chillers and absorption heat pumps.

2.4.2

Techno-economic aspects

Installed Capital Costs (€/kWh) Regarding absorption cooling water/lithium bromide as working pair, chiller costs range from about € 870 to 920 per ton of capacity (double-effect adds about € 58 per ton of capacity). An electric centrifugal chiller costs about € 290 to € 350 per ton of capacity. As shown in the figure below, the cost of a unit per kW of cooling capacity depends on its size, but becomes approximately constant above 2 MW. The average value could be around 100 – 150 €/kW. A rule-of-thumb is that a double effect unit is approximately 20% more expensive than a single-effect unit with the same capacity. The reason for the higher cost is the additional generator and condenser in the design. However, data from the ASHRAE handbook indicate that the extra cost is more likely to be as high as 30-40%. The average value could be estimated as 130 – 250 €/kW. Another rule-of-thumb is that a hot-water fired unit is approximately 25% more expensive than a steam ”fired” unit with the same capacity. The cause for the latter rule would be the size of the ducts necessary for delivering a given thermal power to the absorption machine is larger with hot water than with steam. However, data of some manufacturers do not support this rule-of-thumb. Single-effect absorption machines fired with comparatively low-temperature hot water (90-95 ºC) are more expensive than the conventional single-effect machines. The data of different manufacturers confirms that the price difference is approximately 35%. Ammonia machines costs are around € 1250 to 1750 per ton of capacity.

Figure 2.4.8 - Estimated cost for water/lithium bromide absorption chiller, single effect

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Operation and Maintenance Costs (€/kWh) Maintenance costs of absorption machines greatly vary according to the contract type. In most cases the same maintenance firm provides under a single contract, the operation and maintenance of the whole system. In some cases the firm using the absorption chiller provides its own personnel to attend the operation of the AC system, and uses external services for period check-up (according to the maintenance programme established).

2.4.3

Concepts for integration with other technologies and into networks

Recovery of waste heat Thermally driven cooling systems are potentially very attractive from the economic and environmental point of view when combined with electric generation systems producing waste heat such as, in cogeneration or CHP systems (called trigeneration systems) and district heating networks (called district heating and cooling networks). The electric generation systems that can be coupled with sorption cooling systems can be as divers as reciprocating engines, micro gas turbines, gas turbines, fuel cells, biomass power plants, etc. The characteristics of the recovered waste heat (temperature, mass flow, cleanness, etc) will influence the selection of the suitable thermally driven sorption system. In most cases, it will be the heat demand that determines the cogeneration plant size. The result is that most cogeneration units are smaller than the electrical base-load demand of the site they serve. If the site also requires cooling, sorption cooling offers two potential advantages: -

An additional heat load, allowing increased running hours A reduction in electrical demand, by displacing the need for electrically powered cooling

Thus, at the design stage, it may be possible to specify a larger cogeneration unit that will economically generate more electricity, and simultaneously use extra heat to reduce the electricity demand. Alternatively, if an existing cogenration unit’s output is limited by the demand for heat, a sorption chiller will increase the utilisation of the cogeneration plant, and its electrical output. Solar-assisted air conditioning There are many different ways to convert solar energy into cooling or air-conditioning. A first distinction can be made between electrically operated (photovoltaic panels) and solar thermal collectors (thermal process). Among the thermally driven process, thermo-mechanical processes (such as, Rankine based or steam jet cycles) and processes based on heat transformation can be distinguished. In the latter group, the technologies can be divided into open cycles (desiccant cooling systems) and close cycles (absorption and adsorption systems). Solar collectors and ground-source heat pump The solar heat may be used in different ways in systems with ground source heat pumps, depending on the choice of components and system. In the most flexible systems, solar heat can be used in several ways, depending on demand and temperature levels. • • • •

directly to the domestic hot water directly for heating the building heating the evaporator in the heat pump recharging the borehole.

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The advantages of recharging the borehole include: • • • • •

increased seasonal performance factor of the heat pump reduction in the depth of the borehole possibility of higher heat extraction from the borehole reduction of the thermal interaction of neighbouring boreholes with heat extraction solar collectors and boreholes may be designed for seasonal heat storage in a system with a group of houses with a common heat distribution network.

The reduction of the thermal interaction is of special interest in densely populated dwelling areas, where concern for long-term thermal influence between adjacent boreholes might lead to restrictions on the use of ground heat sources. Ground-source heat pump The heat to a conventional ground source heat pump is taken from boreholes. For single family dwellings, one borehole is normally sufficient but, for higher demand, several boreholes can be linked together. The depth of the borehole varies from 60 to 180 m. In the borehole there is normally a collector consisting of a U-tube heat exchanger with a circulating heat carrier fluid. In ground-source heat pump systems without solar collectors, the heat carrier fluid is normally an antifreeze solution of ethanol/water. This antifreeze liquid cannot be used if the system is connected to solar collectors with high temperatures, due to explosion risks, and a glycol-based rapeseed oil is normally used instead. Solar collectors Depending on the type of solar collectors used in the system, the solar heat can be used in several ways. For unglazed solar collectors, the heat can be used either to increase the temperature to the evaporator or for recharging the borehole. The simplest way is to connect the solar collector to the return pipe from the evaporator back to the borehole. Figure 2.4.9 shows one system available on the market. When using glazed solar collectors, one possible system is to use the solar collectors only for domestic hot water as shown in Figure 2.4.10. In this system the heat pump is used for all of the space heating and as auxiliary heating for the domestic hot water, when the solar collector is not able to meet the total demand. The operating time of the heat pump decreases, as the solar collector produces the hot water during the summer and the heat pump can be shut off. This gives the borehole a natural recharge and may extend the life of the heat pump, as summer operation with many starts and stops is reduced to a minimum. The seasonal performance factor (SPF) of the system also increases, as the heat pump has a shorter operation time and because the temperature in the borehole is higher than it would be in a conventional system without solar collectors.

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Figure 2.4.9 - Unglazed solar collector recharching the borehole

Figure 2.4.10 - System with a heat pump and glazed solar collectors, used only for heating domestic hot water

2.4.4

Socio-economic aspects

Making use of what is normally waste heat through integrated energy systems (IES) for cooling, heating, and power (CHP) meets the same building electrical and thermal loads with much lower input of fossil fuels, yielding very high resource efficiencies. Opportunities for further advancements in absorption technologies exist, particularly for expanding integration of energy systems through combined heating, cooling, and power applications achieving energy efficiency approaching 80%. The main barrier from the technical point of view with respect to electric driven chillers is a lower COP. But from a global primary energy consumption perspective taking into account the primary energy to generate the consumed energy the difference in COP is not so high. The other commonly mentioned barrier is their relatively higher cost with respect to compression chillers. In this case it is also important to analyse the whole system including the total cost of the CHP system including the absorption chiller and the alternative cost including the compression one. The beneficial effect of the absorption chiller on the whole combined heating and cooling plant considering not only the operation but the design make the differences in investment and operation cost minimal or favourable to absorption systems. The choice of the cooling technology to be integrated with the cogeneration system is highly dependent on the balance of heating, cooling and electric loads, the relative economic values of cooling, heating and electricity and many other site-specific factors. Adsorption systems have lower thermodynamic efficiencies (lower COP) than absorption systems. Their main advantage is that they can be driven by a lower heat source supply temperatures, which makes them applicable to a wider range of waste heat applications than the majority of absorption systems. If costs are low enough, they could compete with small-scale absorption heat pumps. Other

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possible applications are transport refrigeration and cooling and food preservation in remote areas (e.g. solar cooling). Also, vehicle air conditioning is another potential.

2.4.5

Design, simulation and optimisation tools

The software well adapted to the simulation and analysis of thermal cooling systems includes: Absim ABSIM is a modular computer code for simulation of absorption systems. This modular code is based on unit subroutines containing the governing equations for the system's components and on property subroutines containing thermodynamic properties of the working fluids. Eleven absorption fluids are presently available in the code's property database, and twelve units are available to compose practically every absorption cycle of interest. ABSIM may be used for evaluating new cycles and working fluids and to investigate a system's behavior in off-design conditions, to analyse experimental data, and to perform preliminary design optimisation. A graphical user interface enables the user to draw the cycle diagram on the computer screen, enter the input data interactively, run the program, and view the results either in the form of a table or superimposed on the cycle diagram. Special utilities enable the user to plot the results and to produce a PTX diagram of the cycle. Equation Enginering Solver The basic function provided by EES is the numerical solution of a set of algebraic equations. EES can also be used to solve differential and integral equations, do optimization, provide uncertainty analyses and linear and non-linear regression, convert units and check unit consistency and generate publication-quality plots. Built-in functions are provided for thermodynamic and transport properties of many substances, including steam, air, refrigerants, cryogenic fluids, JANAF table gases, hydrocarbons and psychrometrics. Additional property data can be added. EES also allows userwritten functions, procedures, modules, and tabular data. Other software of more general application can also be used for thermal cooling systems, such as, Aspen Plus or Matlab. A third group of software could include research home-made models using different programming languages such as Fortran or Visual Basic developed by research groups in many universities or in research centres.

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Hydropower systems (Zafh.net) Analysis of technical aspects

Description of the units and selection of components, efficiencies, environmental impact, control systems, compatibility with demand, maintenance, barriers for their implementation, etc Overview Hydropower plants whether small or big in size convert hydrostatic energy in mechanical energy. Nowadays mostly all systems are combined with a generator and used for electricity production (Figure 2.5.-1). The main components are the reservoir, the pressure piping and as the most important components regarding efficiency, turbine and generator.Large modern water turbines operate at mechanical efficiencies greater than 90%. Water turbines are divided into two groups: reaction turbines and impulse turbines.

Figure 2.5.-1: Kaplan turbine and electrical generator cut-away view. Reaction turbines Reaction turbines are acted on by water, which changes pressure as it moves through the turbine and gives up its energy. They must be encased to contain the water pressure (or suction), or they must be fully submerged in the water flow. Most water turbines in use are reaction turbines. They are used in low and medium head applications. Impulse turbines Impulse turbines change the velocity of a water jet. The jet impinges on the turbine's curved blades which reverse the flow. The resulting change in momentum (impulse) causes a force on the turbine blades. Since the turbine is spinning, the force acts through a distance (work) and the diverted water flow is left with diminished energy. Prior to hitting the turbine blades, the water's pressure (potential energy) is converted to kinetic energy by a nozzle and focused on the turbine. No pressure change occurs at the turbine blades, and the turbine doesn't require housing for operation. Impulse turbines are most often used in very high head applications. Power The power calculation is carried out as follows:

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where: •

P = power (J/s or watts)

•

η = turbine efficiency

•

ρ = density of water (kg/m3)

•

g = acceleration of gravity (9.81 m/s2)

•

h = head (m). For still water, this is the difference in height between the inlet and outlet surfaces. Moving water has an additional component added to account for the kinetic energy of the flow. The total head equals the pressure head plus velocity head.

•

= flow rate (m3/s)

Pumped storage Some water turbines are designed for Pumped storage hydroelectricity. They can reverse flow and operate as a pump to fill a high reservoir during off-peak electrical hours, and then revert to a turbine for power generation during peak electrical demand. This type of turbine is usually a Deriaz or Francis in design. Large modern water turbines operate at mechanical efficiencies greater than 90%. Types of water turbines Reaction turbines: • Francis •

Kaplan, Propeller, Bulb, Tube, Straflo

•

Tyson

•

Water wheel

Impulse turbines: • Pelton •

Turgo

•

Michell-Banki (Crossflow or Ossberger turbine)

Design and application

Figure 2.5.-2: Overview of turbine design according to head and flow rate Turbine selection is based mostly on the available water head, and less so on the available flow rate. In general, impulse turbines are used for high head sites, and reaction turbines are used for low head

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sites. Kaplan turbines are well-adapted to wide ranges of flow or head conditions, since their peak efficiency can be achieved over a wide range of flow conditions. Small turbines (mostly under 10 MW) may have horizontal shafts, and even fairly large bulb-type turbines up to 100 MW or so may be horizontal. Very large Francis and Kaplan machines usually have vertical shafts because this makes best use of the available head, and makes installation of a generator more economical. Pelton wheels may be either vertical or horizontal shaft machines because the size of the machine is so much less than the available head. Some impulse turbines use multiple water jets per runner to increase specific speed and balance shaft thrust. Typical range of heads •

Kaplan

•

Francis

10 < H < 350

•

Pelton

50 < H < 1300

•

Turgo

2 < H < 40 (H = head in meters)

50 < H < 250

Maintenance

Figure 2.5.-4: Francis turbine showing cavitation pitting, fatigue cracking. Turbines are designed to run for decades with very little maintenance of the main elements; overhaul intervals are on the order of several years. Maintenance of the runners and parts exposed to water include removal, inspection, and repair of worn parts. Normal wear and tear is pitting from cavitation, fatigue cracking, and abrasion from suspended solids in the water. Steel elements are repaired by welding, usually with stainless steel rod. Damage areas are cut or ground out, then welding back up to their original or an improved profile. Old turbine runners may have a significant amount of stainless steel added this way by the end of their lifetime. Elaborate welding procedures may be used to achieve the highest quality repairs. Other elements requiring inspection and repair during overhauls include bearings, packing box and shaft sleeves, servomotors, cooling systems for the bearings and generator coils, seal rings, wicket gate linkage elements and all surfaces. Environmental impact Water turbines have had both positive and negative impacts on the environment. They are one of the cleanest producers of power, replacing the burning of fossil fuels and eliminating nuclear waste. They use a renewable energy source and are designed to operate for decades. They produce significant amounts of the world's electrical supply. Historically there have also been negative consequences. The rotating blades or gated runners of water turbines can interrupt the natural ecology of rivers, killing fish, stopping migrations, and disrupting peoples' livelihoods. Since the late 20th century, it has been possible to construct hydropower systems that divert fish and other organisms away from turbine

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intakes without significant damage or loss of power; such systems require less cleaning but are substantially more expensive to construct. Freshwater turbine of the Scharnhauser Park A 67 kW turbine pump will be installed at an elevated fresh water tank in Scharnhauser Park. The electricity produced will be fed into the grid. General specifications: Technical data turbine Throughput Head Revolution Power

Data 2005 Ritz 50265 288 m³/h 112.4 m 1510 1/min 67 kW

Technical data generator Voltage/frequency Power

Rotary current asynchronous generator 400V / 50 Hz 75 kW

investment

Approx. 80.000€

2.5.2

Concepts for integration with other technologies and into networks

The freshwater turbine of the Scharnhauser Park will be directly integrated into the freshwater supply system of the urban site. It lowers freshwater pressure to the necessary level for the domestic tabs and produces up to 75 kW of electric power, which will be fed into the grid system with payment per kWh according to the German energy feeding law for renewable energies.

2.5.3

Socio-economic aspects

The master advantage of hydro systems is elimination of the cost of fuel. Hydroelectric plants are immune to price increases for fossil fuels such as oil, natural gas or coal, and do not require imported fuel. Hydroelectric plants tend to have longer lives than fuel-fired generation, with some plants now in service having been built 50 to 100 years ago. Labor cost also tends to be low since plants are generally heavily automated and have few personnel on site during normal operation. Pumped storage plants currently provide the most significant means of storage of energy on a scale useful for a utility, allowing low-value generation in off-peak times (which occurs because fossil-fuel plants cannot be entirely shut down on a daily basis) to be used to store water that can be released during high load daily peaks. Operation of pumped-storage plants improves the daily load factor of the generation system. Reservoirs created by hydroelectric schemes often provide excellent leisure facilities for water sports, and become tourist attractions in themselves. Multi-use dams installed for irrigation, flood control, or recreation, may have a hydroelectric plant added with relatively low construction cost, providing a useful revenue stream to offset the cost of dam operation. In practice, the utilization of stored water is sometimes complicated by demand for irrigation which may occur out of phase with peak electricity demand. Times of drought can cause severe problems, since water replenishment rates may not keep up with desired usage rates. Minimum discharge requirements represent an efficiency loss for the station if it is uneconomic to install a small turbine unit for that flow.

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Concerns have been raised by environmentalists that large hydroelectric projects might be disruptive to surrounding aquatic ecosystems. Generation of hydroelectric power can also have an impact on the downstream river environment. First, water exiting a turbine usually contains very little suspended sediment, which can lead to scouring of river beds and loss of riverbanks. Second, since turbines are often opened intermittently, rapid or even daily fluctuations in river flow are observed. Finally, water exiting from turbines is typically much colder than the pre-dam water, which can change aquatic faunal populations, including endangered species. The reservoirs of hydroelectric power plants in tropical regions may produce substantial amounts of methane and carbon dioxide. This is due to plant material in newly flooded and re-flooded areas being inundated with water, decaying in an anaerobic environment, and forming methane, a very potent greenhouse gas. The methane is released into the atmosphere once the water is discharged from the dam and turns the turbines. According to the World Commission on Dams report, where the reservoir is large compared to the generating capacity (less than 100 watts per square meter of surface area) and no clearing of the forests in the area was undertaken prior to impoundment of the reservoir, greenhouse gas emissions from the reservoir may be higher than those of a conventional oil-fired thermal generation plant. In boreal reservoirs of Canada and Northern Europe, however, greenhouse gas emissions are typically only 2 to 8% of any kind of conventional thermal generation. Another disadvantage of hydroelectric dams is the need to relocate the people living where the reservoirs are planned. In many cases, no amount of compensation can replace ancestral and cultural attachments to places that have spiritual value to the displaced population. Additionally, historically and culturally important sites can be flooded and lost. Some hydroelectric projects also utilize canals, typically to divert a river at a shallower gradient to increase the head of the scheme. In some cases, the entire river may be diverted leaving a dry riverbed. For the freshwater turbine planned to be installed at the Scharnhauser Park the above mentioned disadvantages are obsolete. The turbine will be integrated into the freshwater system to reduce the pressure at the tabs and simultaneously produce green electric energy

2.5.4

Design, simulation and optimisation tools

Specific speed The specific speed, ns, of a turbine characterizes the turbine's shape in a way that is not related to its size. This allows a new turbine design to be scaled from an existing design of known performance. The specific speed is also the main criteria for matching a specific hydro site with the correct turbine type. The specific speed of a turbine can also be defined as the speed of an ideal, geometrically similar turbine, which yields one unit of power for one unit of head. The specific speed of a turbine is given by the manufacturer (along with other ratings) and will always refer to the point of maximum efficiency. This allows accurate calculations to be made of the turbine's performance for a range heads and flows.

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Figure 2.5.-3: Turbine shape selection in relation to specific speed (European Community's 'Layman's Guidebook) Specific speed calculation:

(dimensioned parameter), n = rpm

(dimensionless parameter), Ω = angular velocity (radians/second) •

P = power (J/s or watts)

•

ρ = density of water (kg/m3)

•

g = acceleration of gravity (9.81 m/s2)

•

h = head (m). For still water, this is the difference in height between the inlet and outlet surfaces. Moving water has an additional component added to account for the kinetic energy of the flow. The total head equals the pressure head plus velocity head.

•

n = rpm

Given a flow and head for a specific hydro site, and the rpm requirement of the generator, calculate the specific speed. The result is the main criteria for turbine selection. The specific speed is also the starting point for analytical design of a new turbine. Once the desired specific speed is known, basic dimensions of the turbine parts can be easily be calculated. Affinity Laws allow the output of a turbine to be predicted based on model tests. A miniature replica of a proposed design, about 0.3 m in diameter, can be tested and the laboratory measurements applied to the final application with high confidence. Affinity laws are derived by requiring similitude between the test model and the application. Flow through the turbine is controlled either by a large valve or by wicket gates arranged around the outside of the turbine runner. Differential head and flow can be plotted for a number of different values of gate opening, producing a hill diagram used to show the efficiency of the turbine at varying conditions. Affinity Laws allow the output of a turbine to be predicted based on model tests. A miniature replica of a proposed design, about one foot (0.3 m) in diameter, can be tested and the laboratory measurements applied to the final application with high confidence. Affinity laws are derived by requiring similitude between the test model and the application. The laws can be summarised as

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follows Flow rate is directly proportional to turbine impeller speed, e.g. F1 / F2 = rpm1 / rpm2 where F = flow rate, and rpm = impeller speed The ratio of Heads is directly proportional to the square of the ratio of turbine impeller speeds, e.g. H1 / H2 = (rpm1 / rpm2)2 where H = Head, and rpm = impeller speed The ratio of turbine powers is directly proportional to the cube of the ratio of turbine impeller speeds, e.g. P1 / P2 = (rpm1 / rpm2)3 where P = Power, and rpm = impeller speed Flow through the turbine is controlled either by a large valve or by wicket gates arranged around the outside of the turbine runner. Differential head and flow can be plotted for a number of different values of gate opening, producing a hill diagram used to show the efficiency of the turbine at varying conditions. The following design and simulation software is available: •

PC-hydro, a DOS software package to calculate penstock losses

•

JLAHydro by Jean-Luc Willot to evaluate the flow discharge at a measurement weir using the overflow method, slope calculations for a trapezoidal channel, diameter calculations for a penstock, sizing of transmission cables together with the selection of the optimal turbine from the JLA turbine series

•

PELTON SIZING SPREADSHEET by Joseph Hartvigsen

•

impulse turbine characteristis by Joseph Hartvigsen

•

TURBNPRO Version 3, a windows software package, which determines hydro turbine sizing and type selection based on actual site data can be entered. Typical performance and dimensional characteristics of the hydroturbine size/type selected are developed by the program and may be used to assess the site energy potential. Advantages, disadvantages and limitations of the various water turbine configurations/ arrangements are discussed and the impact of cavitation on hydro turbine sizing and type selection is covered.

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Gas Cogeneration (CREVER, CRF) 2.5.5

Analysis of technical aspects

2.5.5.1 Description of the units and selection of components Cogeneration is the simultaneous production of power and heat, it is also known as Combined Heat and Power (CHP). The principle behind cogeneration is to use heat produced during power generation for industrial uses or home heating; in this way the efficiency in primary energy usage can exceed 90%. The cogeneration theme is cross-cutting with Distributed Generation issues. Because transporting electricity over long distances is easier and cheaper than transporting heat, cogeneration installations are usually sited as near as possible to the place where the heat is consumed. A further saving of losses (5% to 10%) due to power transmission and distribution over the electricity grid from remote power station is possible for the share of electricity consumed near the cogeneration source. Cogeneration encompasses a range of technologies, but will always include an electricity generator and a heat recovery system. Cogeneration plant consists of four basic elements: • • • •

A prime mover (engine); An electricity generator; A heat recovery system; A control system.

The prime mover drives the electricity generator, producing power, waste heat is recovered through the recovering system. Cogeneration typically achieves 25 to 35 % reduction in primary energy usage compared with electricity-only generation and heat-only boilers. This can allow the host organisation to make substantial savings in costs and emissions where there is a suitable heat load. The typical prime movers that can be used for cogeneration applications are the following: -

Reciprocating engines Gas turbines Steam turbines Combined cycles Micro gas turbines Fuel cells Stirling engines

In the following sub-sections technical detail about these technologies will be provided.

2.5.5.1.1 Reciprocating Engines Operating Principles A reciprocating engine, also often known as a piston engine, is an engine that utilises one or more pistons in order to convert pressure into a rotating motion. Reciprocating internal combustion engines represent a widespread and mature technology for power generation. Reciprocating engines are used for all types of power generation, from small portable generators to larger industrial engines of several megawatts. Gas-fired reciprocating engines are well suited for CHP units in commercial and light industrial applications of less than 5 MW. Smaller engine systems produce hot water. Larger systems can be designed to produce low-pressure steam.

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Spark ignition engines for power generation use natural gas as the preferred fuel, although they can be set up to run on propane or gasoline. Diesel-cycle, compression ignition engines operate on diesel fuel or heavy oil, or can be set up in a dual-fuel configuration that can burn primarily natural gas with a small amount of diesel pilot fuel. The emissions profiles of reciprocating engines have been improved significantly in recent years by the use of exhaust catalysts and through better design and control of the combustion process. The reciprocating engines are available usually in sizes of 0,015-6 MWe but in some cases even higher. In the particular case of spark ignition engines can be found sizes until 5MW. For liquid fuels such as fuel oil the maximum capacity is up to 20 MWe. The advantages of this system are:      

Low first cost High availability Good response in load changes. Efficiency less sensitive to low loads than gas turbines. Versatility by many engines connected in parallel Reciprocating engines start rapidly and deal well with part loads, flexibility from 30% to 100% with high efficiency. Proven reliability when properly maintained

The disadvantages are:      

Must be cooled, even if the heat recovered is not reusable Relatively high noise levels. Relatively high air emissions Need for regular maintenance and High maintenance costs. The heat that can be potentially recovered is distributed in different sources (mainly engine cooling, oil cooling and exhaust gas heat) Reciprocating engines are more technically complex than turbines.

Internal Combustion Engines Technology There are two basic types of reciprocating engines: spark ignition (SI) and compression ignition (CI). The essential mechanical components of Otto-cycle (SI) and Diesel-cycle (CI) engines are the same. Both have cylindrical combustion chambers, in which pistons travel the length of the cylinders. Connecting rods transform the linear motion of the pistons into the rotary motion of the crankshaft. The primary difference between the Otto and Diesel cycles is the method of igniting the fuel. Ottocycle engines use a spark plug to ignite the premixed air-fuel mixture after it is introduced into the cylinder. Diesel-cycle engines compress the air introduced into the cylinder to a high pressure, raising its temperature above the auto-ignition temperature of the fuel, which is then injected into the cylinder at high pressure. There are two type of gas fired internal combustion engines: Natural Gas Spark-Ignition Engines Natural gas spark-ignition engines are typically less efficient than diesel engines because of their lower compression ratios. However, large, high-performance lean-burn engine efficiencies approach those of diesel engines of the same size.

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Many natural gas spark-ignition engines are derived from diesel engines, however, natural gas sparkignition engines operate at lower brake mean effective pressure (BMEP2) and peak pressure levels. Due to the derating effects from lower BMEP, the spark-ignition versions of diesel engines often produce only 60% to 80% of the power output of the parent diesel engine. Manufacturers often enlarge cylinder bore about 5% to 10% to increase the power, but this is only partial compensation for reduced BMEP. However, by operating at lower cylinder pressure and bearing loads, as well as in the cleaner combustion environment of natural gas, spark ignition engines generally offer the benefits of extended component life and lower emissions than their diesel parents. Dual-Fuel Engines Dual-fuel engines are diesel-cycle compression ignition engines predominantly fuelled by natural gas with a small percentage of diesel oil used as a “pilot” fuel. Compression heating auto-ignites the pilot fuel and initiates combustion of the main fuel-air mixture. Pilot fuel minimum requirements can range from 1% to 20% of total fuel input. Dual-fuel operation is a combination of Diesel and Otto-cycle operation, approaching the Otto cycle more closely at low pilot-fuel percentages. Most dual-fuel engines can be switched between dual-fuel and 100% diesel operation while the engine is operating at any output level. Reciprocating engines can be classified as high, medium, or low speed. Engine-driven electric generators typically must run at fixed speeds and maintain a constant 50 Hertz (Hz) frequency, which dictates the required engine operating speed (i.e. a 50 Hz generator requires engine speeds of 1,000, 1,500 or 3,000 rpm according to the number of poles of the generator: the higher the number of poles the lower the engine speed). The specific power output of engines is proportional to engine speed, resulting in lower costs for small high speed engines. However, the cost benefits of high speed engines must be weighed against other factors. Smaller high speed engines tend to have lower efficiencies than larger engines, due in part to the higher surface area to volume ratios of small cylinders, which result in higher heat losses. Also, high speed engines tend to have shorter periods between both minor and major overhauls. These factors often are less important than capital cost for limited duty cycle applications, such as standby and emergency. Performance and efficiency enhancements of internal combustion engines can be obtained by: Adjusting Brake Mean Effective Pressure (BMEP) and Engine Speed Engine power is related to engine speed and the Brake Mean Effective Pressure (BMEP). Reciprocating engines can produce more power by increasing engine speed and/or the pressure inside the engine’s cylinders. High BMEP levels indicate high specific power output, and generally result in improved efficiency and lower specific capital costs and maintenance costs. However, higher BMEP increases thermal and mechanical stresses within the engine combustion chamber and drive-train components. Turbocharging Essentially, all modern industrial engines above 300 kW are turbocharged to achieve higher power densities. A turbocharger is an intake air compressor driven by a turbine. The turbine is powered by the hot exhaust gases. Turbocharging forces more air into the cylinders, increasing engine output. Cylinder pressure and temperature normally increase as a result of turbocharging, Heat exchangers (called after-coolers or inter-coolers) are often used to cool the combustion air exiting the turbocharger 2

Brake mean effective pressure (BMEP) can be regarded as the “average” cylinder pressure on the piston during the power stroke and is a measure of the specific loads on the engine. BMEP is generally an indication of how well the engine utilizes total cylinder displacement in creating useful work.

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compressor to keep the temperature of the air to the engine under a specified limit and to increase the air density. Efficiencies Electric efficiencies of natural gas engines range from 28% LHV3 for stoichiometric engines 4 smaller than 100 kW to more than 40% LHV for larger lean-burn engines 5 (> 2 MW). Waste heat can be recovered from the engine exhaust and from the engine cooling systems to produce either hot water or low-pressure steam for CHP applications. Overall, CHP system efficiencies (electricity and useful thermal energy) of 70% to 80% are routinely achieved with natural gas-engine systems in applications with electrical and heat loads appropriately in balance. Part-Load Performance In power generation and CHP applications, reciprocating engines generally drive synchronous generators at constant speed to produce steady alternating current (AC) power. As load is reduced, the heat rate of spark-ignition engines increases and efficiency decreases. The efficiency at 50% load is approximately 8% to 10% less than full-load efficiency. As the load decreases further, the curve becomes steeper. Gas engines compare favourably to gas turbines, which typically experience efficiency decreases of 15% to 25% at half-load conditions. Diesel engines exhibit more favourable part-load characteristics than spark-ignition engines. The efficiency curve for diesel engines is comparatively flat between 50% and 100% load. Effects of Ambient Conditions on Performance Reciprocating engines are generally rated at ISO6 conditions of 25°C and 0.987 atmospheres (1 bar) pressure. Like gas turbines, reciprocating engine performance (both output and efficiency) degrades with the increase of ambient temperature or site elevation. While the effect on gas turbines can be significant, it is less so on engines. As a rule-of-thumb, reciprocating engine power is reduced by approximately 4% per 300m of altitude above 300m, while efficiency decreases about 1% for every 300m of altitude. Both engine power and efficiency typically decrease 2% for every 6°C above 43°C. However, each engine model has its own performance characteristics, which depend on engine-design features, such as turbocharger and intercooler selection. Heat Recovery Most of the waste heat is available in the engine exhaust and jacket water coolant (figure 2.6.1), while smaller amounts can be recovered from the lube oil cooler and the charge air after-cooler if so equipped (i.e. in turbocharged engines). In typical engines, heat in the jacket water or coolant accounts for up to 30% of the energy input and is capable of producing 90°C to 99°C hot water. Some engines, such as those with highpressure or ebullient cooling systems, can operate with water jacket temperatures up to 130°C. Engine exhaust heat represents 30% to 50% of the available waste heat. Exhaust temperatures of 450°C to 650°F are typical. By recovering heat from the cooling systems and exhaust, approximately

3

LHV stands for Lower Heating Value of the fuel, which does not take into account the heat of condensation of the water vapor in the combustion products. Higher Heating Value (HHV) includes the heat of condensation of the water vapor in the combustion products; it is greater than LHV by approximately 10%. 4

Stoichiometric engines are designed to burn the chemically correct proportions of fuel and air needed for complete combustion, i.e., there is no excess fuel or oxygen after combustion. 5 6

In lean-burn engines, the fuel-air mixture contains more air than is needed for complete combustion. International Organization for Standards.

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70% to 80% of the fuel's energy can be effectively utilized to produce both power and useful thermal energy.

Figure 2.6.1 - Scheme of reciprocating internal combustion engine Availability, Life and Maintenance Although reciprocating engines are generally perceived as maintenance-intensive, they can provide high levels of availability, even in high-load-factor applications. While natural gas engine availabilities vary with engine type, speed, and fuel quality, the major engine manufacturers estimate engine availability to be 96% for continuous duty applications. Improvements in diagnostics and controls are expected to increase availability in the next years. The manufacturers estimate that the forced outage to scheduled outage rate ratio is currently 2 to 1. The use of multiple units or back-up units at a site can further increase the availability and reliability of the overall cogeneration facility. The service life of natural gas reciprocating engine systems is estimated to be 20 years, if they receive several minor and at least one major overhaul during that time. Oil analysis to monitor engine wear is part of most preventive maintenance programs. A top-end overhaul, which entails rebuilding cylinder heads and turbochargers, is generally recommended at between 8,000 and 30,000 hours of operation. A major overhaul is performed after 30,000 to 72,000 hours of operation and involves piston replacement, crankshaft inspection, bearings, and seals. Fuels Spark-ignition engines can be operated on a variety of alternative gaseous fuels, including: • Liquefied petroleum gas (LPG): propane and butane mixtures. • Sour gas: unprocessed natural gas as it comes directly from the gas well. • Biogas: combustible gases produced from biological degradation of organic wastes, such as landfill gas, sewage digester gas, and animal waste digester gas. • Industrial waste gases: flare gases from landfills and gases coming from refineries, chemical plants, and steel mills processes. • Manufactured gases (also called Syngas): typically low and medium heating value gas produced by gasification or pyrolysis processes.

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Factors that impact the operation of a spark-ignition engine with alternative gaseous fuels include: • Volumetric heating value: since engine fuel is delivered on a volume basis, fuel volume into the engine increases as heating value decreases, causing engine derating on fuels with very low heating value. Derating is more pronounced with naturally aspirated engines, and may be compensated partly or totally by turbocharging the engine, depending on air requirements. • Auto-ignition characteristics and detonation tendency. • Contaminants that may impact engine component life or engine maintenance, or result in air pollutant emissions that require additional control measures. • Hydrogen content, which may require special measures (generally if hydrogen content by volume is greater than 5%) because of hydrogen’s high flammability, flame speed, and heatrelease characteristics. Contaminants are a concern with many waste fuels. If acid gas components are present and the exhaust temperature is allowed to drop below the acid dew point in the exhaust system, the acids also can corrode downstream equipment and greatly shorten lube oil life. A substantial fraction of any nitrogen in the fuel will be oxidised into NOx in combustion. Solid particulates must be kept to very low concentrations to prevent corrosion and erosion of combustion chamber and turbocharger components. Various cleaning steps (such as fuel-scrubbing, droplet-separation and filtration) will be required if any fuel contaminant levels exceed manufacturers’ specifications. Landfill gas, in particular, often contains compounds that necessitate pretreatment. Once alternative fuels are treated and made acceptable for use in engines, their emissions performance profiles are similar to natural gas-engine performance. Specifically, the low emissions ratings of leanburn engines usually can be maintained on alternative fuels. Emissions Exhaust emissions are the primary environmental concern with reciprocating engines. The primary pollutants are oxides of nitrogen (NOx), carbon monoxide (CO), and volatile organic compounds (VOCs, unburned or partially burned non-methane hydrocarbons). Concentrations of other pollutants, such as oxides of sulfur (SOx) and particulate matter (PM) are primarily dependent on the fuel used. In general, SOx emissions are an issue only in larger, lowerspeed diesel engines firing heavy oils. Particulate matter (PM) can be an important pollutant for engines that use liquid fuels. NOx emissions are usually the primary concern with natural gas engines. Without exhaust aftertreatment, lean-burn natural gas engines produce the lowest NOx emissions; and diesel engines produce the highest. For any engine there are generally trade offs between low NOx emissions and high efficiency. There are also trade-offs between low NOx emissions and emissions of the products of incomplete combustion (CO and unburned hydrocarbons). There are three main approaches to these trade offs that may come into play, depending on regulations and economics. One approach is to control for lowest NOx accepting a fuel efficiency penalty and possibly higher CO and hydrocarbon emissions. A second option is finding an optimal balance between emissions and efficiency. A third option is to design for highest efficiency and use post-combustion exhaust treatment to control emissions if required for permitting purposes. The emissions characteristics of natural gas SI engines have improved significantly in the past decade through better design and control of the combustion process and through the use of catalytic treatment of exhaust gases. Advanced lean-burn natural gas engines are available that produce untreated NOx levels as low as 50 ppmv @ 15% reference O2 (dry basis). Manufacturers  

Aircogen Ltd (UK), www.aircogen.com Caterpillar (USA), www.caterpillar.com

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Cummins Power Generation (USA), www.cummins.com Deutz AG (Germany), www.detz.com GE Jenbacher (USA, Austria), www.jenbacher.com Wärtsilä (Finland), www.wartsila.com Guascor (Spain), www.guascor.com Man (Germany), www.man-engines.com

And for engines less than 250 kWe:      

Hess Microgen (USA), www.hessmicrogen.com EAW Energieanlagenbau (Germany), www.eaw-energieanlagenbau.de EQTEC Iberia (Spain), www.eqtec.es Senertec – Dachs (Germany), www.senertec.com EC Power Ltd (UK) www.ecpower.co.uk Powerplus Technologies Gmbh – Ecopower (Germany), www.ecopower.de

Future R&D, expectations and timeline  

 

High Efficiency- Target fuel-to-electricity conversion efficiency (LHV) is 50 % by 2010. Environment – Engine improvements in efficiency, combustion strategy, and emissions reductions will substantially reduce overall emissions to the environments. The NOx target for the advanced natural gas reciprocating engine is 0.1g/hp-hr, a 95% decrease from today's NOx emissions rate with no deterioration of other criteria. Fuel Flexibility – Natural gas-fired engines are to be adapted to handle biogas, renewables, propane and hydrogen, as well as dual fuel capabilities. Other R&D directions include: new turbocharger methods, heat recovery equipment specific to the reciprocating engine, alternate ignition system, emission-control technologies, improved generator technology, frequency inverters, controls/sensors, higher compression ratio, and dedicated naturalgas cylinder heads.

2.5.5.1.2 Gas Turbines Operating Principles A gas turbine is a heat engine that uses high-temperature, high-pressure gas as the working fluid. Part of the heat supplied by the gas is converted directly into mechanical work. High-temperature, highpressure gas rushes out of the combustor and pushes against the turbine blades, causing them to rotate. In most cases, hot gas is produced by burning a fuel in air. This is why gas turbines are often referred to as "combustion" turbines. Gas turbines for distributed generation applications are an established technology in sizes from several hundred kilowatts up to about 50 MW (sizes up to 250 MW, suitable to centralized generation ,are available). Gas turbines can be set up to burn natural gas, a variety of petroleum fuels or can have a dual-fuel configuration. Maintenance costs per unit of power output are among the lowest of DG technology options. An important advantage of CHP using gas turbines is the high-quality waste heat available in the exhaust gas. The high-temperature exhaust gas is suitable for generating high-pressure steam, making gas turbines a preferred CHP technology for many industrial processes. Low maintenance and high-quality waste heat make gas turbines an excellent solution for industrial or commercial CHP applications larger than 5 MW. Technical and economic improvements in small turbine technology are pushing the economic range into smaller sizes as well. Gas turbine emissions can be controlled to very low levels.

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Gas turbines offer low maintenance cost, proven reliability when properly operated, high quality waste heat and low air emissions. Drawbacks of gas turbines include bad partial load efficiencies and high sensitivity to ambient conditions. Gas turbine systems operate on the thermodynamic cycle known as the Brayton cycle. In a Brayton cycle, atmospheric air is compressed, heated, and then expanded. The hot pressurised air in the expander turn a series of fan blades mounted on a shaft. The shaft power produced by the expander (also called the turbine) is partially consumed by the compressor and the rest is used to generate electrical power. The power produced by an expansion turbine or consumed by a compressor is proportional to the absolute temperature of the gas passing through the device. Consequently, it is advantageous to operate the expansion turbine at the highest practical temperature consistent with economic materials and internal blade-cooling technology and to operate the compressor with inlet airflow temperature as low as possible. As technology advances permit higher turbine inlet temperature, the optimum pressure ratio also increases. Higher temperatures and pressure ratios result in higher efficiency and higher specific power output (power out per unit of fuel energy in). Several variations of the Brayton cycle are in use today. Fuel consumption may be decreased by preheating the compressed air with heat from the turbine exhaust using a recuperator or regenerator, the compressor work may be reduced and net power increased by using intercooling or precooling the inlet air. Gas turbine exhaust is quite hot, up to 430°C to 480°C for smaller industrial turbines and up to 590°C for some new, large central station utility machines and aeroderivative turbines. The exhaust may be used to raise steam in a boiler to generate additional power in a combined cycle.

Figure 2.6.2 - Cogeneration system with open-cycle gas turbine (Source: Educogen Project)

Gas turbines can be classified in two main families: Aeroderivative gas turbines These are turbines adapted for stationary power from jet and turboshaft aircraft engines. While these turbines are lightweight and thermally efficient, they are usually more expensive than products designed and built exclusively for stationary applications. The largest aeroderivative turbines available are approximately 40 MW in capacity. Many aeroderivative gas turbines for stationary use operate with high compression ratios, requiring a highpressure external fuel gas compressor. With advanced system developments, aeroderivative turbines are approaching 45% simple-cycle efficiencies (LHV).

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Industrial (or frame) gas turbines These turbines were developed exclusively for stationary power generation and are available in the 1 to 250 MW capacity range. They are generally less expensive, more rugged, can operate longer between overhauls, and are better-suited for continuous base-load operation than aeroderivative turbines. However, they are less efficient and much heavier. Industrial gas turbines generally have more modest compression ratios and often do not require an external fuel gas compressor. Industrial gas turbines are approaching simple-cycle efficiencies of approximately 40% (LHV) and combined-cycle efficiencies of 60%. While rotational speed generally increases as physical size decreases, there is no single rule relating rotational speed to power size. Since generated power is required to have 50 Hz frequency, gas turbines running at high rpm values require a gearbox to reduce generator speed, or power electronics (i.e. inverters) to convert high frequency AC power output to usable 50 Hz power (this is usually necessary with micro-turbines, which are not the discussed in this report). Several technologies that increase the output power and/or the efficiency of gas turbines have been developed. Recuperator Fuel use can be reduced (and hence efficiency improved) by using a heat exchanger called a recuperator which uses the hot turbine exhaust to preheat the compressed air entering the turbine combustor. Depending on gas turbine operating parameters, a recuperator can add up to 10 percentage points in machine efficiency. However, since there is increased pressure drop on both the compressed air and turbine exhaust sides of the recuperator, power output is typically reduced by 10% to 15%. Recuperators also lower the temperature of the gas turbine exhaust, reducing the turbine’s effectiveness in CHP applications. Recuperators are expensive. Their cost can normally be justified only when the gas turbine operates for many full-power hours per year. Intercooler Intercoolers are used to increase gas turbine power by dividing the compressor into two sections and cooling the compressed air leaving the first compressor section before it enters the second section. Intercoolers increase net power appreciably; but since the temperature of the gas delivered by the entire compressor is now cooler, more heat has to be supplied by the combustor. Gas turbine efficiency does not change significantly with the use of intercooling. Efficiencies The thermal efficiency of the Brayton cycle is a function of pressure ratio, ambient air temperature, turbine inlet air temperature, the efficiency of the compressor and turbine elements, turbine bladecooling requirements, and any performance enhancements, such as recuperation, intercooling, inlet air cooling, reheat, or steam injection. Many of these parameters have been improved over time, making newer turbines usually more efficient. Usually larger combustion turbines have higher electrical efficiencies. Higher electrical efficiencies mean that there is less thermal energy available to produce steam, leading to higher ratios of power to heat for large CHP systems. Electric efficiencies range from 24% for 1 MW turbines to 41% for large turbines (40 MW) with total CHP efficiencies ranging from 65% to 72% respectively. Gas turbines need a minimum fuel supply gas pressure of about 7 bar for the smallest turbines and substantially higher pressures for larger turbines and aeroderivative machines. The cost and power consumption of the fuel gas compressor can be significant, depending on the supply pressure of the gas being delivered to the site. Typically, required supply pressures increase with gas turbine size.

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Part-Load Performance When less than full power is required from a gas turbine, the output is reduced by lowering the turbine inlet temperature. In addition to reducing power, this change in operating conditions also reduces efficiency. Typically gas turbines efficiency decreases of 15% to 25% at half-load conditions. Effects of Ambient Conditions on Performance The ambient conditions under which a gas turbine operates noticeably affect both power output and efficiency. At higher inlet air temperatures, both the power and efficiency are lower. The power decreases due to the decreased air mass flow rate (the density of air declines as temperature increases), and the efficiency decreases because the compressor requires more power to compress warmer air. Conversely, the power and efficiency are higher for lower inlet air temperatures. By comparing the variation in power and efficiency for a gas turbine as functions of ambient temperature to the reference International Organization for Standards (ISO) condition at sea level and 15°C, one find that at inlet air temperatures of near 38°C power output can be as low as 90% of ISOrated power for typical gas turbines. At cooler temperatures of 5 to 10°C, power output can be as high as 105% of ISO-rated power. The density of air decreases with altitude; and, consequently, power output decreases. Efficiency remains essentially constant with altitude. The decreased power and efficiency caused by high ambient air temperatures can be mitigated by any of several approaches to inlet air cooling, including: refrigeration, evaporative cooling, and thermal energy storage using off-peak cooling. Refrigeration cooling With refrigeration cooling, either a compression-driven or thermally activated (absorption chiller) refrigeration cycle cools the inlet air through a heat exchanger. The heat exchanger in the inlet air stream causes an additional pressure drop in the air entering the compressor, thereby slightly lowering cycle power and efficiency. However, with the inlet air now substantially cooler than the ambient air, there is a significant net gain in power and efficiency. Compression refrigeration requires a substantial parasitic power loss if the compressors are driven by electric motors, while thermally activated absorption cooling can utilize waste heat from the gas turbine. However, the complexity and cost of the last approach pose potential drawbacks in many applications. Evaporative cooling Evaporative cooling, which is widely used due to its low capital cost, sprays water directly into the inlet air stream. Evaporation of the water cools the air. Since cooling is limited to the wet bulb air temperature7, evaporative cooling is most effective when the ambient air is dry. Evaporative cooling can consume large quantities of water, which may not be feasible in arid regions. It is offered on a few large gas turbines and is expected to be used more frequently on smaller machines in the future. Thermal energy storage cooling The use of thermal energy storage – typically ice, chilled water, or low-temperature fluids – to

7

This is also known as adiabatic saturation temperature. During the adiabatic saturation process heat leaves the air cooling it and this allows water to evaporate into the air bringing to its saturation (100% humidity). When saturation is occurs water reaches a steay-state temperature, called adiabatic saturation temperature, which is the same temperature reached by saturated air.

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cool inlet air can eliminate most parasitic losses from the augmented power capacity. If on-peak power hours are narrowly defined, i.e., just a few hours per day, thermal energy storage may be a viable option. In that case, the shorter time of energy storage discharge and longer time for daily charging allow for a smaller, less expensive thermal energy storage system. Heat recovery Thermal energy of the exhaust gas is generally 60% to 70% of the inlet fuel energy. The most common use of this energy is for steam generation in unfired or supplementary-fired HRSGs (Heat Recovery Steam Generators). However, the turbine exhaust gases also can be used as a source of direct process energy for unfired or fired process fluid heaters or as preheated combustion air for power boilers. The two most important factors influencing the amount of energy available for steam generation are gas turbine exhaust temperature and HRSG stack temperature. Gas turbine exhaust temperature is set by the turbine firing temperature and turbine pressure ratio. Typically, aeroderivative gas turbines have higher firing temperatures than industrial gas turbines, but the higher pressure ratios in aeroderative gas turbines compensates for the higher firing temperature, so the discharge temperatures of the two turbine types are close, typically in the range of 450 to 510°C. For the same HRSG stack temperature, higher turbine exhaust temperature (i.e. higher HRSG gas inlet temperature) results in more available thermal energy and increased HRSG output. Similarly, lower HRSG stack temperatures reflect a greater amount of energy recovery and higher total system efficiency. Generally, unfired HRSGs can be designed to economically recover approximately 95% of the available energy in the turbine exhaust (the energy released in going from turbine exhaust temperature to the HRSG exhaust temperature). In combined cycles steam generated in HRSG system is adopted to run a steam turbine, increasing overall electricity efficiency (reducing available thermal power output). Supplementary Firing Since gas turbines generally consume little of the available oxygen in the turbine airflow, the oxygen content of the turbine exhaust permits supplementary fuel firing upstream of the HRSG to increase steam production relative to an unfired unit. Supplementary firing can raise the temperature of the gas entering the HRSG to 1300°C and more than double the amount of steam produced by the unit. Since the turbine exhaust gas is essentially preheated combustion air, less fuel is consumed in supplementary firing than would be required for a standalone boiler providing the same incremental steam generation. The efficiency of incremental steam production from supplementary firing above that of an unfired HRSG approaches 100% based on the LHV of the fuel (about 90% HHV efficiency when using natural gas). Supplementary firing also increases system flexibility. Unfired HRSGs are typically convective heat exchangers that respond solely to the exhaust conditions of the gas turbine and do not easily allow for steam flow control. Supplementary firing provides the ability to control steam production rates, independent of the gas turbine operating mode. Availability, Life and Maintenance Many operational conditions affect a gas turbine’s propensity to fail. Frequent starts and stops cause damage which accelerates mechanical failure. On the other hand, gas turbines in steady operation on clean fuels can operate for a year without needing to shut down. Estimated availability of gas turbines in continuous operation on clean gaseous fuels like natural gas exceeds 98%. Use of distillate fuels and other liquid fuels, especially those with contaminants (alkalis, sulfur, and ash), require more frequent shutdowns for preventive maintenance, and this reduces availability.

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The economic life of gas turbine systems is estimated to be 20 years; this includes several major overhauls during that time. Fuels The majority of gas turbines intended for service as stationary power generators is available with combustors equipped to burn natural gas. A typical range of heating values of gaseous fuels acceptable for gas turbines is 35 to 43 MJ per normalized cubic meter, which covers the range of pipeline quality natural gas. Clean liquid fuels are also suitable for use in gas turbines. Special combustors developed by some gas turbine manufacturers can handle cleaned gasified solid and liquid fuels. Burners have been developed for medium heating value fuel (16 to 20 MJ/Nm3), which is produced in oxygen-blown gasifiers, and for low heating values fuel (3 to 5 MJ/Nm3), which is produced in air-blown gasifiers. These special combustors were developed principally for large gas turbines and are not found on small gas turbines. Fuel contaminants, such as ash, alkalis (sodium and potassium), and sulfur result in alkali sulfate deposits, which impede flow, degrade performance, and cause corrosion in the turbine hot section. Fuels are permitted to have only low levels of specified contaminants in them (typically less than 10 ppm total alkalis and single-digit ppm of sulfur). Liquid fuels require their own pumps, flow control, nozzles and mixing systems. Many gas turbines are available with either gas or liquid firing capability. In general, these gas turbines can be converted from one fuel to another quickly. Several gas turbines are equipped for dualfuel firing and can switch fuels with minimal or no interruption. The different heats of combustion result in slightly higher mass flows through the expansion turbine when liquid fuels are used, and thus a very small increase in power and efficiency performance is obtained. Also, the fuel pump power requirements for liquid fuels are less than those of fuel gas booster compressors, thereby further increasing net performance with liquid fuels. Use of liquid fuels, especially heavy fuels and fuels with impurities, radiates heat to the combustor walls significantly more intensely than occurs with clean gaseous fuels, thereby overheating the combustor and transition section walls. Gas turbine combustors operate at pressure levels of 5 to 24 bar. While pipeline pressure of natural gas is higher in interstate transmission lines, the pressure is typically reduced into the cities distribution piping system. Quite often, a fuel gas booster compressor is required to ensure that fuel pressure is adequate for the gas turbine flow control and combustion systems. The cost of the fuel gas booster compressors adds to the installation capital cost. Often, redundant booster compressors are used, because gas turbines cannot operate stably without adequate fuel pressure. Liquid-fueled gas turbines use pumps to deliver the fuel to the combustors. Emissions Gas turbines are among the cleanest fossil-fueled power-generation equipment commercially available. The primary pollutants from gas turbines are oxides of nitrogen (NOx), carbon monoxide (CO), and volatile organic compounds (VOCs). Other pollutants such as oxides of sulfur (SOx) and particulate matter depend primarily on the fuel used. Emissions of sulfur compounds, primarily SO2, reflect the sulfur content of the fuel. Gas turbines operating on natural gas or distillate oil that has been desulfurized in the refinery emit insignificant levels of SOx. In general, SOx emissions are significant only if heavy oils are fired in the turbine, and SOx control is a fuel purchasing issue rather than a turbine technology issue. Particulate matter is a marginally significant pollutant for gas turbines using liquid fuels. It is important to note that the gas turbine operating load has a significant effect on the emissions levels of the primary pollutants (NOx, CO, and VOCs). Gas turbines are typically operated at high loads; and, therefore, are designed to achieve maximum efficiency and optimum combustion at these high loads. Controlling all pollutants simultaneously at all load conditions is difficult. At higher loads, higher NOx emissions are expected, due to peak flame temperatures. At lower loads, lower thermal efficiency and less complete combustion occur, resulting in higher emissions of CO and VOCs.

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NOx control has been the primary focus of emission-control research and development in recent years. In older, diffusion-flame combustors, fuel/air mixing and combustion occur simultaneously. This results in local fuel/air mixture ratios that produce high local flame temperatures. These “hot spots” are where most of the NOx emissions originate. Many new gas turbines feature lean premixed combustion systems. These systems, sometimes referred to as dry low NOx (DLN) or dry low emissions (DLE), operate in a tightly controlled lean (low fuelto-air ratio) premixed mode that maintains modest peak flame temperatures. The following provides a description of the most important emission-control approaches: Diluent Injection The first technique used to reduce NOx emissions was injection of water or steam into the high temperature zones of the flame. Both water and steam are strong diluents that can reduce NOx emissions by quenching hot spots in the flame. However, positioning of the injection is not precise and some NOx is still created. Depending on uncontrolled NOx levels, water or steam injection can reduce NOx emissions by 60% or more. Both water and steam increase the mass flow through the turbine, which creates a small amount of additional power. Use of exhaust heat to raise the steam also increases overall efficiency slightly. The water used for either approach needs to be demineralized thoroughly to avoid forming deposits and corrosion in the turbine expansion section. This adds cost and complexity to the operation of the turbine. Lean Premixed Combustion NOx formation is a function of both flame temperature and residence time. The focus of combustion improvements of the past decade was to lower flame hot-spot temperatures by using lean fuel/air mixtures. Lean combustion decreases the fuel/air ratio in the zones where NOx is produced so that peak flame temperature is less than the stoichiometric adiabatic flame temperature, thereby suppressing thermal NOx formation. NOx levels as low as 9 ppm have been achieved with lean premixed combustion. However, few DLN combustors have reached the level of practical operation necessary for commercialization – the capability of maintaining 9 ppm across a wide operating range from full power to minimum load. Noise also can be an issue in lean premixed combustors because acoustic waves form due to combustion instabilities when the premixed fuel and air are ignited. This noise also manifests itself as pressure waves, which can damage combustor walls and accelerate the need for combustor replacement, thereby adding to maintenance costs and lowering unit availability. Selective Catalytic Reduction The primary post-combustion NOx control method used today is selective catalytic reduction (SCR). Ammonia is injected into the flue gas and reacts with NOx in the presence of a catalyst to produce nitrogen and water vapor. The SCR system is located in the exhaust path, typically within the HRSG, where the temperature of the exhaust gas matches the desired operating temperature of the catalyst. Low temperature SCR is ideal for retrofit applications, where it can be located downstream of the HRSG, avoiding a potentially expensive retrofit of the HRSG to place the catalyst within a hotter zone inside the HRSG. High-temperature SCR installations, operating in the 425°C to 590°C range, have increased significantly in recent years. The high operating temperature permits the catalyst to be placed directly downstream of the turbine exhaust flange. The cost of conventional SCR has dropped significantly over time, but these systems are still expensive and significantly affect the economic feasibility of smaller gas turbine projects. SCR

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requires on-site storage of ammonia, a hazardous chemical. In addition, ammonia can “slip” through the process unreacted, contributing to environmental health concerns8. Carbon Monoxide Oxidation Catalysts CO in gas turbine exhaust is typically controlled with oxidation catalysts. Some SCR installations incorporate CO oxidation modules along with NOx reduction catalysts for simultaneous control of CO and NOx. required. The catalyst is usually a precious metal such as platinum, palladium, or rhodium. CO catalysts are also used to destroy hazardous organic air pollutants and other VOCs. CO catalysts on gas turbines achieve approximately 90% destruction of CO and 85% to 90% destruction of formaldehyde (similar reductions can be expected for other VOCs). Catalytic Combustion In catalytic combustion, fuel is oxidized at very lean conditions in the presence of a catalyst. Catalytic combustion is a flameless process, allowing fuel oxidation to occur at temperatures below 930°C, where very little NOx is formed. Catalytic combustors are being developed to control NOx emissions down to less than 3 ppm. Data from ongoing long-term testing indicates that catalytic combustion exhibits low vibration and acoustic noise, only one-tenth to one-hundredth the levels measured in the same turbine equipped with DLN combustors. Past efforts at developing catalytic combustors for gas turbines achieved low, single-digit-ppm NOx levels, but failed to produce combustion systems with suitable operating durability. Catalytic combustors capable of achieving NOx levels below 3 ppm are in full-scale demonstration and are entering early commercial introduction. SCONOx™ Catalytic Absorption System SCONOx™, is a post-combustion alternative to SCR that has been demonstrated to reduce NOx emissions to less than 1 ppm and remove almost 100% of the CO. SCONOx™ combines catalytic conversion of CO and NOx with an absorption/regeneration process that eliminates the ammonia reagent found in SCR technology. CO and NO are catalytically oxidized to CO2 and NO2. The NO2 molecules are subsequently absorbed on the treated surface of the SCONOx™ catalyst. The system does not require the use of ammonia, avoiding the potential for ammonia slip associated with SCR. The SCONOx™ system is generally located within the HRSG and, under special circumstances, may be located downstream of the HRSG. Current Status The current status of this technology is illustrated in Table 2.6.1 that shows the technical performance of some gas turbines between 1 and 40 MWe.

8

The SCR stoichiometric reaction should eliminate all NOx but since there are non-uniformities in NOx and ammonia distributions excess ammonia could “slip” out of the exhausts or conversely NOx reaction could be incomplete.

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Table 2.6.1 – Performance of some representative gas turbines systems (Source: Energy and Environmental Analysis, Inc., estimates for “typical” commercially available turbine systems). Turbine Nominal capacity (kW) Electrical Efficiency (%), LHV Required fuel gas pressure (barg) Exhaust gas flow (ton/h) Turbine exit temp. (ºC) HRSG exhaust temp. (ºC) Power/Heat Ratio Total CHP Efficiency (%)

Solar Saturn Solar Taurus 20 60

Solar Mars 100

GE LM2500

GE LM6000

1000

5000

10000

25000

40000

24.3

30.1

32.2

38.0

41.0

6.5

11.0

17.2

23.4

30.0

19.95

73.48

143.34

259.00

432.73

510

510

491

510

457

160

160

160

160

160

0.51

0.68

0.73

0.95

1.07

65

67

69

70

72

Manufacturers Some of the manufacturers and packagers of gas turbines are the following:          

Alstom (Francia), www.power.alstom.com Centrax Gas Turbines (Reino Unido), www.centrax.co.uk Siemens (Germany), www.powergeneration.siemens.com General Electric (USA), www.gepower.com Turbomach (Switzerland), www.turbomach.com Pratt and Whitney (USA, Canada), www.pratt-whitney.com Mitsubishi (Japan), www.mhi.co.jp/power/e_power Rolls Royce (Reino Unido), www.rolls-royce.com/energy Kawasaki Motor Corp., Gas Turbine Division (Japan), www.khi.co.jp/gasturbine Dresser Rand http://www.dresser-rand.com

Future R & D, expectations and timeline 

Gas turbines smaller than 2 to 3 MW face intense competition from reciprocating engines on the basis of both cost and efficiency. Competition from reciprocating engines is expected to become even more intense as the emissions from engines in the 500 kW to 3 MW size range are reduced through RD&D efforts. Consequently, there is appreciable uncertainty regarding the path of future development for gas turbines smaller than 3 MW.



Turbines ranging from 3 to 10 MW face attractive prospects for increased sales and moderate investments in technology improvements. These turbines compete well with similarly sized

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reciprocating engines in many applications. Significant gains in efficiency and specific power are expected through higher turbine inlet temperatures, improved internal cooling, etc. 

The cost of installing CHP plants will decline, as states adopt streamlined siting, interconnection, and permitting procedures that allow for greater standardization of CHP components and packages. These changes in government policy will allow beneficial changes in technology and reductions in lead times. Also efficiency improvements will result in both a power increase and a decrease in cost per kW.



The installation period for a gas turbine cogeneration system is of 4 – 14 months and for large systems may reach two years. The life cycle is around 15-20 years.

2.5.5.1.3 Steam Turbine Operating Principles Steam turbines convert steam energy into shaft power and are one of the most versatile and oldest prime mover technologies used to drive generators or mechanical machinery. The capacity of steam turbines can range from fractional horsepower to several hundred MW for large utility power plants. Steam turbines require a source of high-pressure steam that is produced in a boiler or heat recovery steam generator (HRSG). This separation of energy conversion functions enables steam turbines to operate with an enormous variety of fuels, ranging from natural gas to solid waste, including all types of coal, wood, wood waste, and agricultural byproducts (sugar cane bagasse, fruit pits, and rice hulls). Steam turbine CHP systems are primarily used in industrial processes where solid or waste fuels are readily available for boiler use. In CHP applications, steam is extracted from the steam turbine and used directly in a process or for district heating, or it can be converted to other forms of thermal energy including hot water or chilled water. Large steam turbines may need more than 10 hours to warm up safely. While smaller units have morerapid start-up times, steam turbines differ appreciably from reciprocating engines, which can start up rapidly. They also differ from gas turbines, which can start in a moderate amount of time and loadfollow with reasonable rapidity. While steam turbines are competitively priced compared to other prime movers, the costs of complete, greenfield boiler/steam turbine CHP systems are relatively high on a per kW of capacity basis because of their low power-to-heat ratio, the costs of the boiler, fuel handling, and overall steam systems, and the custom nature of most installations. Steam turbines are well suited to medium- and large-scale industrial and institutional applications where inexpensive fuels, are available. However, retrofit applications of steam turbines into existing boiler/steam systems can be competitive options for a wide variety of users. In general, steam turbine applications are driven by balancing lower-cost fuel, or avoided disposal costs for a waste fuel, against the high capital cost and (usually high) annual capacity factor for the steam plant and the combined energy plant-process plant application. For these reasons, steam turbines are not normally direct competitors of gas turbines and reciprocating engines in distributed generation applications.

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Figure 2.6.3 - Cogeneration system with condensing steam turbine (Source: Educogen Project). Steam Turbine technology Steam turbines differ from reciprocating engines and gas turbines in that the fuel is burned in a boiler, which is separate from the power generation equipment (the steam turbogenerator). The energy is transferred from the boiler to the turbine by pressurised steam. For sizes up to (approximately) 40 MW, shop-assembled, horizontal watertube industrial boilers are used. Larger boilers are field-erected directly on site. Large shop-assembled boilers are typically capable of firing only gas or distillate oil, because there is inadequate residence time for complete combustion of most solid and residual fuels in such designs. Large, field-erected industrial boilers, firing solid and residual fuels, resemble utility boilers. In the steam cycle, water is first pumped to elevated pressure, which is medium to high pressure, depending on the size of the unit and the temperature to which the steam is eventually heated. The water is then heated to the boiling temperature corresponding to the pressure, boiled (converted from liquid to vapour), and then most frequently superheated (heated to a temperature above that of boiling). The pressurised steam is expanded to lower pressure in a turbine, then exhausted, either to a condenser at vacuum conditions (power-only configuration) or into an intermediate temperature steam-distribution system that delivers the steam to the industrial or commercial application (CHP configuration). The condensate from the condenser or from the industrial steam utilisation system is returned to the feedwater pump for continuation of the cycle. Steam turbines consist of a stationary set of vanes (called nozzles) and a moving set of adjacent blades (called buckets or rotor blades) installed within a casing. The vanes and blades work together so that the steam turns the shaft of the turbine and the connected load. The internal flow passages of a steam turbine are very similar to those of the expansion section of a gas turbine. (Indeed, gas turbine engineering came directly from steam turbine design.) The main differences are the different gas density, molecular weight, isentropic expansion coefficient, and (to a lesser extent) viscosity of the two fluids. When the steam is expanded through a high-pressure-ratio turbine (as in utility and large industrial steam systems) the steam can begin to condense in the turbine if the temperature drops below the saturation temperature at that pressure. If water droplets are allowed to form in the turbine, blade erosion will occur when the drops impacted the blades. To avoid this, at this point in the expansion, the steam is sometimes returned to the boiler and reheated to high temperature and then returned to the turbine for further (safe) expansion. In a few very large, high-pressure, utility steam systems, double reheat systems are installed. Because steam turbine casings are thick, to enable them to handle high steam pressures, they have high thermal inertia. Steam turbines must be warmed and cooled slowly to minimise the differential expansion between the rotating blades and the stationary parts. Large steam turbines may need more than 10 hours to warm up safely. While smaller units have more-rapid start-up times, steam turbines

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differ appreciably from reciprocating engines, which can start up rapidly. They also differ from gas turbines, which can start in a moderate amount of time and load-follow with reasonable rapidity. Industrial-scale steam turbines used for CHP, where the turbine exhaust steam is used for other purposes, can be classified into two main types: noncondensing and extraction. Noncondensing (Back-Pressure) Turbines The noncondensing turbine (also referred to as a back-pressure turbine) exhausts its entire flow of steam to the industrial process or facility steam mains at conditions close to the process heat requirements. Usually, the steam sent into the mains is not much above saturation temperature9. The term “back-pressure” refers to turbines that exhaust steam at atmospheric pressures and above. The discharge pressure is established by the specific site requirements – 3.5, 10, and 17 bar are the most typical pressure levels for steam distribution systems. The lower pressures most often are used in district heating systems, and the higher pressures most often are used in supplying steam to industrial processes. Industrial processes often include further expansion for mechanical drives, using small steam turbines to drive heavy equipment that is intended to run continuously for long periods. Extraction Turbines Extraction turbines have opening(s) in their casings for extraction of a portion of the steam at some intermediate pressure. The extracted steam may be used for process purposes in a CHP facility or for feedwater heating – as is the case in most utility power plants. The rest of the steam is condensed. The steam-extraction pressure may or may not be automatically regulated depending on the turbine design. Regulated extraction allows more steam to flow through the turbine to generate additional electricity during periods of low thermal demand by the CHP system. In utility-type steam turbines, there may be several extraction points, each at a different pressure corresponding to a different temperature at which heat is needed in the thermodynamic cycle. The facility’s specific needs for steam and power over time determine the extent to which steam will be extracted for use in the process – or be expanded to vacuum conditions and condensed. In large, often complex, industrial plants, additional steam may be admitted into the steam turbine, flowing in through the casing and increasing the flow in the steam path. This arrangement is often used when multiple boilers are operating at different pressures, because of their historical existence. These steam turbines are referred to as admission turbines. At steam extraction and admission locations, there are usually steam flow-control valves that add to the cost of the turbine and control system. Efficiencies This paragraph summarises the performance characteristics of “typical” commercially available steam turbine systems and for boiler/steam CHP systems in the 500 kW to 15 MW size range. Steam turbine thermodynamic efficiency, which is a measure of how efficiently the turbine extracts power from the steam, is useful in identifying the conditions of the steam as it exhausts from the turbine and in comparing the performance of various steam turbines. Turbine thermodynamic efficiency is not to be confused with electrical generating efficiency, which is the ratio of net power generated to total fuel input to the cycle. Multistage (moderate to high-pressure ratio) steam turbines have thermodynamic efficiencies that range from less than 60% for very small (<1,000 kW) units to more than 90% for large industrial and utility-sized units. Small, single-stage steam turbines can have efficiencies as low as 50%. Steam turbine CHP systems are generally characterised by very low power-to-heat ratios, typically in the 0.05 to 0.2 range. This is because electricity is a by product of heat generation, with the system optimised for steam production.

9

Saturation temperature varies according to steam pressure.

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While steam turbine CHP system cycle electrical efficiency may seem very low, it is because the primary objective of a boiler/steam turbine CHP system is to produce large amounts of steam for uses other than power generation. The effective electrical efficiency of steam turbine systems themselves, however, is generally very high, because almost all the energy difference between the high-pressure boiler output and the lowpressure turbine output is converted to electricity. This means that total CHP system efficiencies are generally very high and approach the boiler efficiency level. Steam boiler efficiencies range from 70% to 85% HHV depending on boiler type and age, fuel, duty cycle, application, and steam conditions. There are numerous steam turbine design features that have been implemented to increase efficiency, allow operation over a range of conditions, simplify manufacture and repair, and achieve other practical purposes. The long history of steam turbine use has resulted in a large inventory of steam turbine designs that can be used to tailor turbines for specific applications. Manufacturers tailor design requirements by varying the flow area in the internal turbine stages and the extent to which steam is extracted (removed from the flow path between stages) to accommodate the specifications of their clients. Current Status     



Steam must be at high pressure and temperature. Typical inlet steam conditions are 42 bar/400ºC or 63 bar/480ºC The temperature required by the process dictates actual outlet steam conditions The higher the turbine inlet pressure, the greater the power output, but higher steam pressures entail progressively greater boiler capital and running costs. Steam turbines are capable of operating over broad range of steam pressures. They operate with inlet pressure up to 3.500 psig and exhaust vacuum conditions as low as one inch of Hg (absolute). Double or triple-pressure steam boilers enhance the heat recovery and increase the efficiency of the whole Rankine cycle, but make the system more complex. These boilers are used in large systems. The installation period is of 12 – 18 months for small units, up to three years for larger systems, and the life cycle is about 25 - 35 years.

Heat recovery The amount and quality of steam available for process use after passing through the steam turbine is a function of the entering steam conditions and the design of the steam turbine. Exhaust steam from the turbine can be used directly in a process or for district heating. It can also be converted to other forms of thermal energy, including hot or chilled water. Steam discharged or extracted from a steam turbine could be used in a single- or double-effect absorption chiller. The steam turbine also could be used as a mechanical drive for a centrifugal chiller. Between the power-only output of a condensing steam turbine and the power and steam combination of a back-pressure steam turbine, essentially any ratio of power to heat output can be supplied to a facility. Back-pressure steam turbines can be obtained with a variety of back pressures, further increasing the variability of the power-to-heat ratio. This flexibility gives system designers the ability to create CHP systems that respond to seasonal and daily variations in power and steam demands. Availability, Life and Maintenance Steam turbines are rugged, with operational life often exceeding 50 years. For comparative purposes, the economic life of steam turbine systems may be assumed to be a minimum of 20 years. Maintenance is simple, comprised mainly of ensuring that all fluids (steam flowing through the turbine and the oil for the bearing) are always clean and at the proper temperature. Other maintenance activities include inspecting auxiliaries such as lubricating-oil pumps, coolers, and oil strainers; and checking the operation of safety devices such as overspeed trips. In order to obtain reliable service, steam turbines require long warm-up periods so that there are minimal thermal expansion stress and wear concerns.

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One maintenance issue with steam turbines is the removal of solids that carry over from the boiler and deposit on turbine nozzles and other internal parts, degrading turbine efficiency and power output. Some of these solids are water-soluble, but others are not. Three methods are employed to remove deposits: 1) manual removal; 2) cracking off the deposits by shutting off the turbine and allowing it to cool; and 3) water-washing water-soluble deposits while the turbine is running. Steam turbines are generally considered to have 99% availability with longer than one year between shutdowns for maintenance and inspections. This high level of availability applies only to the steam turbine, not to the boiler or HRSG that is supplying the steam. Fuels Industrial boilers operate on a wide variety of fuels, including wood, coal, natural gas, oils, municipal solid waste, and sludges. The fuel handling, storage, and preparation equipment needed for solid fuels adds considerably to the cost of an installation. Thus, such fuels are used only when a high annual capacity factor is expected of the facility, or when the solid material has to be disposed of to avoid an environmental or space occupancy problem. Emissions Emissions associated with a steam turbine are dependent on the fuel used to generate the steam. Boiler emissions vary depending on fuel type, boiler design, environmental conditions, and pollution-control technologies. Boiler emissions include nitrogen oxides (NOx), sulphur oxides (SOx), particulate matter (PM), carbon monoxide (CO), and carbon dioxide (CO2). NOx control has been the primary focus of emissions-control research and development in boilers. The following provides a description of the most prominent emissions-control approaches. 1) Combustion Process Emissions Control Combustion-control techniques are less costly than post-combustion control methods and are often used on industrial boilers for NOx control. Control of combustion temperature has been the principal focus of combustion process control in boilers. Combustion control requires trade-offs: high temperatures favour complete combustion of the fuel and low residual hydrocarbons and CO, but high temperatures promote NOx formation. Lean combustion dilutes the combustion process and reduces combustion temperatures and NOx formation. However, lean combustion undesirably reduces boiler efficiency. Flue-Gas Recirculation (FGR) FGR is the most effective technique for reducing NOx emissions from industrial boilers with inputs below 105 GJ/hr. With FGR, a portion of the relatively cool boiler exhaust gases reenters the combustion process, reducing the flame temperature and associated thermal NOx formation. It is the most popular and effective NOx reduction method for firetube and watertube boilers, and many installations can rely solely on FGR to meet environmental standards. The practical limit to NOx reduction via FGR is 80% in natural gas-fired boilers and 25% for standard fuel oils. Low Excess Air Firing (LAE) High levels of excess air can result in increased NOx formation, because the excess nitrogen and oxygen in the combustion air entering the flame combine to form thermal NOx. Firing with low excess air means limiting the excess air that enters the combustion process, thus limiting the amount of extra nitrogen and oxygen entering the flame. This is accomplished through burner design modification and is optimised through the use of oxygen trim controls. When operating with low excess air, care must be taken to accomplish complete combustion of the fuel and to avoid excess CO emissions. LAE can result in overall NOx reductions of 5% to 10% when firing with natural gas. In small, compact oil- and gas-fired boilers, high levels of excess air are frequently used to ensure complete combustion. Large industrial boilers usually use low excess air in order to minimize the heat loss in the stack exhaust.

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Burner Modifications By modifying the design of standard burners to create larger flames, lower-flame temperatures and lower-thermal NOx formation can be achieved, resulting in lower overall NOx emissions. While most boiler types and sizes can accommodate burner modifications, such modifications are most effective for boilers firing natural gas and distillate fuel oils, with little effectiveness in heavy oil-fired boilers. Also, burner modifications must be complemented with other NOx reduction methods, such as flue-gas recirculation, to comply with the more stringent environmental regulations. Achieving low NOx levels (30 ppm) through burner modification alone can adversely impact boiler-operating parameters such as turndown, capacity, CO levels, and efficiency. Water/Steam Injection Injecting water or steam into flames reduce flame temperature, lowering thermal NOx formation and overall NOx emissions. However, under normal operating conditions, water/steam injection can decrease boiler efficiency by 3% to 10%. Also, there is a practical limit to the amount that can be injected without causing condensation-related problems. This method is often employed in conjunction with other NOx-control techniques such as burner modifications or flue-gas recirculation. When used with natural gas-fired boilers, water/steam injection can decrease NOx emission by up to 80%, with less reduction achievable in oil-fired boilers. II) Post-Combustion Emissions Control There are several types of exhaust-gas treatment processes that are applicable to industrial boilers. Selective Non-Catalytic Reduction (SNCR) In boiler SNCR, a NOx-reducing agent such as ammonia or urea is injected into the boiler exhaust gases at a temperature in the 760 to 870°C range. The agent breaks down the NOx in the exhaust gases into water and atmospheric nitrogen (N2). While SNCR can decrease boiler NOx emissions by up to 70%, it is very difficult to apply SNCR industrial boilers that modulate or cycle frequently. To perform properly, the reducing agent must be introduced at a specific flue-gas temperature, and the location of the exhaust gases at the necessary temperature is constantly changing in a cycling boiler. Selective Catalytic Reduction (SCR) This technology involves the injection of the reducing agent into the boiler exhaust gas in the presence of a catalyst. The catalyst allows the reducing agent to operate at lower exhaust temperatures than SNCR, in the 260 to 650°C temperature range. Depending on the type of catalyst, NOx reductions of up to 90% are achievable with SCR. The two agents used commercially are ammonia (NH3 in anhydrous liquid form or aqueous solution) and aqueous urea. Urea decomposes in the hot exhaust gas and SCR reactor, releasing ammonia. Approximately 0.9 to 1.0 moles of ammonia are required per mole of NOx at the SCR reactor inlet in order to achieve 80% to 90% NOx reduction. The use of SCR adds to both the system capital and operating costs, and SCR can only occasionally be justified on boilers with inputs less than 105 GJ/hr. SCR requires on-site storage of ammonia, a hazardous chemical. In addition, ammonia can “slip” through the process unreacted, contributing to environmental health concerns. Manufacturers The following are some of the major manufacturers:   

Ansaldo Energia (Italy), www.ansaldoenergia.com Alstom (France), www.power.alstom.com General Electric (USA), www.gepower.com

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Siemens (Germany), www.powergeneration.siemens.com Turbomach (Switzerland), www.turbomach.com Man Turbo (Germany), www.manturbo.com Mitsubishi (Japan), www.mhi.co.jp

Future R&D, expectations and timeline  

Employment of new engineering analysis and design tools (such as Computational fluid dynamics and finite element analysis) to improve steam turbine designs Advances in material technology

2.5.5.1.4 Combined Cycle Cogeneration System Operating Principles The term combined cycle is used for systems consisting of two thermodynamic cycles, which are connected with a working fluid and operate at different temperature levels. The high temperature cycle (topping cycle) rejects heat, which is recovered and used by the low temperature cycle (bottoming cycle) to produce additional electrical (or mechanical) energy, thus increasing the electrical efficiency. The most widely used combined cycle systems are those of gas turbine / steam turbine (combined Joule-Rankine cycle). They so much outnumber other combined cycles that the term combined cycle, if nothing else is specified, means combined Joule-Rankine cycle. The system is a combination of the gas and steam turbines, with heat recovery boiler between them. A gas turbine produces electricity and high enthalpy steam which is expanded through a steam turbine to produce more electricity and lower enthalpy steam. The most widely used combined cycle systems are Combined Joule-Rankine. The maximum possible steam temperature with no supplementary firing is by 25-40 ºC lower than the exhaust gas temperature at the exit of the gas turbine, while the steam pressure can reach 80 bar. If higher temperature and pressure is required, then an exhaust gas boiler with burner(s) is used for firing supplementary fuel. With supplementary firing, steam temperature can approach 540 ºC and pressure can exceed 100 bar. The system can operate either under combined Joule-Rankine cycle or combined Diesel-Rankine cycle. The types of fuel that the system can use are similar to those mentioned for gas turbines. Typical electric output of the system is in the range 4 – 100 MWe. There are also systems of 400 MWe. Combined cycle cogeneration system has an efficiency of 70 – 90 % and a power to heat ratio in the range 0.6 – 2.0. It has higher efficiency from both gas and steam turbine systems but, however, it is very uneconomic in small sizes. The main components of the system are: steam turbine, gas turbine, heat recovery boiler, and auxiliaries (pumps, etc.) as shown in Figure 2.6.4.

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Figure 2.6.4 -Scheme of combined cycle cogeneration The Combined Cycle Cogeneration System have sizes depending of their components (manly Gas Turbine and Steam Turbine) the range of power can be between 20 to 500 MW. Some power plants use more than one combined cycle group (pairs of steam and gas turbines) so it is possible to obtain a total power output up to 1200 – 1600 MW. Advantages: 

 

The combined cycle plant takes advantage of the efficiencies of running both cycles simultaneously to produce power very cost effectively during those peak periods thereby saving the utility from having to purchase power to meet spikes in demand Advantage of combined cycle power plants is their ability to respond quickly to fluctuations in customer demand for electricity One advantage of this kind of plants is the possibility to build them in two stages. The first stage, turbogas, can be finished in a short time and the plant can begin operations right away; subsequently, construction of the steam unit can be finished, thus completing the combined cycle.

Disadvantages: 

The limitations that materials and design impose on operating temperatures and efficiency.

Current status   

The combined cycle plants have a smaller polluting effect due to a better use of the final energy cycle. The plants are designed to support the load variations. The installation can be completed in two phases: the gas turbine subsystem is installed first, which can be ready for operation in 12-18 months. While this is in operation, the steam subsystem is installed. The installation period is of 2 – 3 years, and the life cycle is about 15 – 25 years.

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Table 2.6.2 – Main Combined cycle characteristics. Power range (MW)

Efficiency (%)

HRSG type

15 – 50

40 – 50

Double pressure

51 – 100

44 – 52

Double pressure

101 – 250

50 – 52

Double- and triple-pressure

Above 250

56 - 58

Triple-pressure with reheat

Manufacturers There are no manufacturers specialised only on combined cycles. Manufacturers of gas turbines and steam turbines (that in some cases are the same) provide and install also combined cycles. So the list of references of manufacturers for steam and gas turbines are also valid for combined cycles. Some of these manufacturers provide turn key solutions for combined cycles, such as, Alstom, Siemens or Turbomach. It is not usual to find combined cycles based on reciprocating engines instead of gas turbines, but some manufacturers of large reciprocating engines such as Wärtsilä have some references of these systems. Future R&D, expectations and timeline To overcome the barriers, attention must be paid to:  

     

Raising the efficiencies of gas turbines. This may be achieved through: Developments that allow them to operate at higher temperatures, ie improving the performance of existing materials and developing thermal barrier coatings, new materials and advanced bladecooling techniques Improving design aspects, e.g. to minimise aerodynamic losses. Continued work aimed at reducing both capital and plant operating costs. Reducing emissions, particularly those of NOx. Improving the efficiency of part-load operation. Turbine burner development for the use of unconventional fuels, eg coal gas and gasified biomass, and in combination with natural gas. Combustion developments to reduce NOx emissions, eg by staged and catalytic combustion.

2.5.5.1.5 Micro Gas Turbines Operating Principles Microturbines are small combustion turbines with outputs of 25 kW to 500 kW. They are used for stationary energy generation applications at sites with space limitations for power production. They are fuel-flexible machines that can run on natural gas, biogas, LPG, diesel, and kerosene. Microturbines have few moving parts, low emissions, low electricity costs, and waste heat utilisation opportunities; and are lightweight and compact in size. Waste heat recovery can be used in combined heat and power (CHP) systems to achieve energy efficiency levels greater than 80%. Microturbines consist usually of a compressor, combustor, turbine, alternator, recuperator (also called regenerator) and generator. In CHP operation, a second heat-recovery heat exchanger – the exhaust gas heat exchanger – can be used to transfer remaining energy from the microturbine exhaust to a hot

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water system. The use of the regenerator (regenrative cycle) doubles the net efficiency of the micro turbine at the expense of a lower exhaust gas temperature. Exhaust heat can be used for a number of different applications, including process or space heating, heating potable water, driving absorption chillers, or regenerating desiccant dehumidification equipment. Some microturbine-based CHP applications do not use recuperators, and some have the ability to bypass their recuperator to adjust their thermal to electric ratio. The temperature of the exhaust from these microturbines is much higher (up to 650 ºC) and thus more heat is available for recovery. Microturbines are classified by the physical arrangement of the component parts: single shaft or twoshaft, simple cycle or recuperated, inter-cooled, and reheat. The machines generally operate at more than 40,000 rpm. Microturbines are available in sizes between 0,030 to 0,2 MW

Figure 2.6.5 – Typical micro gas turbines configuration.

The advantages are:        

Compact and modular design Lower maintenance and operating costs Low emissions and noise Acceptable noise levels; Fuelled by domestic natural gas resource with expanded fuel flexibility; Low emissions; High temperature exhaust for heat recovery; Acceptable power quality.

The disadvantages are:   

Requires high pressure gas (compressor reduces net kWe output. Not available to start under large load or follow large transients. Performance Sensitive (inlet air temperature and altitude)

Current status  

The most popular microturbine installed to date is the 30-kW system manufactured by Capstone. The typical 30-60 kW unit cost averages 1,000 €/kW. For gas-fired microturbines, the present installation cost (site preparation and natural gas hookup) for a typical commercial site averages 8.200 €.

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Manufacturers Honeywell pulled out of the microturbine business in December 2001, leaving the following manufacturers in the microturbine market: -

Capstone Turbine Corporation (USA), www.microturbine.com Elliot Energy Systems (using the power electronics of Bowman) (USA), www.tapower.com Turbec (Italy, Sweden), www.turbec.com Ingersoll-Rand Energy Systems (USA), www.irenergysystems.com Bowman Power Group Ltd (UK) (Packaging the microturbine of Elliott), www.bowmanpower.co.uk/

According to the results of the european Project Bioturbine in 2003 the worldwide micro turbine market was as follows: Capstone (2500), Ingersoll-Rand (80), Elliott (200), Bowman (100) and Turbec (150). Installations Examples of micro gas turbines installations: -

Turbec T100, Gas Natural SDG, S.A. office building in Montigalà (Barcelona, Spain). Bowman 80 kW connected to an absorption chiller, Hospitalet de Llobregat (Barcelona, Spain) Capstone, Ikerlan (Basque Country, Spain). Two Capstone C30 in two landfills in Cerdanya and Vic (Spain) University of California – Irvine (USA), testing of several types of microturbines. ORNL (USA), testing of several types of microturbines. Centre for Environmental Energy Engineering (CEEE), capstone of 60 kW in Maryland (USA) integrated with and absorption chiller and a dessicant unit. Crever – Universitat Rovira i Virgili (Spain) testing of a Capstone C30 in different configurations.

Future R&D, expectations and timeline  

The market for microturbines is expected to range from 2.4 to 8 billion Euros by 2010, with 50% of sales concentrated in North America. The next generation of "ultra-clean, high-efficiency" microturbine product designs will focus on the following performance targets:  High Efficiency — Fuel-to-electricity conversion efficiency of at least 40%.  Environment — NOx < 7 ppm (natural gas).  Durability — 1,000 hours of reliable operations between major overhauls and a service life of at least 45,000 hours.  Fuel Flexibility — Options for using multiple fuels including diesel, ethanol, landfill gas, and biofuels.

2.5.5.1.6 Fuel Cells Operating Principles Fuel cells produce power electrochemically, more like batteries than conventional generating systems. Unlike storage batteries, however – which produce power from stored chemicals – fuel cells produce power when hydrogen fuel is delivered to the cathode of the cell, and oxygen in air is delivered to the anode (figure 6). The resultant chemical reactions at each electrode create a stream of electrons (or

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direct current) in the electric circuit external to the cell. The hydrogen fuel can come from a variety of sources, but the most economic is steam reforming of natural gas – a chemical process that strips the hydrogen from both the fuel and the steam. Fuel cell systems today typically consist of a fuel processor, fuel cell stack, and power conditioner. The fuel processor, or reformer, converts hydrocarbon fuels to a mixture of hydrogen-rich gases and, depending on the type of fuel cell, can remove contaminants to provide pure hydrogen. The fuel cell stack is where the hydrogen and oxygen electrochemically combine to produce electricity. The electricity produced is direct current (DC) and the power conditioner converts the DC electricity to alternating current (AC) electricity, for which most of the end-use technologies are designed. As a hydrogen infrastructure emerges, the need for the reformer will disappear as pure hydrogen will be available near point of use. Fuel cells are categorized by the kind of electrolyte they use: Alkaline Fuel Cells (AFCs) were the first type of fuel cell to be used in space applications. AFCs contain a potassium hydroxide (KOH) solution as the electrolyte and operate at temperatures between 60 and 250°C. The fuel supplied to an AFC must be pure hydrogen. Carbon monoxide poisons an AFC, and carbon dioxide (even the small amount in the air) reacts with the electrolyte to form potassium carbonate. Phosphoric Acid Fuel Cells (PAFCs) were the first fuel cells to be commercialized. These fuel cells operate at 150-220°C and achieve 35 to 45% fuel-to-electricity efficiencies LHV. Proton Exchange Membrane Fuel Cells (PEMFCs) operate at relatively low temperatures of 70100°C, have high power density, can vary their output quickly to meet shifts in power demand, and are suited for applications where quick start-up is required (e.g., transportation and power generation). The PEM is a thin fluorinated plastic sheet that allows hydrogen ions (protons) to pass through it. The membrane is coated on both sides with highly dispersed metal alloy particles (mostly platinum) that are active catalysts. Molten Carbonate Fuel Cell (MCFC) technology has the potential to reach fuel-to-electricity efficiencies of 45 to 60% on a lower heating value basis (LHV). Operating temperatures for MCFCs are around 650° C, which allows total system thermal efficiencies up to 85% LHV in combined cycle applications. MCFCs have been operated on hydrogen, carbon monoxide, natural gas, propane, landfill gas, marine diesel, and simulated coal gasification products. Solid Oxide Fuel Cells (SOFCs) operate at temperatures up to 1,000°C, which further enhances combined-cycle performance. A solid oxide system usually uses a hard ceramic material instead of a liquid electrolyte. The solid-state ceramic construction enables the high temperatures, allows more flexibility in fuel choice, and contributes to stability and reliability. As with MCFCs, SOFCs are capable of fuel-to-electricity efficiencies of 45 to 60% LHV and total system thermal efficiencies up to 85% LHV in combined-cycle applications. Fuel cell systems can be sized for grid-connected applications or customer-sited applications in residential, commercial, and industrial facilities. Depending on the type of fuel cell (most likely SOFC and MCFC), useful heat can be captured and used in combined heat and power systems (CHP). Many fuel cell technologies are modular and capable of application in small commercial and even residential markets; other technology operates at high temperatures in larger sized systems that would be well suited to industrial CHP applications.

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Figure 2.6.6 – Schematic of a typical Fuel Cell. Fuel Cell usual capacity range goes from a few kW to 2 MW or higher depending on the type of fuel cell, application, etc. The advantages are:             

Reliability Low operating cost Clean emissions Constant power production Computer grade power Quit operations Choice of fuels Low emissions High efficiency over load range Modular design, siting flexibility, short construction time Automated operation, quick load changes, low maintenance Flexible heat to power ratio Low or high-grade heat, depending on design and fuel cell type

The disadvantages are:      

High initial cost Not firmly established technology Availability Poor ability for multiple starts. Poor ability to follow large, rapid transients Corrosion for liquid electrolytes, Sulphur.

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Table 2.6.3 – Main chracteristics of different types of fuel cells. Source: A guide to Decentralized Energy Cogeneration, 2003 Phosphoric Acid Fuel Cell (PAFC) Anode : H2 → 2 H+ + 2eCathode ½ O2 + 2H+ + 2e- → H2O

Chemical reactions Electrical Efficiency* Range

Heat Application

Polymer Electrolyte Fuel Cells (PEMFC) Anode : H2 + 2 (OH)- → 2 H2O + 2eCathode ½ O2 + 2H+ + 2e- → H2O

Solid Oxide Fuel Cells (SOFC)

Molten Carbonate Fuel Cells (MCFC)

Alkaline Fuel Cells (AFC)

Anode : H2 + O2-→ H2O + 2eCathode ½ O2 + 2 e→ O2-

Anode : H2 + (CO3)2-→ H2O + CO2 + 2eCathode ½ O2 + CO2 + 2e- → (CO3)2-

Anode : H2 → 2 H+ + 2eCathode : ½ O2 + H2O + 2 e - → 2 (OH)-

45-50

70

36-42

30-40

45-60

100-200 kW

3-250 kW

1-10 MW

T = 200ºC Recovered heat to be use for space or water heating, often suiting district heating system

T=80ºC Can be use in cogeneration to produce hot water. Ideal for space or water heating.

250 kW – 5 MW T=650ºC. Recovered heat T=1000ºC. to be use for Recovered heat to commercial be use for industrial buildings and processes combined cycle applications.

10-200 kW T=80ºC Would be use in stationary applications and in desalination plants.

* Electrical efficiencies are based on values for hydrogen fuel and do not include electricity required for hydrogen reforming. Current status  







Fuel cells are still too expensive to compete in widespread domestic and international markets without significant subsidies. PAFC – More than 170 PAFC systems are in service worldwide, with those installed by ONSI having surpassed 2 million total operating hours with excellent operational characteristics and high availability. Phosforic Acid Fuel Cells, developed since the late 60s, are the only mature technology, but they suffer an intrinsically high cost, due to the use of precious metals as catalyst PEMFC – PEM systems up to 200 kW are operating in several hydrogen-powered buses. Most units are small (<10 kW). PEMFCs currently cost several thousand dollars per kW. Polymer Electrolyte Fuel Cells, operating at low temperature (60-80°C) are the preferred technology for automotive applications SOFC – Solid Oxide Fuel Cells operate at very high temperature (900-1000°C) and are a very promising technology for stationary power generation, although there are still technological problems related to the use of a metal-ceramic combination at very high temperature. A small, 25 kW natural gas tubular SOFC systems has accumulated more than 70,000 hours of operations, displaying all the essential systems parameters needed to proceed to commercial configurations. Both 5 kW and 250 kW models are in demonstration. MCFC – Molten Carbonate Fuel Cells have an operating range from some kWs up some MW. Operating at high temperature (650°C) they don’t need precious catalysts and are very tolerant against fuel composition without the drawbacks of SOFC temperature related problems. They generate high-grade heat and they are very well suited for cogeneration. Presently MCFC technology is developed in the US, in Japan, in Korea and, in Europe. 50 kW and 2 MW systems have been field-tested. Commercial offerings in the 250 kW-2 MW range are under development.

Manufacturers Some fuel cell developers include:     

Fuel Cell Energy, USA, partner of MTU (Germany) (MCFC and in the future also SOFC), www.fce.com, www.mtu-online.com/cfc Ansaldo Fuel Cells, Italy, (MCFC), www.ansaldofuelcells.com UTC – United Technologies Corporation, formerly ONSI, USA, (PAFC, PEMFC), www.utcpower.com Avista Laboratories , USA, www.avistalabs.com Ballard Generation Systems, Canada (PEMFC), www.ballard.com

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Siemens, Germany, (SOFC and hybrid SOFC/GT), www.powergeneration.siemens.com/en/fuelcells Nuvera Fuel Cells, Italy, (PEMFC), www.nuvera.com Proton Energy Systems, USA, (PEMFC), www.protonenergy.com Teledyne Energy Systems, USA, (PEMFC), www.teledyneenergysystems.com Axane (Air Liquid group), France, (PEMFC), www.axane.fr PlugPower – Vaillant, USA, (PEMFC), www.plugpower.com ZTEK Corporation, USA, (SOFC), www.ztekcorporation.com SOFCo, USA, (SOFC), www.sofco-efs.com Sulzer Hexis, Switzerland, (SOFC), www.hexis.com

Installations -

National Bank of Omaha (Nebraska, USA), 4 x 200 MW each PAFC of UTC Fuel Cells.

-

100 kW SOFC cogeneration system installed at the village of Westervoort, near Arnhem, Netherlands. where it operated for 16,667 hours at a peak power of ~140 kW. It typically fed 109 kW into the local grid and 64 kW of hot water into the local district heating system and operated consistently at an electrical efficiency of 46%. In March 2001 the system was moved from the Netherlands to a site in Essen, Germany, where it was operated by the German utility RWE for an additional 3,700 hours, for a total of over 20,000 hours.

-

In Böblingen (Baden-Württemberg), a HotModule decentralised fuel cell power plant from MTU CFC Solutions GmbH, will be the world’s first to generate power and heat using biogas from a digester plant. The system, to be installed in Leonberg during 2006 and will supply up to 245kW of electric power and 170kW of heat.

Future R&D, expectations and timeline The main research targets within the next 10 years should be the reduction of costs, simplification and improved reliability. Basic research is needed to improve the performance of the different fuel cell types. New materials could bring down the costs and increase the life expectancy. By simulating the stack itself, the auxiliary equipment can be simplified and optimised now, without an existing fuel cell with the target performance. Reliability and maintenance are other important issues for a breakthrough of fuel cells. Many systems have to be tested before a guarantee for reliable operation can be given. Demonstration projects play an important role, giving information on the lifetime of different components and identifying those components which are critical for the lifetime of the system. Additionally, information must be obtained on the total capital and operational costs including maintenance, service and replacement of parts, during the entire lifetime of the system. At the moment information about maintenance and operation and replacement costs are not known and can only be estimated.

2.5.5.1.7 Stirling Engines Operating Principles A Stirling engine works by alternatively heating and cooling a working gas. Heat is provided at a constant temperature at one end of a cylinder (the hot end), while heat is rejected at constant temperature at the opposite end (the cold end). Work is created as the expanding gas pushes against a piston. The working gas is transferred back and forth between the two chambers, often with the aid of a “displacer piston.” The working gas is generally compressed in the cold chamber and generally expanded in the hot chamber to produce power. A regenerator is used between the hot and cold chambers of the machine to increase the energy-conversion efficiency.

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Stirling engines are heat engines that operate on the Carnot cycle. They do not closely approach Carnot efficiencies due to the fact that engine components need to be cooled and lubricated. The basic components of a Stirling engine package for distributed generation applications would include the Stirling engine core, combustion package, lubricating oil system, engine-cooling system, and control system. An important element of a Stirling engine is the working fluid. Due to their heat transfer characteristics, hydrogen and helium are typically preferred. However, the use of hydrogen introduces several design issues, e.g., engine seals, and corrosion. In a typical Stirling engine, about 30% of the heat input is converted to electric power, and 70% of the heat input is rejected to the cooling system and exhaust gases, so there is a good potential for water heating or other low-temperature heating. Because Stirling engines are liquid-cooled, it is relatively easy to capture heat for CHP applications through a simple liquid-to-liquid heat exchanger. The only difference between a “power only” package and a CHP package is the addition of the heat exchanger and related control elements. Stirling engines achieve CHP thermal efficiencies approaching 80% at competitive reasonable costs with a suitable thermal host.

Figure 2.6.7 - Biomass cogeneration scheme based in an Stirling engine. The potential Stirling engine power range is expected to range from 1 to 300 kW or even up to 1.5 MW. But the few commercially available or market ready systems today are below 55 kW and mainly under 10 kW. The advantages are:   

     

The Stirling engine is fuel independent, it doesn't even need any fuel. Is a very quietly operating engine, can be made operating virtually without any vibrations. A high percentage of the Stirling engine heat losses will go to the cooling fluid instead of into the exhausts, which makes the Stirling engine suitable for combined heat and power generation (socalled micro-CHP). A possible long interval between maintenance and major overhauls is another positive factor. No extra thermal-boiler necessary. Electricity production independent from heat production. Very low emissions. Easy to control. Can be built as an interchangeable unit.

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The disadvantages are:  

The engine has a disadvantageous weight-to-power ratio. This means that not all-mobile applications are possible. An expensive material in the hot parts of the engine is another factor that tends to make the engine expensive.

Current status Stirling technology is still in a development phase. Potential applications would include small commercial building heating/cooling systems, hotels or laundries. The models currently under development are in the 1 to 55 kW range. The lower end of the range is best suited for residential applications, while the higher fits a small commercial application. The packages can be installed in multiples to obtain larger outputs. Life and reliability data are not available, due to the limited operational experience of Stirling engines. Manufacturers -

SOLO Kleinmotoren GmbH (Germany), www.stirling-engine.de Sunpower (USA), www.sunpower.com Danstoker (Denmark), www.danstoker.dk Whisper Tech (UK), www.whispergen.com DTE Energy Technologies (USA), www.dtetech.com Enatec (Holland), www.enatec.com Distributed Energy Company (DISENCO) (formerly Sigma) (UK), www.disenco.com

Installations -

2 natural gas units of SOLO 161 Stirling at Graz (Austria), E-Werk Gösting V. Franz GmbH & Co KG, since 2003.

-

1 natural gas units of SOLO 161 Stirling at WellVital-Hotel Erika, Bad Kissingen (Germany), Hotel, since 2004.

Future R&D, expectations and timeline The key challenge for Stirling engines in becoming accepted in the marketplace is cost and reliability. For Stirling engines to become a commercial commodity product installed cost will have to come down significantly. After price reduction, an increase in available capacities and performance (efficiency) will be the next targets. Stirling engine developers – like microturbine developers – seem to be concluding that the market in the 25 kW capacity will not be robust enough to support the manufacturing numbers required. Models with higher capacities have to be introduced in the market. These improvements will increase their attractiveness for on-site power and CHP applications.

2.5.5.2 Efficiencies Table 2.6.4 – Summary of the main characteristic parameters of some CHP technologies Gas Turbine

Reciprocating Engine (Otto)

Reciprocating Engine (Diesel)

Steam Turbine

Combined Cycle

Micro Gas Turbine

Fuel Cell

Stirling Engine

Status

Commercial

Commercial

Commercial

Commercial

Commercial

Commercial

Early entry / development

Early entry / development

Electrical power

500 kW – 50 MW

3 kW – 6 MW

200 kW – 20 MW

400 kW –300+ MW

10 – 400 MW

30 kW – 250 kW

1 kW – 1 MW

1 – 55 kW

Power/Heat ratio

0.2:1 – 0.67:1

0.33:1 – 1:1

0.33:1 – 2.0:1

0.1:1 – 0.5:1

0.33:1 – 2:1

0.4:1 – 0.83:1

0.67:1 – 2.0:1

1.25:1 – 2.0:1

Electrical Eff. (%) (LHV)

32 - 46

25 - 43

35 - 45

10 - 45

55 - 60

25 - 33

30 – 65

20 –25

Global Efficiency (%)

65 - 90

70 - 92

65 - 90

60 - 85

75 - 90

80 - 85

80 - 90

60 - 80

Availability (%)

90 - 98

92 - 97

90 - 95

Close to 100

95 - 98

90 - 98

> 95

n. a.

Start-up time

5 – 10 min

10 s

10 s

1 h – 1 day

Depends on the ST installed

60 s

3–8h

n. a.

Emisions (@ 15%O2)

NOx – 25 ppm CO – 50 ppm

NOx <200 ppm

NOx < 9 ppm CO < 50 ppm

NOx < 1ppm CO < 2ppm

Lower than recip. engines

Installed area (m2/kW)

0.037 – 0.065

0.02 – 0.029

0.027

0.037 – 0.167

n. a.

NOx <160 ppm Depends on the Depends on the Co <70 ppm type of fuel type of GT 0.02

< 0.01

0.074

2.5.5.3 Compatibility with demand The selection of the appropriate technology for a specific application depends in most cases the choice of the prime mover will be determined by site requirements. This in turn will dictate the other items of plant. The main indicators are described below. Reciprocating Engines may be suitable for sites where:       

Power or processes are cyclical or not continuous Low-pressure steam or medium or low temperature hot water are required There is a low heat:power demand ratio When natural gas is available, gas powered reciprocating engines are preferred When natural gas is not available, fuel oil or LPG powered diesel engines may be suitable Electrical load is less than 1 MWe - spark ignition (units available from 3 kWe to 10 MWe) Electrical load greater than 1 MWe - compression ignition (units from 100 kWe to 20 MWe)

Gas turbines may be suitable if:     

Power demand is continuous, and is over 1-3 MWe Natural gas is available (although this is not a limiting factor) There is high demand for medium/high pressure steam or hot water, particularly at temperature higher than 140°C Demand exists for hot gases at 450°C or above – the exhaust gas can be diluted with ambient air to cool it, or put through an air heat exchanger (Also consider using in a combined cycle with a steam turbine)

Steam turbines may be the appropriate choice for sites where:       

Electrical base load is over 250 kWe There is a high process steam requirement; and heat:power demand ratio is greater than 3:1 Cheap, low-premium fuel is available Adequate plot space is available High-grade process waste heat is available (e.g. from furnaces or incinerators) Existing boiler plant is in need of replacement Heat: power ratio is to be minimised, using a gas turbine combined cycle

Microturbines, Fuel Cells and Stirling engines, these tend towards the small size ranges. Considerations also include the long-term availability and cost of fuel, the cost of electricity purchased, including charges associated with the provision of a back-up supply, and the credit earned for any exported electricity. In addition, the service and technical support available from the equipment suppliers, and the proven reliability of particular machines, may have a significant bearing on the outcome of the selection procedure.

2.5.5.4 Barriers for their implementation Economic    

High prices for fuels, usually due the fact that CHP users are smaller fuel users than the large traditional electricity producers. Payment for exported electricity too low. Installations costs per kilowatt usually higher than in a larger electrical plant. Transportation problems and seasonally when works with biomass.

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Not enough technical and economic information to make a decision.

Regulatory    

Definition of the CHP too restrictive. Restrictions on trading surplus electricity. Lack of reward for contribution to reduce national emissions. Access to the electricity market, especially if there are small producers.

Technical    

Extent of gas grid. Running hours per annum. The quality of fuel. Seen as complicated to operate.

Market   

Limited customer awareness Lack of awareness of finance options Restrictive dispatch tolerances

2.5.6

Techno-economic aspects

If the technical assessment shows that several alternative cogeneration schemes might be acceptable (as is frequently the case) an economic assessment is needed for each one before the final choice is made. During this evaluation there will be areas of interface with the technical assessment which may itself be modified as a result. Capital Cost This is the cost required for the establishment of an operational CHP system on the site, and comprises: • • • • • • • • •

engineering design; compliance with planning and building regulations; environmental requirements, fire prevention and protection; cogeneration unit(s) and associated plant (installing, testing and commissioning); fuel supply and handling; connection charges; all associated mechanical and electrical services (installing and commissioning); new buildings, modification to existing buildings, foundations and support structures; operator training and any special tools needed for servicing and repair;

Operating Costs These are the annual costs of operating cogeneration plant and comprise: • •

fuel for the prime mover, and for supplementary and auxiliary systems if applicable; labour for operating and servicing the plant;

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maintenance materials and labour, including scheduled maintenance carried out by the manufacturers. As some scheduled component replacements are often at long intervals, maintenance costs should preferably be averaged over several years; consumables, e.g. lubricating oil, feedwater treatment chemicals, cooling tower dosing, as applicable; back-up electricity prices and complementary and export electricity prices.

Savings If the cogeneration plant provides a relatively small proportion of the site's energy demands and the unit costs of providing complementary heat and electricity remain unchanged, annual savings are readily derived by subtracting the cogeneration total running cost from the existing cost of the energy it displaces (both thermal and electrical). This is not correct when the proportion of energy provided by the CHP system is such high that the costs of providing the remainder are significantly changed. For example, the reduced amount and different load profile of imported electricity may mean higher tariffs; the reduced and possibly intermittent loading of conventional boilers may have some effect on heat costs. In this case, the use of cogeneration running costs alone is insufficient and comparison of total site energy costs with and without cogeneration is necessary. Overall economics of cogeneration projects Under favourable circumstances cogeneration projects can result in simple payback periods of three to five years. The economics of cogeneration projects are much more sensitive to changes in electricity price than to changes in fuel price; for example a 10% increase in electricity prices might reduce the payback period by 15% whereas a 10% reduction in fuel price would reduce the payback period by only 6%. This low sensitivity to fuel prices is due to the fact that increased (or reduced) fuel prices increase (or reduce) both cogenerator running costs and boiler energy displacement savings. Such a sensitivity analysis should be part of the feasibility study. Factors favouring short payback periods include: • • • • •

low investment cost; low fuel price; high electricity price; cogeneration fuel price premium (compared with boiler fuel); high annual operating hours (contemporary heat and power demand);

In the following paragraphs the costs related to the three technologies described in the previous section are detailed.

2.5.6.1 Internal Combustion Engines Capital Cost Installed costs can vary significantly depending on the scope of the plant equipment, geographical area, competitive market conditions, special site requirements, emissions control requirements, prevailing labour rates, and whether the installation is a new or retrofit application. Smaller genset packages are often less costly on a specific cost basis (€/kW) than larger gensets. Smaller engines typically run at a higher speed (rpm) than larger engines and often are adaptations of high-production-volume automotive or truck engines. These two factors combine to make the small engines cost less than larger, slower-speed engines. The basic genset package consists of an engine connected directly to a generator without a gearbox. In Europe where 50 Hz power is used, the engines run at speeds that are sub-multiples of 3000 rpm, typically 1,500 rpm for smaller high-speed engines.

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Some smaller packages come with an enclosure, integrated heat-recovery system, and basic electricparalleling equipment. The cost of the basic engine genset package plus the cost for added systems needed for the particular application or site comprise the total equipment cost. Installed costs for engine based CHP systems suitable for distributed generation (sizes ranging from 100 kW to 5 MW) are usually in a range from 750 to 1150 €/kW. Table 2.6.5 and 6 and also the figure 2.6.8 show some data on small-medium scale reciprocating engines. Table 2.6.5 - Review of investment data on reciprocating engines (Includes the heat recovery system for the exhaust gas and cooling of the engine and lubricating oil). Year Company [kW] (€/kW) Ref. feb-02 MAN 100 1676 13 feb-02 Cummins 300 1328 13 feb-02 Caterpillar 800 1106 13 feb-02 Caterpillar 3000 1018 13 feb-02 Wartsila 5000 1018 13 2003 10-5000 671-958 7 2003 100 1293 7 2003 300 1111 7 2003 1000 905 7 2003 3000 895 7 2003 5000 852 7 1800 1600

[€/kW]

1400 1200 1000 800 600 400 0

1000

2000

3000

4000

5000

6000

[kW] 2002

2003

Figure 2.6.8 – Unitary cost of reciprocating engines as a function of their nominal capacity [20, 12].

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Table 2.6.6 - Estimated capital cost for reciprocating engines in grid-connected CHP applications [7].

Nominal capacity (kW) Cost (€/kW) Equipment Genset Package Heat recovery Interconnection / Electrical Total equipment

100

300

1000

3000

5000

479 incl. 240 719

335 72 144 651

354 86 96 537

422 62 72 556

431 38 62 532

Labor / Materials Total process capital

396 1114

293 945

230 766

211 766

201 733

72 72 36

67 67 33

54 54 27

56 46 27

53 42 27

1294

1111

901

895

855

Project, cosntrcution and management Engineering and fees Project contingency Total plant cost (€/kW)

Next the investment cost for some micro-CHP reciprocating engines is given: • • •

13.5 kWe (EC Power Ltd): 17.000 € (natural gas) to 19.000 € (diesel, 17 kWe). 4.7 kWe (EcoPower): 13.500 € (plus additional costs for modem and software, commissioning, etc). 5.5 kWe (Senertech Dachs): 15.300 € (plus other additional costs)

Maintenance Maintenance costs vary with engine type, speed, size, and number of cylinders, and typically include: • • •

Maintenance labour Engine parts and materials, such as oil filters, air filters, spark plugs, gaskets, valves, piston rings, electronic components, and consumables (such as oil). Minor and major overhauls.

Recommended service is comprised of routine short-interval inspections/adjustments and periodic replacement of engine oil and filter, coolant, and spark plugs (typically at 500 to 2,000 hours). Full maintenance contracts (covering all recommended service) generally cost 0.6 to 1.6 €cents/kWh, depending on engine size, speed, and service, as well as customer location. Many service contracts now include remote monitoring of engine performance and condition and allow predictive maintenance.

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Table 2.6.7 - Review of operation and maintenance data on reciprocating engines Year feb-02 feb-02 feb-02 feb-02 2003 2003 2003 2003 2003 2003

Company MAN Cummins Caterpillar Caterpillar -

[kW] 100 300 800 3000 10-5000 100 300 1000 3000 5000

(€/kW) 0,02 0,014 0,011 0,01 0.008-0.017 0.0172 0.0125 0.0086 0.0086 0.0077

Ref. 13 13 13 13 7 7 7 7 7 7

Table 2.6.8 - Typical natural gas reciprocating engines operation and maintenance [7]. Nominal capacity [kW] Variable (service contract) [€/kWh] Fixed, [€/kW-yr] Fixed [€/kWh @ 8000 h/yr] Total O&M costs [€/kWh]

100

300

800

3000

5000

0,016

0,115

0,008

0,008

0,008

19,161

4,790

3,832

1,437

1,054

0,001

0,001

0,00048

0,00018

0,00013

0,017

0,012

0,009

0,009

0,008

2.5.6.1.1 Gas turbines Capital Cost Installed cost can vary significantly depending on the scope of the plant equipment, geographical area, competitive market conditions, special site requirements, emissions control requirements, prevailing labor rates, and whether the installation is a new or retrofit application. An industrial-size gas turbine generator is a complex system with many interrelated subsystems. The basic package consists of the gas turbine system, gearbox, electric generator, inlet and exhaust ducting, inlet air filtration, lubrication and cooling systems, standard starting system, and exhaust silencing. Smaller units may include an outdoor enclosure with control panel, batteries, and fire protection. There are definite economies of scale for larger turbine power systems. The 1 MW turbine systems are about twice as costly as turbines above 5 MW. While turbine package costs (per MW) decline only slightly in the range of 5 to 40 MW, ancillary equipment such as the HRSG, gas compression, water treatment, and electrical equipment cost much less per unit of electrical output for larger systems. The total plant cost consists in the cost of all equipment plus freight, installation labor and materials, engineering, project management, site work, licensing and insurance, commissioning and start-up, permits, and licensing. Considering a gas turbine based CHP system with DLE emissions control, HRSG, fuel gas compression, treatment for the boiler feed water, basic utility interconnection for parallel power generation, and minimal site preparation excluding costs of selective catalytic reduction system, supplementary firing or duct burners, or building construction) in a power range suitable for distributed generation the total CHP plant cost vary from 1570 €/kW for 1 MW systems to 580 €/kW for 40 MW systems. The installed cost in the range of 0.5 – 50 MW is around 400 – 900 €/kW.

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Maintenance Routine maintenance practices include online running maintenance and preventive maintenance procedures. These procedures include predictive techniques, such as plotting trends in performance, fuel consumption, heat rate, and vibration. Daily maintenance by site personnel includes visual inspection of filters and general site conditions. Routine inspections are required every 4,000 hours to ensure that the turbine is free of excessive vibration due to worn bearings, rotors or damaged blade tips. Gas turbines need to be overhauled every 25,000 to 50,000 hours, depending on service, and the overhaul is typically a complete inspection and rebuild of components to restore the gas turbine to original performance standards. A typical overhaul consists of dimensional inspections, upgrading and testing of the turbine and compressor, rotor removal, inspection of bearings, blade inspection and clearances. Gas turbine maintenance costs can vary significantly, depending on the quality and diligence of the preventative maintenance program and operating conditions. Although gas turbines can be cycled, maintenance costs for a gas turbine that is cycled every hour can be three times as high as for a turbine that is operated for intervals of 1,000 hours or more. Operating a turbine above its rated capacity for significant periods of time will dramatically increase the number of hot path inspections and overhauls needed. Gas turbines that operate for extended times on liquid fuels will need shorter than average overhaul intervals. The operation and maintenance cost in the range of 0.5 – 50 MW is around 0.004 – 0.009 €/kWh.

2.5.6.2 Steam Turbines Capital Cost Steam turbine-based CHP plants are complex, with many interrelated subsystems that usually must be custom designed. The cost of complete solid-fuel CHP plants depends on many factors, including major cost items, such as fuels handling, pollution-control equipment, and boilers. A typical breakdown of installed costs for a complete steam turbine CHP plant is boiler (25%); fuel handling, storage, and preparation system (25%); stack gas cleanup and pollution controls (20%); steam turbine generator (15%); and field construction and plant engineering (15%). The electrical generator can account for 20% to 40% of the cost of the turbine-generator assembly. Because of both the size of such plants and the diverse sources of the components, solid fuel cogeneration plants invariably involve extensive system engineering and field labor during construction. Steam turbine prices depend greatly on the extent of competition and related manufacturing volumes for units of desired size, inlet and exit steam conditions, rotational speed, and standardization of construction. Prices per kW for steam turbines are higher for smaller turbines. Typical complete plants cost more than 830 €/kW, with little generalization; although, for the same fuel and configuration, costs per kW of capacity generally increase as size decreases. Maintenance Steam turbines are rugged, with operational life often exceeding 50 years. Maintenance is simple and steam turbine maintenance costs are quite low, typically less than 0.4 €cent/kWh. Boilers and any associated solid-fuel processing and handling equipment that is part of the boiler/steam turbine plant require their own types of maintenance.

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2.5.6.2.1 Micro gas turbines Costs Table 2.6.9 - Review of investment data on micro gas turbines. Year

Equipment

2001 2001 2001 2001 2001 may-01 sep-01 mar-02 mar-02 mar-02 mar-02 2002 2003 2003 2003 2003 2003 ene-04 2004 2004 sep-05

Capstone 330 (Recup) Capstone 60 (Recup) ElliotTA-45 (sin recup) ElliotTA-45R (Recup) Capstone 330* Ingersoll Rand* Turbec* DTE* Capstone 330* Ingersoll Rand 70LM* Bowman TG80* Turbec T100* Capstone Turbec -

Power [kW] 30 60 45 45 80-100 30 70 100 350 30-250 30 70 80 100 30-60 100 30-300

Unitary cost (€/kW) 976 837 668 895 837 - 1255 1255 - 1778 800 2783 2247 1727 1481 1106 - 1328 1437 - 2203 2525 1845 1851 1695 795 - 954 1046 78444 839 - 1259

Unitary cost (€/kWh) 0,0042 - 0,01 0,084 - 0,126

* Includes installation costs and the heat recovery system. 3000

2500

[€/kW]

2000

1500

1000

500

0 0

20

2001

40

2002 (incl. installation costs)

60 [kW]

80

2003 (incl. installation costs)

100 2004

Figure 2.6.9 – Unitary cost of micro gas turbines.

120 2005

Ref. 2 2 2 2 2 3 4 5 5 5 5 6 7 7 7 7 7 8 9 9 10

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Table 2.6.10 - Estimated Capital cost for micro gas turbines in grid connected CHP applications [7]

30

Ingersoll Rand 70

1054 172 96 172 1226 628 1854

1025 incl. incl. 110 1135 425 1561

958 72 incl. 110 1140 426 1566

881 72 Incl. 96 1049 386 1435

149

114

114

103

149 104

91 80

91 80

84 72

2257

1845

1851

1695

Capstone Nominal capacity (kW) Cost (€/kW) Equipment Microturbine package Gas Booster Compressor Heat recovery Controls / Interconnection Total equipment (€/kW) Labor / Materials Total capital (€/kW) Project, cosntruction and management Engineering and fees Project contingency Total Plant Cost (€/kW)

Bowman

Turbec

80

100

Maintenance Table 2.6.11 - Review of Operation and maintenance cost data on micro gas turbines. Year

Equipment

Power [kW]

Unitary cost (€/kW)

Unitary cost (€/kWh)

Ref.

sep-01 may-03 2003 2003 2003 2003 2003 2004

-

80-100 30-250 30 70 80 100 -

0,002 - 0,01 -

0,01 0,0125 - 0,019 0,0192 0,0144 0,0125 0,0144 0,008 - 0,126

11 12 7 7 7 7 7 8

* Includes installation costs and the heat recovery system.

2.5.6.2.2 Stirling engines The investment cost of Stirling engines in the literature is estimated as 1570 – 2350 €/kW in the range of 1 – 600 kWe (ref. 1). The Stirling model with the highest presence in the market so far, SOLO Stirling 161 costs around 29000 € (9.5 kWe).

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2.5.6.2.3 Fuel Cells Costs Table 2.6.12 - Review of investment data on fuel cells Year

FC Type

[kW]

(€/kW)

(€/kWh)

may-01 may-03 2003 Sep-05 Sep-01 2002 Mar-02 Apr-02 Apr-02 2003 2003 2002 Mar-02 Apr-02 2003 2002 Mar-02 Apr-02 Apr-02 2003 2003 2001 Sep-01 2002 Mar-02 Apr-02 2003 -

n.a. n.a. n.a. n.a. PEMC PEMC PEMC PEMC PEMC PEMC PEMC PAFC PAFC PAFC PAFC MCFC MCFC MCFC MCFC MCFC MCFC SOFC SOFC SOFC SPFC SOFC SOFC SOFC

1-200 5-250 1-200 8-400 300 0,1-500 10 200 150-250 5-10 11000 5-200 200 200 2200 800-2000 250 2000 250 2000 60-4000 100000 2,5-100000 100 100-250 -

3138 - 4184 2874 2682 - 4503 2517 - 3356 6014 - 6798 6000 - 20000 4425 6085 3983 3640 5269 2400 - 5000 3319 - 3872 4978 4982 10000 885 - 2212 5532 3098 4790 3114 1046 - 1569 5753 - 7060 30000 1360 - 2092 3661 3468 2615

0,002 - 0,016 0,0839 - 0,126 -

Ref . 3 12 7 10 1 6 15 16 16 7 7 6 15 16 7 6 15 16 16 7 7 2 1 6 15 16 7 14

Table 2.6.13 - Estimated capital cost for fuel cells in grid-connected CHP applications, based on estimated target entry prices to users (2003, ref. 7). Nominal capacity (kW) 200 10 200 250 2000 100 PAFC PEMFC PEMFC MCFC MCFC SOFC Fuel cell type Coste (€/kW) Equipment Package Cost Grid isolation breakers Total equipment Labor / Materials Total process capital

4311

4503

2989

4167

2711

2730

96 4407

240 4742

96 3085

96 4263

19 2730

115 2845

287

96

287

287

220

316

4694

4838

3372

4551

2951

3162

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Project, cosntruction and management Engineering and fees Project contingency Total Plant Cost (€/kW)

05/05/2006

149

144

268

125

96

86

144

57 86

86 77

57 86

57 86

29 48

77 86

4982

5269

3641

4790

3114

3468

Maintenance Table 2.6.14 - Review of operation and maintenance cost data on fuel cells Year May-03 Apr-02 2003 Apr-02 Apr-02 2003 2003 Apr-02 Apr-02 2003 Apr-02 2003

FC Type n.a. PAFC PAFC PEMC PEMC PEMC PEMC MCFC MCFC MCFC SOFC SOFC

[kW] 200 200 10 20 5-10 150-250 250 2000 250 10 100-250

(€/kW) -

(€/kWh) 0,003 - 0,014 0,032 0,028 0,037 0,025 0,032 0,022 0,048 0,037 0,041 0,025 0,023

Ref. 12 16 7 16 16 7 7 16 16 7 16 7

Table 2.6.15 - Typical fuel cell systems (non-fuel) O & M costs (2003, ref. 7). Nominal capacity [kW] 200 38-630 150-250 250 2000 100-250 PAFC PEMFC PEMFC MCFC MCFC SOFC Fuel cell type Variable service contract 0,008 0,012 0,008 0,007 0,005 0,010 [€/kWh] Variable consumables [€/kWh] 0,0002 0,0002 0,0002 0,0002 0,0002 0,0002 6,227 17,245 6,227 4,790 2,012 9,580 Fixed [€/kW-yr] 0,001 0,002 0,001 0,001 0,000 0,001 Fixed [€/kWh @ 8000 h/yr] 0,018 0,018 0,013 0,034 0,026 0,012 Stack fund [€/kWh] 5 4 4 4 4 8 Stack life (años) 30 50 35 30 20 20 Recovery factor (%)* Total O&M cost [€/kWh] 0,028 0,032 0,022 0,041 0,032 0,023 *Recovery factor: catalyst recovery, metal scrap value and non-repeat hardware value at end of life.

2.5.7

Concepts for integration with other technologies and into networks

The typical application of CHP systems are described in the following. Industrial Cogeneration Industrial cogeneration schemes are typically located on sites that have a high demand for process heat and electricity all year. Suitable examples are found in the refining, paper, chemicals, oil, greenhouses and textile sectors. The industrial processes requiring heat can be classified according to the needed temperature level: • Low temperature processes (lower than 100°C), e.g. drying of agricultural products, space heating or cooling, and hot water.

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Medium temperature processes (100-300°C), e.g. processes in pulp and paper industry, textile industry, sugar factories, certain chemical industries, etc. In these processes heat is usually supplied in the form of steam. High temperature processes (300-700°C), e.g. in certain chemical industries. Very high temperature processes (higher than 700°C), e.g. in cement factories, primary metal industries, glass works.

The requirements for heat in industry are often in the form of steam and hence the majority of modern industrial cogeneration systems are based on gas turbines. A number of larger systems use combined cycle cogeneration. Industrial cogeneration installations can operate for 8000 hours/year or more. District Heating Cogeneration District heating (DH) is one of the three main applications of cogeneration. The heat provided by cogeneration is ideal for providing space heating and hot water for domestic, commercial or industrial use. The use of natural gas as a fuel gives added flexibility to district heating systems. Engines, providing electricity and heat, in combination with boilers, can introduce more cogeneration into existing DH networks. The operation of a DH network faces a unique set of challenges. Modern distribution pipes have made it more economic to transport heat over considerable distances but the cost is still high. New networks require extensive civil works and the appropriate permissions for planning and access. Historically the costs of building networks have been subsidised by local or national government but this type of funding is no longer as readily available as it has been in the past. In district heating applications, in addition to the distance and dispersion of users, the thermal power required and the annual number of degree-days are important parameters for the feasibility. In most of the cases the economic distance for transfer of heat does not exceed 10 km; in exceptional cases it may reach 30 km. Residential and Commercial Cogeneration The cogeneration systems used in residential and commercial applications tend to be smaller systems, often based on 'packaged' units. Packaged units comprise a reciprocating engine, a small generator, and a heat recovery system, housed in an acoustic container. The only connections to the unit are for fuel, normally natural gas, and the connections for the heat and electricity output of the unit. These systems are commonly used in hotels, leisure centres, offices, smaller hospitals, and multi-residential accommodation. Suitable reciprocating engines are normally stationary diesel or automotive engines that have been converted to run on natural gas. They can also be dual-fuelled. The heat recovery is via the engine’s cooling circuits, and its exhaust so to ensure a high availability of electricity there must be a simultaneous use for the heat or heat storage facilities. Larger applications are based on technology that is similar to the cogeneration systems used in industry, gas turbines, or larger reciprocating engines. Such systems are used in larger hospitals, large office complexes, universities and colleges. From the point of view of heating and cooling demands, three subsectors can be identified: • • •

hospitals and hotels apartment buildings office buildings.

Each one of these subsectors has its own profile. Other buildings (such as universities and stores) have load profiles that are combinations of the profiles of the three subsectors. Trigeneration

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Trigeneration can be defined as the conversion of a single fuel source into three energy products: electricity, heat (steam or hot water) and cooling (chilled water), with lower pollution and greater efficiency than producing the three products separately. There are different methods for coupling a conventional cogeneration system with a chiller either by compression (cogeneration to drive refrigeration compressors) or by absorption (using heat to create cooling). The barriers facing the growth of CHP combined with cooling, can be even more severe than the barriers for CHP growth. For the time being, it increases the costs of the system considerably. Trigeneration can be applied to all the applications of cogeneration: District cooling: It is particularly suitable in urban areas with high density arrangement offices and residential dwellings requiring air conditioning. In this application absorption chillers are often favoured because they don’t use chlorofluorocarbons and they can be used in conjunction with cogeneration systems for thermal and electrical energy. The chilling equipment can be based centrally, with chilled water piped to users, or can be located on the premises of the user. The most economic choice will depend on the application and geographical distribution. District cooling systems using absorption chillers often complement district heating systems, when both use heat supplied from a cogeneration plant. The heat demand in summer is lower than in winter and heat-driven district cooling, which requires the heat mainly in summer, can help to balance the seasonal demands for cogenerated heat. In Europe, there is awareness of the technology, but there is certainly less experience –with the possible exception of Sweden. An additional barrier that these systems face in Europe, apart of the fact that installing cooling increases the initial costs of the system considerably, is that the most suitable applications will be found in the South of Europe, which means, in countries where there is less experience of district heating (and where networks would have to be built), and hence less history among consumers or suppliers of the provision of this type of central energy. Cooling demand in industries: Many industries, in particular the food industry, lack sources of cold water during summer. River water is often at temperatures 25°C to 30°C rather than the 10°C to 15°C required. Cooling in individual buildings: These systems are used in hotels, sport and leisure centres and residential accommodation. The CHP systems are smaller units, normally based on engines (gas or diesel). The heat recovery is via the engine’s cooling circuit and its exhaust. To ensure a high availability of electricity there must be a simultaneous use for the heat and the heat storage facilities. A method increasing the use of recovered heat is to produce cooling using absorption chillers. This allows the CHP system to run during the summer months, when the lower demand for heating would otherwise reduce the opportunity for system operation. Other applications Two other applications of cogeneration, which can be mentioned here, are landfills and sewage treatment plants. In both cases, a fuel gas is produced, which can fuel a gas engine cogeneration unit. Gasifiers that convert crop residues or wood to low or medium heating value gas can be connected with internal combustion engines. The main concern about gasification is to produce a gas clean enough10 to be used in gas fired engines. Anaerobic digestion of animal wastes from confined livestock operations also could be used to produce biogas (a mixture of 60% methane and 40% carbon dioxide) to fuel an internal combustion engine.

10

Tar is one of the main contaminants contained in producer gas (gas obtained through gasification process) affecting gas fired engines durability.

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The possibilities for the integration between the different technologies are described next. Reciprocating engines The following are the most common applications for thermal energy produced for other applications:   

Recovery of heat from the exhaust gases and from the cooling system to produce steam up to 15 bar steam and/or hot water at 85-90ºC. Direct use of the exhaust gases mainly for drying. Production of hot air through the installation of suitable exchange devices.

Some type of wastes can be gasified and the resultant gas used to fuel a gas turbine or gas engine installation. The higher nominal capacity reciprocating engines can be used in combined cycles with steam turbines. Gas Turbines 

Generation of steam in a Heat Recovery Steam Generator (HRSG) at high pressure for use in a steam turbine An important advantage of CHP using gas turbines is the high-quality waste heat available in the exhaust gas. The high-temperature exhaust gas is suitable for generating highpressure steam, making gas turbines a preferred CHP technology for many industrial processes. In simple cycle gas turbines, hot exhaust gas can be used directly in a process or by adding a heatrecovery steam generator (HRSG) that uses the exhaust heat to generate steam or hot water. Because gas turbine exhaust is oxygen-rich, it can support additional combustion through supplementary firing. A duct burner can be fitted within the HRSG to increase the steam production at lower-heating value efficiencies of 90% and greater.



Combined Gas Turbine and Fuel Cell system: This type of combined system is not already commercially available and offers the highest electrical efficiency of all the so far tested electric generation systems. There are at least two possible configurations. In one of them the fuel cells substitutes the combustion chamber in the gas turbine. The compressed air is used in the fuel cell and the exhaust from the fuel cell is later expanded in the gas turbine. The second configuration is based in the exchange of heat between both systems. In this hybrid configuration the fuel cells does not need to operated at the turbine pressure, instated it operates at the preferred ambient pressure and is independent of a gas turbine cycle pressure ratio.



The available mechanical energy can be applied not only to produce electricity through a generator but also to drive pumps, blowers and compressors (as in natural gas transport networks).



The exhaust gases can be used for direct firing and drying processes. The single flow of heat at high temperature is suitable for processes in which direct contact with combustion gases is permissible. This means that intermediate fluids (steam, hot water, and heat transfer fluids) are unnecessary, and hence, in theory, the highest levels of thermal efficiency can be achieved. However, it is important to assess whether the direct use of the exhaust gases will affect product quality, and for this reason direct use is normally restricted to natural gas-fired gas turbines.



Some type of wastes can be gasified and the resultant gas used to fuel a gas turbine or gas engine installation.



Gas turbines can work with inlet cooling technologies of different types to improve its performance.

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One solution that permits maximising power output for any given steam demand is to reinject steam from unused steam generating capability directly into the gas turbine, insofar as the design will allow, to increase both the power output and the efficiency by using more of the otherwise wasted exhaust energy. The mass flow through the turbine is increased without increasing the work consumed in the compressor so the net power output increases. The arrangement is known as the steam-injected-gas-turbine (STIG) and has the added advantage of reducing the nitrogen oxide (NOx) emissions because the combustion temperature is lowered. A similar effect is achieved spraying water.

Steam Turbines 

Steam Turbine cycles can be integrated with an incinerator (burning a wasted fuel, such as farm wastes or municipal solid waste) and with any other toping cycle producing heat at high temperature (combined cycles).

Combined cycles 

Combined Cycles like gas turbines can work with inlet cooling technologies of different types to improve its performance.



In an IGCC (Integrated Gasification Combined Cycle) plant, coal is gasified in a reaction vessel. The hot gases are then cleaned and, after combustion, expanded through a gas turbine for power generation. Waste heat from the gas turbine and from gas cleaning and gasification processes is used to raise high-pressure steam for additional electricity generation. "First-of-a-kind" IGCC plant have been shown to achieve net efficiencies of around 45%, but, with technology and cycle improvements, net efficiencies could reach 51-52%. Furthermore, IGCC technologies are appropriate for fuels other than coal, eg petroleum coke, refinery bottoms. Variants in IGCC technology include different types of gasifier (eg fluidised bed, entrained flow, slagging-type), different gasifying media (oxygen or air, and steam), and full-gasification or partial-gasification followed by combustion.

Micro gas turbines 

Hybrid system with Fuel Cells to produce combined micro gas turbines/fuel cells systems.



High temperature exhaust gases available for drying processes direct driving of absorption chillers, etc.

Fuel Cells There are many possible applications for the recovery of heat depending on the type of fuel cell. In table 2 some indications are given.

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Table 2.6.16 – Main chracteristics of different types of fuel cells. Source: A guide to Decentralized Energy Cogeneration, 2003

Electrical Efficiency* Range

Phosphoric Acid Fuel Cell (PAFC)

Polymer Electrolyte Fuel Cells (PEMFC)

Solid Oxide Fuel Cells (SOFC)

Molten Carbonate Fuel Cells (MCFC)

Alkaline Fuel Cells (AFC)

36-42

30-40

45-60

45-50

70

3-250 kW T=80ºC Can be use in cogeneration to produce hot water. Ideal for space or water heating.

1-10 MW

100-200 kW T = 200ºC Recovered heat to be use for space Heat or water heating, Application often suiting district heating system

250 kW – 5 MW T=650ºC. T=1000ºC. Recovered heat Recovered heat to to be use for be use for commercial industrial buildings and processes combined cycle applications.

10-200 kW T=80ºC Would be use in stationary applications and in desalination plants.

* Electrical efficiencies are based on values for hydrogen fuel and do not include electricity required for hydrogen reforming. Some research is currently underway to develop hybrid systems of fuel cells/gas turbines and fuel cells/micro gas turbines. Stirling engines





Stirling engines are use for micro-cogeneration boilers, because for this kind of boilers, there is a need for small engines with a capacity between 0,2 and 4 kWe, for that reason they are a good alternative. There is a possibility of using a solar dish to heat the Stirling Engine eradicating the need for combustion of a fuel.

2.5.7.1 Site Appraisal When evaluating the opportunity of a CHP installation it is recommended to proceed in two stages. Stage 1 - An initial appraisal to determine whether it is worth committing the resources necessary to undertake a detailed feasibility study. Stage 2 - If the initial appraisal shows that, in principle, cogeneration is a viable option for the site, then a second stage detailed technical appraisal should be undertaken. The study should be based on careful analysis of site energy demand to enable appropriate, cost effective cogeneration plant to be specified. It will also examine the effects on overall performance of plant optimisation, export of electricity and integration with any existing plant. Startup A checklist can be adopted before proceeding with the planning of a cogeneration plant: 1. Have all other energy saving measures been identified and either implemented or taken into consideration? 2. Is there a simultaneous base load requirement for electricity and heat which exceeds electrical and thermal peak power respectively for more than 4,500 hours/year? 3. Are the thermal loads compatible with the heat provided by available cogeneration technologies? 4. Is there a suitable fuel supply?

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5. Is there suitable access and space for a cogeneration unit and is the location suitable with respect to other site functions (e.g. noise and exhaust)? 6. Are the fuel and electricity consumption records available on a monthly or more frequent basis? 7. If there are any site changes/developments planned, have the possible effects on the cogeneration size/economics been taken into account? 8. Is there a requirement to upgrade any part of the existing heating, electrical distribution or control system as a result of the cogeneration installation? 9. Is the proposed heat user near to the proposed cogeneration location and electrical distribution system? 10. Is there a likelihood that direct funding or an alternative route to funding is available? Site Energy Profiles If the initial assessment suggests that it is worth proceeding further, then detailed investigatory work will have to be undertaken. The starting point for all detailed cogeneration feasibility studies is to gain an accurate assessment of the profile of electrical and thermal loads. Correct sizing of the cogeneration unit and choice of the prime movers are essential to the viability of the installation and they are only possible if the heat and electricity demands are clearly defined. Electrical load profiles can be relatively easily determined using a portable load monitor and recording power loads. If major differences in consumption and load occur between normal weekdays and Saturdays or Sundays these must be determined. Also, if the monthly invoices demonstrate major seasonal variations in consumption. Thermal loads are more difficult to measure accurately. A number of existing cogeneration systems have not achieved their anticipated savings because the plant was inaccurately specified, sometimes on the basis of existing installed boiler capacity. For the correct specification of cogeneration, the peak thermal demand of the site is of much less importance than the base load profile. Cogeneration is generally only cost effective if a sufficiently large heating or cooling requirement exists for most of the running hours. As a final note, cogeneration should not be sized based on a highly inefficient use of energy on the site. During the evaluation phase opportunities for reducing the site energy demand should be identified. Those that are cost-effective should be implemented. If they are not, then at least their impact needs to be taken into account in the sizing of the cogeneration plant. Failure to do this may result in an oversized and less economic cogeneration facility. Other Factors The location of the cogeneration system will also affect choice of plant. In particular, the following factors need to be considered: • • • • • •

access to services, including electrical, heating and fuel supplies; noise emissions; exhaust emissions; ventilation and air quality requirements; delivery, access and positioning of the system; maintenance requirements.

Selecting Appropriate Technologies for Specific Applications In most cases, the choice of the prime mover will be determined by site requirements. Steam turbines may be the appropriate choice for sites where: •

electrical base load is over 250 kWe

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there is a high process steam requirement and heat:power demand ratio is greater than 3:1 cheap, low-premium fuel is available adequate space is available high grade process waste heat is available (e.g. from furnaces or incinerators) existing boiler plant is in need of replacement heat:power ratio of an existing gas turbine is to be minimised, using a gas turbine combined cycle

Gas turbines may be suitable if: • • • • •

power demand is continuous, and is over 1 MWe (smaller gas turbines are just starting to penetrate the market) natural gas is available (although this is not a limiting factor) there is high demand for medium/high pressure steam or hot water, particularly at temperature higher than 140°C demand exists for hot gases at 450°C or above. The exhaust gas can be diluted with ambient air to cool it, or put through an air heat exchanger Also consider using in a combined cycle with a steam turbine

Reciprocating engines may be suitable for sites where: • • • • • •

power, or processes are cyclical or not continuous low pressure steam or medium or low temperature hot water are required there is a low heat:power demand ratio when natural gas is available, gas powered reciprocating engines are preferred electrical load is less than 1 MWe - spark ignition (units available from 3 kWe to 10 MWe) electrical load greater than 1 MWe - compression ignition (units from 100 kWe to 20 MWe)

Considerations also include the long-term availability and cost of fuel, the cost of electricity purchased, including charges associated with the provision of a back-up supply, and the credit earned for any exported electricity. In addition, the service and technical support available from the equipment suppliers, and the proven reliability of particular machines, may have a significant bearing on the outcome of the selection procedure.

2.5.8

Socio-economic aspects

In 1997, the European Commission published its Communication on a Community strategy to promote CHP and to dismantle barriers to its development. The communication argues that CHP could save on average 500 kg CO2 per MWh when compared with the separate production of electricity and heat. Full use of the technical CHP potential might thus save up to 9% of the EU-total CO2 production in 2010. There is an ongoing trend towards natural gas as principal fuel for CHP installations due to its availability, environmental benefits, and market penetration of gas turbines, gas engines, and in the forthcoming years probably gas-fuelled micro turbines and fuel cells. A key factor with regard to the current situation and further development of CHP in EU Member States is the liberalisation of the electricity and gas markets. Whilst in the long run liberalised energy markets are expected to help CHP realise its full potential, the transition period is often bad. Partial and imperfect market opening has put the CHP market on ice, led to a downturn in sales of CHP equipment in the past years. Mounting gas prices and dropping electricity prices in the period between 1999 and 2000 weakened CHP economies in most Member

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States. At present in many European countries gas and electricity prices are strongly correlated, leaving CHP less affected from energy price rises. In addition, ongoing legislative reforms and restructuring of the electricity and gas markets are causing uncertainty about the future prospects for CHP, leading to a “wait and see” attitude of potential investors and CHP producers. The obstacles to positive development in the CHP sector have been classified as follows: • Economic barriers These include unreasonably low rates at which CHP generators can sell electricity to the grid, high back-up tariffs, high fuel prices, unpredictability of price developments, a number of obstacles in financing CHP plants, prices which do not reflect the environmental benefits of CHP etc. • Regulatory barriers These include licensing procedures, planning regulations, unsuitable emission control schemes for small-scale CHP etc. • Institutional barriers These include attitudes of grid operators to the connection of the CHP unit etc. On the other hand, ongoing regulatory changes in the context of EU electricity market liberalisation, combined with increasing pressure to reduce CO2 emissions, have also been used to establish support mechanisms for CHP. Most countries also used this opportunity to introduce some kind legal definition of CHP, e.g. on the grounds of efficiency criteria. Within DECENT project, barriers and success factors for Decentralised Generation in the EU were identified through extensive case studies, expert interviews, and literature review. A list of the barriers and success factors identified in DG, expecially related to CHP systems, is shown below: Spatial planning & licensing For (natural gas based) CHP installations such problems matter less, since they are anyway integrated in building structures where energy converters are placed (industry, hospital, housing etc.). This does, however, not exclude regulatory obstacles, such as lengthy procedures to obtain operating permits, during the authorisation of decentralised CHP plants. As modern natural gas fired CHP engines usually comply with stringent air emission standards, for CHP installations usually noise might form a bottleneck for licensing, depending on the location Grid Connection Procedures Here, the terms of physical connection of the generator to the grid shall be distinguished from the terms of use of grid services, once the generator is interconnected. To form the basis for physical interconnection to the grid, DG developers have to agree with the grid operator / the utility on the technical terms of interconnection, on contractual matters including liabilities, and on the allocation of costs for feasibility studies, necessary grid reinforcements and line extensions. Such issues are covered by regulation in Member States to a different degree. Subject to uncertainty on the DG developer’s side are sometimes the technical specifications regarded as necessary by the grid operator

Intransparent Grid Use Fees

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In a liberalised market environment the grid operators charge fees to power traders. These grid use fees and the procedures how they are regulated have a high impact on DG viability, in case the generator operates on a trading scheme. However the majority of the projects that export power operates under a feed-in scheme, where the power is sold under regulated tariffs to the grid operator so that a trading operation as indicated above does not take place. However, it is anticipated that the relevance of grid use fees for DG will rise with ongoing liberalisation and the replacement of fixed feed-in tariff schemes by green certificate schemes. Second, during operation of the interconnected DG installation, regulated tariffs (or negotiated fees) will determine the costs that are associated with the use of the grid infrastructure both for supply of electricity to the grid/ to customers and for the demand of additional or back-up power (mostly relevant for CHP). Ratio of Gas and Electricity Prices The changing ratio between natural gas and electricity prices in the past years has made operation of natural gas fired CHP hardly feasible. This has been a major barrier for CHP development, and has led to the decommissioning of CHP plants in 2002. Nowadays in many EU countries gas generators are used in marginal plants11 thus setting the price for electricity: natural gas and electricity prices are strongly correlated. Local Resistance Despite the broadly accepted environmental benefits of DG, local resistance can be strong. Reasons for CHP systems are mainly source of air pollution closer to the people and noise. Local resistance can constitute a high barrier to be overcome in a development, since neighbourhood participation rights in spatial planning and licensing/siting processes have generally grown strong, and neighbourhood resistance might also be reflected in non-co-operation of local authorities. The FIRE study (Langniss, 1998) concludes that the financial involvement of local people can help reducing the barriers to renewable projects, because if local people can acquire equity shares of the project, their interest in the project’s success will be large. Another benefit is that project developers can – in an early stage – learn from local shareholders what the specific concerns of the local community are, and take these into account. The main recommendation, targeted to Member States, in order to reduce public opposition is to involve local actors. Schemes to ensure financial involvement in DG developments or benefits to the neighbourhood can help significantly to reduce local resistance and foster local support.

2.5.9

Design, simulation and optimisation tools

Detailed CHP analysis is needed to calculate the measures of energy and economic performance. In order to assess the performances there is need to construct a model of the system, i.e. a mathematical description of the system consisting of data, rules, inferences and equations, where the word system here includes not only the cogeneration unit(s) but also the facility, described by the various loads. A crude model, based on average demands and nominal or average performance of cogeneration units, most probably will produce inaccurate results, inappropriate even for a preliminary assessment. An accurate model based on demands for each hour real performance of the cogeneration units, as it is affected by partial load and ambient conditions may stay at various levels of approximation. For example, it may use:

11

According to economic theory prices are set by the short run marginal cost (‘SRMC’) of the plant producing the last unit of electricity required to meet demand. The logic of this process ensures that only those power plants operate that have the lowest SRMC among all generation units available to operate. For marginal and therefore price setting units – depending on the market in question – it would be expected that they are fuelled by natural gas or black coal.

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only a couple of days (e.g. weekday, weekend) for each season or each month; seven days a week for each season or month; every hour of a typical year (8760 hours).

At any level of approximation, for each hour of the day quantities such as the following are determined, taking into consideration any decisions regarding the operation mode of the cogeneration system: • • • • • • • • •

electrical and thermal loads of the facility (load profiles already created and used); power output of each cogeneration unit; power used on site; power purchased from or sold to the grid; cogenerated heat produced by each unit; cogenerated heat utilised from each unit; fuel consumption of each cogeneration unit; fuel consumption of boilers for supplementary heat; avoided fuel consumption of boilers due to cogeneration.

Depending on the electricity (and perhaps fuel) tariff structure, there may be need to produce cumulative results for each day or month. At the end of the year, quantities such as the following are calculated: • • • • • • • • •

annual number of operation hours of each cogeneration unit (it is verified that it does not exceed the expected availability; otherwise, the calculations have to be repeated with a modified operation mode), average electrical load factor of each cogeneration unit; percentage of cogenerated electricity used on site; percentage of required energy in each form covered by cogeneration; annual electrical efficiency of each cogeneration unit; annual thermal efficiency of each cogeneration unit (based on the utilised heat); annual total efficiency of each cogeneration unit (summation of the annual electrical and thermal efficiency); fuel energy consumption for separate production of electricity and heat; fuel energy savings ratio.

In a detailed hour-by-hour model, the effect of ambient conditions both on energy requirements and on cogeneration system performance is taken into consideration explicitly. Also, site loads can be modelled by considering factors such as building occupancy, type and performance of heating, ventilating and air conditioning system (e.g. compression or absorption units), process requirements, etc. Furthermore, hour-by-hour models allow for accurate calculation of cost for purchased electricity or revenue from selling excess electricity, if rates depend on the hour of the day. The calculations for energy performance are repeated for each characteristic year throughout the lifetime of the system. With more elaborate models, computer modelling and simulation is rather necessary; especially when the effects of alternative system configurations and assumptions or of process changes on the performance have to be studied. The designer may find it more efficient and not very difficult to develop a custom-made software, instead of using a commercial one. For each particular site, energy and economic performance measures are calculated for various configurations of cogeneration systems (number of units, capacity of each unit, heat recovery equipment, etc.). For each configuration, the calculations can be repeated with various models of operation, as well as with various assumptions on the values of technical and economic parameters, in particular those subject to an uncertainty. Based on the results, decisions can be reached on which of the examined systems is the most appropriate for the particular application. Alternative solutions to the cogeneration problem (i.e. alternative systems, from the point of view of configuration and capacity, operating under various pre-specified modes) are evaluated technically and

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economically, and the one with the best overall performance is revealed. However, except of simple applications, the variety of solutions is such that it is extremely difficult and time consuming, to identify and evaluate each one of them. In these cases, a much more efficient procedure to identify the best solution is to apply mathematical optimisation methods. The complete optimisation problem can be stated in the form of questions interwoven with each other: which are the configuration (set of interconnected equipment) of the system, the design characteristics of the components, and the operating strategy (mode) that lead to an overall optimum? The degree of freedom increases in multiproduct systems with production rates not always specified, as it is the case with cogeneration systems. Furthermore, time dependent operation adds one more dimension. In mathematical terms, the optimisation problem is stated by the objective function: min f(x,y,z) subject to the constraints: h i (x, y, z)=0 , i = 1, 2, ., I g j (x, y, z)<0 , j = 1, 2, ., J where x, y, z are the sets of independent variables for operation, design specifications and synthesis (configuration), respectively. Examples of objective functions in cogeneration system optimisation are the following: • • • • • •

maximisation of total efficiency, maximisation of fuel energy savings ratio, maximisation of net present value, maximisation of internal rate of return, maximisation of benefit to cost ratio, minimisation of the payback period.

Among the operation independent variables (x) is the power output of each cogeneration unit. Examples of independent variables for design (y) are the rated power of each unit, pressures and temperatures of fluids (if not strictly specified by processes), nominal efficiencies, etc. The independent variables for synthesis (z) indicate whether or not certain components exist in the system; the number of similar cogeneration units is an example; alternatively, the nominal power of a unit may be an independent variable for synthesis: a zero value indicates that the unit does not exist in the optimal configuration. The equality and inequality constraints, respectively, are nothing more than the model of the system, technical limits, and limits imposed by rules, regulations and contracts. In each time interval defined in such a way that a steady-state operation of the system can be assumed (e.g. each hour, in an hour-by-hour model), an operation optimisation problem can be stated by the operation objective function min f(x) subject to those of the constraints, which are related to the operation of the system. Examples of operation objective functions are the following (each one calculated for the particular time interval): • • •

maximisation of total efficiency, maximisation of fuel energy savings ratio, maximisation of operation profit.

Very often, the synthesis of the system under study is predetermined. In such a case z is known, and the problem is to determine the optimal design and the optimal operation mode in each time interval. As an example, let a cogeneration system be considered with a gas turbine and a double pressure exhaust gas boiler. The set y may include the nominal power output of the gas turbine, the low and

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high steam pressures and temperatures at design point, the nominal steam production rate at each pressure level. The set x in each time interval may include the power output, the steam production rate at each pressure level. If, for any reason, the operation mode in each time interval is predetermined, then the problem is simplified to a design optimisation one. It is solved with only y as independent variables. Many assumptions and parameters are involved in the formulation and solution of an optimisation problem, especially if economics are included. After solving the problem for a particular set of assumptions and parameters (called nominal set), it is necessary to determine the sensitivity of the solution to changes in the assumptions and parameters. This is called sensitivity analysis and entails the following steps: 1.

2.

3.

To find one or more parameters with respect to which the optimal solution is very sensitive. If such parameters exist, a change in the corresponding system features could be examined. To reveal additions or modifications to the system, which could improve the overall performance. For example, information can be obtained on whether increasing the capacity or introducing energy storage could be advisable. To reveal the effect of imprecisely known parameters on the optimal solution. Some parameters may have a considerable uncertainty. Sensitivity analysis can indicate whether it is worthwhile to expend resources to obtain better estimates of these parameter values. On the contrary, it may be revealed that the solution is not sensitive to parameters, which initially were thought of being critical; hence they need no further refinement.

The information thus obtained is often so important, that the sensitivity analysis may be equally valuable than the optimal solution itself. Two methods of sensitivity analysis are described in the following. Parametric study The optimisation problem is solved repeatedly for several values of a parameter in a certain range, while the values of all the other parameters are kept constant. The results are presented in graphs, where the optimum values of the independent variables and of the objective function are drawn as functions of the parameter. Three-dimensional graphs can illustrate the simultaneous effect of three parameters. Beyond that number the graphical representation is not clear or possible. Uncertainty evaluation Let pj ( j = 1, 2, ...) be the parameters with respect to which a sensitivity analysis is needed, and ∆pj the uncertainty (or change) in parameter pj. The uncertainty in the optimal value of the objective function due to uncertainty in the parameter pj is given by:

The most probable uncertainty in the optimum value of the objective function due to uncertainties in a set of parameters is estimated by:

It may not be easy to evaluate analytically the partial derivatives. Then, numerical evaluation is performed, replacing derivatives with finite differences at the vicinity of each pj.

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Such an analytical approach does not give the direct impression of a graphical one, but it can handle any number of parameters simultaneously.

2.5.10 References 1. G. Delcroix, “New technologies and Opportunities for Decentralized Energy Resources” ALSTOM. September 2001. 2. G.J. Williams, A. Sidde, K. Pointon, “Design optimisation of a hybrid solid oxide fuel cell & gas turbine. Power generation system”.Contractor: ALSTOM Power Technology Centre, 2001. 3. P. A. Sánchez, J. A. Martínez “Nuevas expectativas para la cogeneración. Microturbinas, pilas de combustible, motor de ciclo Stirling y otras aplicaciones”. Escan S.A. Energía. Mayo 2001. 4. “Micro-turbine Generators” Edited by Mj Moore. Published by Professional Engineering Publishing, Bury St Edmuds and London, UK. 5. “Technology Characterization: Microturbines” Prepared for: Environmental Protection Agency and prepared by: Energy Nexus Group, Virginia, USA, March 2002. 6. “DGnet.D5: Technical Assessment of DG-Technologies And Tendencies of Technical Devolopment”. WP 2. Review of the International state of the art. Mapping of the European Centres of Excellence and suppliers. 2002. 7. L. Goldstein, B. Hedman, D. Knowles, S. I. Freedman, R. Woods, T. Schweizer “Gas-fired Distributed Energy Resource Technology Characterizations”. NREL (National Renewable Energy Laboratory). NREL / TP – 620 – 34783, November 2003. 8. L. Jeffrey, P.E. Pierce, “Microturbine update” 7th Annual LMOP Conference and project expo” Hyatt Regency Capital Hill. Washington DC, January 6-7, 2004. 9. J. Aabakken, “Power Technologies Data Book”. NREL/TP-620-36347, NREL (National Renewable Energy Laboratory). June 2004. 10. “Pla de negoci empresarial de noves empreses tecnològiques”,. CIDEM. Generalitat de Catalunya, 2005. 11. A. H. Pedersen, “Microturbine energy systems. Description of an EU Project (OMES) and gained experiences with prototypes”, DONG A/S, Denmark. September 2001. 12. J. D. Hardy, “A cooling, heating and power buildings (CHP-B) instructional module”. Thesis of Master of Science in Mechanical Engineering, Dept. of Mechanical Engineering. Mississippi State University, EE. UU. Mayo 2003. 13. “Technology Characterization: Reciprocating Engines”. Prepared for: Environmental Protection Agency and prepared by: Energy Nexous Group, Virginia, USA, February 2002. 14. COGEN Europe, “Micro-CHP Fact Sheet. Germany”, March 2005. 15. O. Bailey, B. Ouagal, E. Bartholomew, C. Manray and N. Bourassa. “An EngineeringEconomic Analysis of Combined Heat and Power Technologies in a µ Grid Application”. Ernest Orlando Lawrence Berkley National Laboratory. Berkley, 2002. 16. “Technology Characterization: Fuel Cells”. Prepared for: Environmental Protection Agency and by: Energy Nexus Group; Virginia, USA. April 2002.

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3 Eco-building concepts (CREVER) Eco-buildings are buildings with substantially reduced impact on the environment compared to conventional buildings due to reduced energy demand for heating, cooling and lighting / electricity and efficient supply of remaining energy demand, usually with renewable energies and/or polygeneration. Eco-buildings thus combine Bioclimatic Architecture principles with techniques and systems generating energy at low environmental impact, that is, active and passive measures to save energy and protect the environment, while providing high comfort level of the occupants inside the building. In the best circumstances Eco-buildings consume no energy from external network or grid, but only the energy that is produced by itself and the energy that exists in the environment.

3.1

Analysis of technical aspects

As highlighted previously, eco-buildings combine active energy supply systems based on renewable energy and/or polygeneration with passive techniques to reduce the energy demand of the building (bioclimatic architecture concept). The bioclimatic architecture adopts an approach based on building shape optimisation, building orientation, evaluation of climatic parameters such as direction of dominant winds, etc. Basically, these measures should permit: • to take advantage of free energy (solar gain) and to reduce the energy losses of the building in winter in order to limit the heating demand, • to reduce the heat gain in summer in order to limit the cooling demand, • to take advantage of natural lighting in order to reduce the corresponding electrical consumption, • to permit a good ventilation of rooms with reduced heat wastes. Following, different measures will be described which can be included in eco-buildings to contribute to reduce the energy demand.

3.1.1

Passive measures for reduction of the energy demand

First of all different measures concerning the optimisation of the building envelope will be presented: a. Building compactness Primarily, eco-buildings should be designed with a compact shape in order to reduce the heat losses. Indeed, the smaller the building external surface for a given building volume, the lower is the global energy exchange between the building and the environment through the façades.

b. Transparent surfaces Glazed systems and transparent façades are critic elements of the building envelope. •

•

Energy efficient transparent surfaces of buildings need to have low thermal transmittance values in order to reduce thermal losses. The thermal transmittance is the heat power per surface area that is transmitted in/out the building due to temperature difference per each degree [W/(m2K)]). Transparent surfaces should also allow a satisfactory day-lighting of the building in order to reduce power consumption for lighting. The visual transmittance of glass is the fraction of

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incident solar light which is transmitted to the interior of the building. High values enhance the availability of daylight. Finally transparent surfaces should favour solar gain in winter without causing overheating in summer. The solar factor g is the fraction of incident solar energy which is transmitted to the interior of the building. Low values of the solar factor reduce solar gains. Depending on the climate, focus can be made on optimising solar gains in winter or limiting them in summer. Both aspects can be coupled using solar shading devices.

High insulation levels of windows can be obtained using double, or even triple glass. The air cavity between two panes contributes to significantly reduce the thermal transmittance of the window. Moreover the closed cavity allows the use of “soft coatings” with low-emissivity and/or selective properties on one of the panes and/or the use of low conductivity gases in the cavity, that improve considerably the glazing performance. Low-emissivity coating in the Far Infrared (FIR) contribute to reduce the thermal transmittance of a glazed surface by reducing the thermal radiant exchange between the two pans. With such coatings a reduction of the thermal transmittance of about 40 % can be obtained. An additional reduction of about 20% can be achieved by filling the cavity with a mix of air and a noble gas, such as Argon or Krypton, which have lower thermal conductivities than air. This type of glass is able to provide thermal insulation values similar to opaque walls. Glazing with spectrally selective coatings, are designed to reflect most of the Near Infrared (NIR) solar radiation and to transmit visible solar radiation in order to maximise light against heat gains, thus reducing overheating in summer without reducing daylighting. The degree of selectivity can be related to the LSG (Light to Solar Gain) ratio, which is the ratio between the visual transmittance and the solar factor. Such glazing is particularly adapted to cooling-load-dominated building types. Finally, the thermal transmittance of the frame should also be considered in that it affects the global window thermal transmittance (U value) proportionally to the rate of frame to glazed area of the window. Due to the high thermal conductivity of metal materials, plastic and wooden frames have always better thermal performance than metals.

c. Opaque surfaces Opaque surfaces (vertical walls, roof, ground floor, etc.) of eco-buildings also have low thermal transmittance values to provide high thermal insulation of the buildings and thus reduce the heat losses. A vapour barrier is often used in conjunction with insulation because the thermal gradient produced by the insulation may result in condensation that may damage the insulation and/or cause mould growth. In order to limit thermal losses, eco-building should also include appropriate techniques to avoid thermal bridges. These are space where the insulation is interrupted and through which heat can escape to the exterior, typically between walls and floor. Additionally the surface albedo (or reflectance) is an important factor to limit the solar gains on the opaque façades of a building, especially in warm climates. The albedo is the ability of a surface to reflect incoming solar radiation. Thus in warm climates “cool” roofs and walls are painted in white because light surfaces absorb less solar radiation than dark ones. Researchers have found that non-white “cool” roofs can be manufactured using colorants (pigments) that reflect the invisible, “near-infrared” radiation that accounts for more than half of the energy coming from the sun. “Cool” roofs and walls reflect an higher part of the sun’s radiation than conventional roofs, lowering temperatures inside buildings, decreasing air-conditioning energy use, and reducing the “urban heat island,” an elevation of air temperatures in urban areas. If the envelope is well insulated and insulation is placed on the outside, heat gains in winter occurs mainly through transparent surfaces, hence high albedo surfaces do not penalize winter performances.

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d. Thermal mass Thermal mass is able to store energy and thus reduce diurnal and seasonal temperature fluctuations. Thermal mass also introduces a time lag between the external surface peak temperature and the internal surface peak temperature. It is thus a very important element of both passive/low energy heating strategies in winter and passive/low energy cooling strategies in summer. It influences thermal comfort affecting both surface temperatures and air temperature.

e. Double skin facades Double skin facades and ventilated facades are construction strategies useful for both cooling and heating dominated climates since they strongly influence ventilation, solar heat gains and heat losses. The secondary skin may be either transparent or opaque, according to heating, cooling and lighting needs of the interior building, and the cavity may be naturally or mechanically ventilated. For example a simple naturally ventilated secondary skin, composed by external water resistant and insulated panels and double windows, may be a major alternative for insulation improvements of external vertical wall. Double skin facades are also designed to prevent building overheating in hot climates. The outer skin provides shade for inner opaque roof, walls and windows, while ventilation in the cavity between the skins removes excess heat that passes through the outer skin. The ideal system in this case is a light mass outer skin with a highly reflective outer surface (to reduce the absorption of solar radiation) and inner surfaces with low Infrared emissivity (to reduce heat exchange between the two layers of the double skin).

f.

Shading Devices

Shading devices are key components, especially in cooling-load-dominated eco-buildings but also in heating-load-dominated eco-buildings, contributing to reduce solar heat gains of the building in summer and thus to lower the demand for air conditioning of the building. The performance of a window shading device is expressed in terms of Shading Coefficient, defined as the ratio g_window /g_single glass, where g is the solar factor. Various typologies have been developed to provide effective solar protection. Basically, shading devices can be divided between movables devices and permanent devices. Movable devices have the advantage that they can be controlled manually or through automation, adapting their function to sun position and other environmental parameters. They can be internal blinds, external blinds or blinds between two layers of glass. Permanent devices are in general devices designed for a specific building, and are less flexible than movable ones. Special care has to be taken with fixed shading systems that may reduce solar heat gains in heating dominated seasons or climates. Such systems have to be optimized with special software to fulfil the objectives of summer shade without reduction in winter gains, thus admitting direct radiation when the sun is low in winter while blocking it when the sun is high in summer. Typical permanent shading devices are overhangs, light shelves and louvers.

g. Ventilation Heat losses due to ventilation needs account for an important part of building heating demand. One possibility to reduce heat losses due to ventilation is to use heat recovery units. These recover heat from the exhaust air stream and use it to pre-condition the incoming air from outside. The effectiveness of these units is given by its ‘heat exchange efficiency’ i.e. the proportion of waste heat that is usefully recovered by the process (typically expressed as a percentage). A heat recovery unit will reduce the amount of energy needed to heat up the incoming air to room temperature. This benefit must always be balanced against the electrical power requirements needed to drive the process.

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Additionally, energy saving control devices can also be introduced. The amount of ventilation needed in a room depends on the pollution level in that room (and, in some cases, whether anyone is present). Automatic controls can be included with all types of ventilation system (e.g. humidity sensor, occupancy/usage sensor, detection of moisture/pollutant release). These reduce the level of ventilation if the source of pollution and/or the pollution level is low, and thus save energy. On the other side, efficient natural ventilation concepts can contribute to reduce the cooling demand of buildings in summer. These concepts should ensure a fresh and comfortable indoor climate with minimal energy consumption and at low cost. Some examples of natural ventilation concepts are the cross ventilation and the stack ventilation: -

Cross ventilation is obtained by having windows in both sides of the room, causing airflow across the space. Positive pressure on the windward and/or a vacuum on the lee side of the building cause air movement across the room(s) from the windward to the lee side, provided the windows on both sides of the room are open. The windows on the windward side of the building are opened less than the windows on the lee side, in order to obtain an optimal airflow with as little draught as possible.

-

Stack Ventilation is based on the principle that warm air is lighter than cold air and thus tends to rise to the roof of the building. When warm air rises, a small vacuum is created at the lower level of the building, sucking in fresh ambient air through open windows at ground level – and thereby a natural airflow is created. Due to its physical nature, the stack effect requires a certain height difference between the windows used for air inlet and outlet. The windows in the roof are used for letting the "used" air out, while the windows at the lower levels take fresh ambient air into the building.

It is also possible to implement different combinations of these two principles as well as hybrid systems where a fan assists the natural ventilation concept in creating airflow, when there is not sufficient air movement in the building.

h. Use of vegetation External vegetation as trees can be used by eco-buildings to partially shade the building façade and to reduce external air temperature in summer time. In fact plants absorb solar radiation and produce water evaporation which has cooling effect on the surrounding air. It is also possible to use the vegetation creating “green” roofs and façades: ground, grass and plants that cover the building providing both insulation and thermal capacity with major effectiveness in cooling dominated climates. Deciduous plants are generally used in order not to reduce heat gains in winter. Metallic grid systems to support climbing plants (e.g. ground ivy or Virginia creeper) at about 30-40 cm from the wall are used to provide ventilation and avoid damage to the wall surface by the plants.

3.1.2

Active measures for efficient energy supply

Once having optimised the building envelope and thus reduced the energy consumption of the ecobuilding compared to a conventional building, the remaining energy demand of the eco-building should be covered, so far as possible, with renewable energy sources and / or polygeneration systems. Possible applications are: - use of solar thermal energy for domestic hot water preparation and space heating - use of photovoltaic energy for electricity production - use of biomass and / or biogas boilers - geothermal energy

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co- / tri-generation systems etc.

3.1.3

Consideration of embodied energy

The Embodied Energy is the energy accumulated in the materials and equipment implemented in the building through their manufacturing, transport, implementation and end of life recovery processes. All the materials used for the walls, roof, carpentry, glasses, insulation, etc. meant an energy consumption in order to be available in the building and permit that it is built. Thus, this energy should also be included in the total energy consumption of a building besides the operating energy and thus in the environmental impact of the building. Hence eco-buildings should integrate building materials with low embodied energy to have a globally low environmental impact.

3.1.4

Others measures of reduction of environmental impact

Apart from the energy efficiency measures, eco-buildings can also include other measures to reduce the environmental impact like water saving measures, waste management systems, etc.

3.2

Techno-economic aspects

The high efficiency measures introduced in eco-buildings generally suppose higher investment costs than conventional buildings, but they lead to significantly lower operating costs over the life of the building due to reduced or even suppressed conventional energy consumption. The increase of the investment costs of an eco-building compared to a conventional building is very variable from one building to the other. Depending on the aggressiveness of the design, experience has shown that it costs no more than 10% more to build high-performance buildings. In some cases, highperformance buildings do not suppose additional investment costs compared to equivalent conventional buildings. The added costs of system investment, if any, have to be compared with the savings resulting from the lower energy consumption each year and in some cases from the reduction of the service and maintenance costs. This can be assessed with general profitability calculation like the Net Present Value or the Internal Return Rate. Additionally, the method of the Life Cycle Cost Assessment is particularly suited for the evaluation of the cost-effectiveness of eco-buildings. This analytical method makes transparent the total cost of a building over its full useful life, including: -

initial costs (design and construction), operating costs (energy, water/sewage, waste, recycling, and other utilities), maintenance, repair and replacement costs, refurbishment costs, other environmental or social costs/benefits (impacts on transportation, solid waste, water, energy, infrastructure, worker productivity, outdoor air emissions, etc), final disposal.

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The LCCA method is especially adapted to evaluate eco-building performance since it favours in many cases innovative and efficient building concepts and technologies that do not succeed in the usual case, where the focus of the investor is mainly or exclusively on the investment cost.

3.3

Socio-economic aspects

Consequently to their reduced environmental impact, eco-buildings also create an indoor environment that provides higher levels of indoor air quality as well as higher levels of thermal, visual and acoustic comfort than conventional buildings. This aspect, associated to the saving potential due to reduced operating costs, contributes to promote a good acceptance of eco-buildings from the user side. Thus, the main barrier to a wider diffusion of the eco-building concepts certainly remains the higher investment costs of the building, even if in many cases, these represent a very small percentage of the total investment costs and can be compensated within a short period of time through the operating cost savings.

3.4

Design, simulation and optimisation tools

Design, simulation and optimisation of eco-buildings are usually realised using building simulation tools. These are software tools which emulate the dynamic interaction of heat, light and mass (air and moisture) within the building to predict its energy and environmental performance as it is exposed to climate, occupants and conditioning systems. Simulation programs permit to - predict the dynamic response and performance of buildings - compare load calculations, energy performance, peak demand, and cost benefit implications of different design options - simulate complex and “green” technologies: - naturally ventilated, passive and mixed-mode buildings (influence on thermal comfort), - daylighting (Exploring daylighting through different Glazing options, - overheating in unconditioned spaces / thermal comfort, - advanced controls operation, - under Floor Air Distribution (UFAD) systems, - etc. Over the past 50 years, literally hundreds of building energy programs have been developed, enhanced, and are in use throughout the building energy community. Among the existing programs, we can distinguish between whole building energy simulation tools and software focussing on a specific aspect of the building, for example practitioner design tools (for HVAC sizing, piping design, etc.), energy and environmental screening tools (life-cycle costing for selected technology), specialised analysis tools (daylighting, evaluation of contamination, etc.). The whole-building energy simulation programs are the most widespread tools, providing users with key building performance indicators such as energy use and demand, temperature, humidity, and costs. These can be simplified programs for overall energy consumption assessment, peak temperature prediction, heating/cooling loads calculations; or more sophisticated programs, for hourly simulation of heat, light and air movement, which can even integrate complex packages like computational fluid dynamics (CFD).[1] [2] Following some of the major whole-building energy simulation programs will be shortly presented.

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3.4.1. Whole-building energy simulation tools [3] [4] •

BLAST www.bso.uiuc.edu/BLAST

The Building Loads Analysis and System Thermodynamics (BLAST) tool (Building Systems Laboratory 1999) is a comprehensive set of programs for predicting energy consumption and energy system performance and cost in buildings. The BLAST program was developed by the U.S. Army Construction Engineering Research Laboratory (USA CERL) and the University of Illinois. BLAST performs hourly simulations of buildings, air handling systems, and central plant equipment in order to provide mechanical, energy and architectural engineers with accurate estimates of a building's energy needs. The detailed heat balance algorithms allow for analysis of thermal comfort, passive solar structures, high and low intensity radiant heat, moisture, and variable heat transfer coefficients -- none of which can be analysed in programs with less rigorous zone models. Additionally, BLAST output may be utilised in conjunction with the LCCID (Life Cycle Cost in Design) program to perform an economic analysis of the building/system/plant design. BLAST is no longer under development and no new versions have been released since 1998. •

BSim www.bsim.dk

BSim (Danish Building Research Institute 2004) is a package of easy-to-use and flexible programs for evaluating the indoor climate and energy conditions as well as the designing of the heating, cooling and ventilation plants. The core of the BSim package is the tsbi5 program which is a combined transient thermal and transient indoor humidity and surface humidity simulation module. The other programs are SimView (graphic model editor and input generator), SimLight (tool for analyses of daylight conditions in simple rooms), XSun (graphical tool for analyses of direct sunlight and shadowing), SimPV (a simple tool for calculation of the electrical yield from PV systems), NatVent (analyses of single zone natural ventilation) and SimDxf (a simple toll which makes possible to import CAD drawings in DXF format). BSim has been used extensively over the past 20 years, previously under the name tsbi3. Today it is the most commonly used tool in Denmark, and with increasing interest abroad, for the analysis of the indoor thermal and moisture climate in complex building or buildings with special requirements for the indoor climate. •

DOE-2.1E www.simulationresearch.lbl.gov

DOE-2.1E (Winkelmann et al. 1993) predicts the hourly energy performance and energy cost of a building given hourly weather information, a building geometric and HVAC description, and utility rate structure. Using DOE-2.1E, designers can determine the choice of building parameters that improve energy efficiency while maintaining thermal comfort and cost-effectiveness. Other uses include utility demand-side management and rebate programs, development and implementation of energy efficiency standards and compliance certification, and training. DOE-2.1E has been used extensively for more than 25 years for both building design studies, analysis of retrofit opportunities, and for developing and testing building energy standards. DOE-2-1E is widely recognised as an industrial standard; however it requires high level of knowledge of the users. Thus, the private sector has adapted DOE-2.1E by creating more than 20 interfaces that make the program easier to use. •

ECOTECT www.ecotect.com

ECOTECT (Marsh 1996) is a highly visual and interactive complete building design and analysis tool that links a comprehensive 3D modeller with a wide range of performance analysis functions covering thermal energy, lighting, shading, acoustics, resources use and costs aspects. Whilst its modelling and

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analysis capabilities can handle geometry of any size and complexity, its main advantage is a focus on feedback at the conceptual building design stages. The intent is to allow designers to taker a holistic approach to the building design process making it easier to create a truly low energy building, rather than simply size a HVAC system to cope with a less than optimal design. Thus, in addition to standard graph and table-based reports, analysis results can be mapped over building surfaces or displayed directly within the space that generated them, giving the designer the best chance of understanding exactly how their building is performing and from that basis make real design improvements. Hence ECOTECT allows the user to "play" with design ideas at the conceptual stages, providing essential analysis feedback from even the simplest sketch model. ECOTECT is unique within the field of building analysis in that it is entirely designed and written by architects and intended mainly for use by architects – although the software is quickly gaining popularity through the wider environmental building design community. •

Energy-10 www.nrel.gov/buildings/energy10.html

Energy-10 is a user-friendly early design stage building energy simulation program that integrates daylighting, passive solar heating, and low-energy cooling strategies with energy-efficient shell design and mechanical equipment. The program is geared toward buildings, that are less than 1000 m2 floor area, or buildings which can be treated as one or two-zone increments. Developed by the U.S. Department of Energy since 1992, Energy-10 runs an hourly thermal network simulation while allowing users to rapidly explore a wide range of energy efficiency strategies and plot the results in a number of ways. Energy-10 takes a baseline simulation and automatically applies a number of predefined strategies ranging from building envelope (insulation, glazing, shading, thermal mass, etc.) and system efficiency options (HVAC, lighting, daylighting, solar service hot water and integrated photovoltaic electricity generation). Full life-cycle costing is an integral part of the software. Starting from building location, footprint, usage type and HVAC type Energy-10 can generate reference and low-energy target cases in seconds based on full annual hourly simulation. •

EnergyPlus, www.energyplus.gov

EnergyPlus (Crawley et al. 2004) is a modular structured software tool based on the most popular features and capabilities of BLAST and DOE-2.1E. It is primarily a simulation engine; input and output are simple text files. EnergyPlus grew out of perceived needs to provide an integrated (simultaneous loads and systems) simulation for accurate temperature and comfort prediction. Loads calculated (by a heat balance engine) at a user-specified time step are passed to the building systems simulation module at the same time step. The EnergyPlus building systems simulation module, with a variable time step, calculates heating and cooling system and plant and electrical system response. This integrated solution provides more accurate space temperature prediction – crucial for system and plant sizing, occupant comfort and occupant health calculations. Integrated simulation also allows user to evaluate realistic system controls, moisture adsorption and desorption in building elements, radiant heating and cooling systems, inter-zone air flow and electric power simulation including fuel cells and other distributed energy systems. •

eQUEST www.doe2.com/equest

eQUEST is an easy to use building energy use analysis tool which provides professional-level results with an affordable level of effort. This is accomplished by combining a building creation wizard, an energy efficient measure (EEM) wizard and a graphical result display module with an enhanced DOE2.2-derived building energy use simulation program. After compiling a building description, eQUEST produces a detailed simulation of the building, as well as an estimate on how much energy it would use. Although these results are generated quickly, the software utilizes the full capabilities of DOE-2.2. eQUEST also offers energy cost estimation,

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daylighting and lighting system control, and automatic implementation of common energy efficiency measures (by selecting preferred measures from a list). •

ESP-r www.esru.strath.ac.uk/Programs/ESP-r.htm

ESP-r (ESRU 2005, Clarke 2001) is a general purpose simulation environment which supports an indepth appraisal of the factors which influence the energy and environmental performance of buildings. It has been under development for more than 25 years. ESP-r has the objective of simulating building performance in a manner that: a) is realistic and adheres closely to actual physical systems, b) supports early-through-detailed design stage appraisals, and c) enables integrated performance assessments in which no single issue is unduly prominent. ESP-r attempts to simulate the real world as rigorously as possible and to a level which is consistent with current best practice in the international simulation community. By addressing all aspects simultaneously, ESP-r allows the designer to explore the complex relationships between a building's form, fabric, air flow, plant and control. ESP-r comprises a central Project Manager around which are arranged support databases, a simulator, various performance assessment tools and a variety of third party applications for CAD, visualisation and report generation. •

HAP www.commercial.carrier.com

Carrier’s Hourly Analysis Program (HAP) provides two powerful tools in one software package. HAP sizes HVAC systems for commercial buildings. It also simulates 8760-hr building energy use and energy costs. HAP is designed for the practising engineer, to facilitate the efficient day-to-day work of estimating loads, designing systems and evaluating energy performance. HAP’s design module uses a system-based approach to HVAC load estimation. This approach tailors sizing procedures and results to the specific type of system being considered. Many types of air handling systems, packaged equipment and central plant equipment can easily be simulated and sized with HAP (central AHUs, packaged rooftop units, split systems, fan coils, water source heat pumps, PTACs, CAV, VAV, multiple-zone systems). HAP’s energy analysis module performs an hour-by-hour simulation of building loads and equipment operation for all 8,760 hours in a year. This approach provides superior accuracy versus the reduced hour-by-hour method used by other software programs on the market. This is because a full hour-byhour calculation considers the unique weather and operating schedules for each day of the year, rather than looking only at average or “typical” days each month. Such accuracy is crucial when analysing design alternatives, energy conservation methods and details of off-design and part-load performance for equipment. •

IDA ICE www.equa.se/ice

IDA Indoor Climate and Energy (IDA ICE) (Sahlin et al. 2004) is a tool for simulation of thermal comfort, indoor air quality and energy consumption in buildings. The mathematical models in IDA ICE are described in terms of equations in a formal language, NMF. This makes it easy to replace and upgrade program modules. IDA ICE has been requested, specified and partly financed by a group of thirty leading Scandinavian AEC companies. The mathematical models have been developed at the Royal Institute of Technology in Stockholm (KTH) and at Helsinki University of Technology. The models are not tailored to Scandinavian needs but seek to capture the international state-of-the-art in building performance modelling.

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IES www.iesve.com

IES , a software tool developed by the IES in Glasgow, provides design professionals with a range of design-oriented building analysis within a single software environment. At the core of the model is a 3D geometric representation of the building to which application specific data is attached in views tailored to specific design tasks. The single model allows easy data exchange among applications. One main component of IES is the software tool ApacheSim, a dynamic thermal simulation tool based on first-principles mathematical modelling of building heat transfer processes. The program provides an environment for the detailed evaluation of building and system designs, allowing them to be optimised with regard to comfort criteria and energy use. Among the issues that can be addressed with ApacheSim are thermal insulation (type and placement), building dynamics and thermal mass, building configuration and orientation, climate response, glazing, shading, solar gain, solar penetration, casual gains, air tightness, natural ventilation, mechanical ventilation, mixed-mode systems, and HVAC systems. ApacheSim results are viewed in Vista, a graphic driven tool for data presentation and analysis. Simulation results include: Over 40 measures of room performance including air and radiant temperature, humidity, sensible and latent loads, gains and ventilation rates; comfort statistics; natural ventilation rates through individual windows, doors and louvers; surface temperatures for comfort analysis and CFD boundary conditions; plant performance variables, load and energy consumption; carbon emissions. •

SUNREL www.nrel.gov/buildings/sunrel

SUNREL (Deru et al. 2002) is an hourly building energy simulation program developed by the Center for Building and Thermal Systems of the U.S. National Renewable Energy Laboratory (NREL) that aids in the design of single- or multizone energy-efficient buildings where the loads are dominated by the dynamic interactions between the building’s envelope, its environment, and its occupants. SUNREL is especially well suited for passive solar buildings and includes algorithms for Trombe walls, advanced glazing, schedulable window shading, active-charge/passive-discharge thermal storage, and natural ventilation. The program is a true simulation model based on time steps of one hour or less. The model representation of the building is a thermal network solved with forward finite differencing among other techniques. In addition, a simple graphical interface aids in creating input and viewing output and make the program easy to learn. •

Tas, www.edsl.net

Tas (EDSL 1989) is a suite of software products which simulate the dynamic thermal performance of buildings and their systems. The main module is a Tas Building Designer, which performs dynamic building simulation with integrated natural and forced airflow. It has a 3D graphics based geometry input that includes a CAD link. Tas Systems is a HVAC systems / controls simulator, which may be directly coupled with the building simulator. It performs automatic airflow and plant sizing and total energy demand. The third module, Tas Ambiens, is a robust and simple to use 2D CFD package which produces a cross section of micro climate variation in a space. Tas is a complete solution for the thermal simulation of new or existing buildings, allowing design professionals to compare alternative heating/cooling strategies and façade design for comfort, equipment sizing and energy demand. Originally developed at Cranfield Institute in the UK, it has been commercially developed and supported since 1984.

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TRACE 700 www.tranecds.com

The TRACE 700 program, developed by the Trane Company, brings the algorithms recommended by the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) to the familiar Windows operating environment. TRACE 700 permit to assess the energy and economic impacts of building-related selections such as architectural features, comfort-system design, HVAC equipment selections, operating schedules, and financial options. Flexible data entry, coupled with multiple views and "drag-and-drop" load assignments, simplify the modelling process and help identify optimal zoning and plant configurations. It also allows to compare up to four alternatives for a single project by modelling various air distribution and mechanical system/control options and then assess the life-cycle cost and payback of each combination based on 8,760 hours of operation. Templates provide a fast, easy way to analyse the effects of changes in building loads such as airflow, thermostat settings, occupancy, and construction. An extensive library of construction materials, equipment, and weather profiles (nearly 500 locations) enhances the speed and accuracy of the analyses. •

TRNSYS sel.me.wisc.edu/trnsys

TRNSYS (TRaNsient SYstem Simulation Program) is an energy simulation program whose modular system approach makes it one of the most flexible tools available, permitting to solve complex energy system problems by breaking the problem down into a series of smaller components. TRNSYS (TRaNsient SYstem Simulation Program) includes a graphical interface, a simulation engine, and a library of components that range from various building models to standard HVAC equipment to renewable energy and emerging technologies. TRNSYS also includes a method for creating new components that do not exist in the standard package. This simulation package has been developed by the Solar Energy Laboratory of the University of Wisconsin and has been used for more than 25 years for HVAC analysis and sizing, multizone airflow analyses, electric power simulation, solar design, building thermal performance, analysis of control schemes, etc. TRNSYS also interfaces with various other simulation packages such as GenOpt for doing system optimisation studies and SimCad whose CAD representation of buildings can be read directly into TRNSYS as the basis of a thermal model. Tools for whole building sustainability analysis [3] Various tools have been developed to assess the sustainability of buildings. These tools provide life cycle assessments, environmental evaluation of building materials, Life Cycle Cost Assessment, environmental impact assessment, calculation of embodied energy, etc. Some available programs for building sustainability analysis are: • • • • • • • • •

Athena Model www.athenaSMI.ca BEES www.bfrl.nist.gov/oae/bees.html Building Greenhouse Rating www.abgr.com.au Envest www.bre.co.uk/envest EQUER www.cenerg.ensmp.fr/english/themes/cycle/index.html GaBi 4 www.pe-consulting-group.com/software_gabi.html KCL-ECO www.kcl.fi/eco LISA www.lisa.au.com Umberto www.umberto.de/english/

Tools for materials, components and equipment design and optimisation There is a wide range of simulations programs which permit the evaluation and optimisation of specific aspects or parts of the building, for instance:

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Tools for envelope system assessment (insulation, thermal bridges, solar shading, windows / wall thermal transmission, etc.) HVAC equipment and systems simulations Lighting systems simulations

Tools for other applications Various simulation tools are available for other applications like: • • • • • •

Atmospheric Pollution Indoor Air Quality Water Conservation Ventilation / Airflow Energy economics (Life Cycle Cost Assessment, …) Etc.

3.4.1

References

1. D. B. Crawley, “Building Simulation Process: Overview and Resources”, US Department of Energy http://tc47.ashraetcs.org/pdf/Presentations/Crawley_Chicago.pdf 2. V.A. Smith, “Survey of Available http://tc47.ashraetcs.org/pdf/Presentations/Smith_Chicago.pdf

Simulation

Tools”,

3. Internet Site of the US Department of Energy, Building Energy Software Tools Directory http://www.eere.energy.gov/buildings/tools_directory/ 4. D.B. Crawley, J.W. Hand, M. Kummert, B.T. Griffith, “Contrasting the capabilities of building energy performance simulation programs”, Version 1.0 July 2005 http://www.eere.energy.gov/buildings/tools_directory/pdfs/contrasting_the_capabilities_of_buildi ng_energy_performance_simulation_programs_v1.0.pdf

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4 Concepts for technology integration into district cooling and heating networks (CREVER) The main parts of a District Heating and Cooling (DHC) system are: • • • •

Point where electrical and thermal energy are generated, Grid of transporting and distributing, Accumulation points Final connection to the consumers.

Many different criterions can be chosen to design and classify the DHC systems, according to the case that we face and the characteristics of the system that we want to accomplish.

4.1

Description of network configurations and characteristics

Closed or open networks Closed networks are used in the case that is known the number of consumers who are going to be connected to the grid. They are most commonly used in complex of buildings, where all the habitants are connected and some other special cases are hotels, hospitals, commercial centres, university residences, airports, etc. The design and installation can be cost effective and with good results, as far as the location of all the consumers and their thermal and cooling needs are known or can be predicted with accuracy. Open networks are used when the thermal energy demand that has to be covered is variable, for example in an urban area of a town. The consumers are not obliged to be connected, like in closed systems, and can choose between DHC and individual heaters and air conditioning. The demand can increase or decrease, according to the efficiency and the cost of the heating supplied. Open networks have to be able to improve their service as any new connection is made without reducing the quality of supply to the other consumers, neither should affect the grid normal circulation of the liquid by changing the pressure standards.

Net or branched configuration Net configuration: The majority of existing DHC networks are of this kind, as they need less tubes for each consumer. The main characteristic is that every consumer is connected through one point with the central distribution network. The design is quite simple, but more difficult to be expanded. Furthermore, in case of fault in one or more consumers, the thermal supply has to be interrupted till it is repaired. Branched configuration: The suppliers are connected to the thermal energy by different ways, so that they are not disconnected in case of faults or damage on the network. The efficiency of the grid is higher, as well as the cost of the investment. The network parameters are variable and the pumping system is adapted to the needs that it faces. A branched system is mainly used in open networks because the pressure in case of demand fluctuation is more constant. Another advantage is that branched systems can be integrated more easily with other energy generation plans. The elevated cost is their main problem, thus they are used in some cases for improving the efficiency and the security of the network or for interconnection with renewable source energy generators.

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Number of tubes Four types of piping systems are in use: -

single pipe: for steam systems with no condensate return and for geothermal sources, when the feed water is fed directly to sewage disposal systems, storm drains, etc;

-

two-pipe system: the most common piping system. Heat supply is provided in one pipe (water or steam) and the condensated cooled water is returned to the heat production unit from the other pipe. It can provide both hot or cool, but not at the same time, so that according to the needs of the consumers (heat for the winter and cold for summer), it is connected every time in different energy setting. Two-pipe connection is used in small networks or in buildings with one connection only to the DHC system or for every installation that doesn’t need at the same time to use hot and cool water. In case that the circulating fluid is vapour, hot water can be provided if heat exchangers are put in the consumer’s side. A two pipe system utilising the pipes for cold water during the cooling season requires users to have their own means of heating water for domestic hot water use.

-

three-pipe system: not widely used consists of a main supply and return pipe with a smaller main supply. The common return line serves both supply pipes and during the summer the main supply line is shut off. The main advantage is the reduced cost of the tubes, compared with the four-pipe system, but the low energy efficiency they provide makes them less popular.

-

four-pipe system: involves separate supply and return pipes for space heating water and hot water or two pipes for heating and two for cooling. This latter system is widely used in the United States. The system of four pipes is commonly used if we want to satisfy heat and cool demands all the year and the distributed generation plant can provide both heating and cooling energy. Of course, the investment on this system is most expensive, but as well it is more flexible.

4.2 4.2.1

Characteristics of the network according to the alternative distribution fluids Circulating fluid (steam, hot or cold water)

To cover heating and cooling needs of consumers the District Heating (DH) can use either steam, hot or cold water as a circulating fluid, depending on the design of the network To cover the refrigeration needs of a building a DH plant can supply hot water and locate to each consumer side an absorption chiller to generate cold, or, the case that is more usual nowadays, to cool the water at the CHP plant and distribute it dirrectly to the consumers. To cover heating needs of consumers the District Heating (DH) can use either steam or hot water as a circulating fluid to distribute the energy to the consumers. Every one has its pros and cons, which are described next. Usually, plants that supply heating to hospitals, industries or the ones that produce also electrical energy, produce and distribute steam, while networks that provide heat to big commercial centres use hot water. The tendency today is to construct grids that circulate hot water, because they are more simple in construction, cheaper in operation and can satisfy a greater geographic area. In Europe, the DH grids that use hot water as energy fluid are operating at temperatures between 90 and 150 0 C, while in USA are of higher pressure and temperature (170 0 C).

4.2.2

Heating capacity

A system functioning with steam is based on the latent heat of the water. For example, for steam saturated at 690kPa and temperature of 170ºC, condensed and cooled till 80ºC, the net heating energy

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is 2400kJ/kg, whereas to cool water from 170ºC to 120ºC the energy generated is 240 kJ/kg, 10 % only compared with the steam. As a conclusion, DH grid that use hot water need 10 times more mass to provide the same thermal energy.

4.2.3

Sizing of tubes

Determination of pipe sizes is one of the major decisions that the designer of a district heating system faces. Steam DH grids need to circulate less mass than hot water DH and achieve bigger velocity. The tube to supply heating to the consumers must be bigger than the one used for water because the density of steam is smaller. In contrary, the tube that returns the steam to the plant is smaller compared with the water circulating tubes, so that the total cost of the tubes for water or steam energy fluid is almost the same. In water circulating DH networks, the sizing of the tubes is related with the difference of temperature between the tube that reaches the consumers and the tube that returns the water to the starting point. For two different systems using hot water, with the same mass circulating and the same difference of temperature, the dimensions of the tubes will be the same, independently if the temperatures are high or low. The tubes for water systems are the same on both directions, while the ones that use vapour are more complicated. The basic problem of circulating vapour that makes this type of design less popular is the corrosion of the tubes. The most appropriate material for the pipes is more a matter of economics, related to the usage of the tubes, of determining the life cycle of it and the heat demands that it will cover. The velocity of the circulating fluid that circulates inside should not be very high, to reduce the hydraulic losses, but not very slow (<0.8 m/s) According to the tubes selected, it is usual to work with velocities between 1 and 3 m/s for water systems and for steam maximum velocity is 60 – 75 m/s. The more common criteria in Europe is to have a pressure drop of about 100 Pa/m, although this figure can be even higher without damaging the system.

4.3 4.3.1

Pressure and temperature in District Heating systems Pressure and temperature demands

No matter what type of DH grid is used (steam, hot or cold water), pumps need to be selected to minimise the losses of energy. For hot water systems, intermediate pumps can be used to increase the pressure between the energy generation point and the consumption level. As the density of water is higher compared with the one of steam, a higher pressure is required. Pressure and temperature must not be higher than the ones needed to satisfy the consumers. Higher pressure and temperature levels will need extra work and planning and more energy losses. Furthermore, lifted temperatures need tubes that can support higher pressures and make the grid less safe. Another important point is that the reduction of the temperature on the consumer’s side must be as high as possible, preferably more than 22ºC. This difference has to be as high as possible because: less mass of liquid is needed, less power is consumed by the pump, the returning temperature is less and less thermal energy is lost.

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Operating level of pressure and temperature

District Heating systems can be classified according to the fluid they use, steam or water. The steam circulating DH are classified according to their pressure: -

Systems of high pression Psupply > 8,6 bar Systems of medium pressure 2 bar > Psupply > 8,6 bar Systems of low presure Psupply < 2 bar

The majority is found in USA, where the cost of combustible was cheaper and the investment cost effective. However, as the steam systems presented some disadvantages, the new DH systems are using water instead. The water circulating DH are classified according to their temperature: -

Systems of high temperature Tsupply > 1750C Systems of medium temperature 1200C > Tsupply > 1750C Systems of low temperature Tsupply < 1200C

The systems of high temperature have high thermal losses, so also elevated energy cost. Also, as they work at high temperatures, they need expensive heat exchangers to transfer the energy that carries the water to the consumers. Nowadays, the new installations work at 900C or less, as they are preferred for economic reasons. The use of materials of low cost for the tubes of transmission and distribution (plastic) and for their insulation (polyurethane) can pull down the cost of the investment, while the low temperature of function enables the direct connection of the tube to the consumer’s part, without any heat exchangers. On the other hand, the low temperature water systems have some disadvantages, as they cannot supply efficient energy for industrial use. The connection to the consumers that already are designed for steam DH systems is very expensive and for refrigerating needs, the temperature has to be elevated to higher level. In general, low temperature systems are used to cover medium or low thermal loads. Low temperature systems are the most used nowadays and they are described with more detail in the next section. The medium temperature DH systems have some of the characteristics of the high and some of the low temperature, depending on if they are at the higher or the lower limit of the category. At the lower end of this temperature scale they operate much like the low temperature systems, with similar characteristics, such as low-cost piping materials, low installation costs, relatively low thermal energy cost, and low thermal energy losses. If, as in some systems, heat exchangers are used to interface the consumer and the distribution system this can result in higher capital investment. In other systems, heat exchangers are not installed for this temperature range, thereby reducing capital outlays. Additional pumping stations and pressure-reduction valves may, however be required. In most of these systems the temperature of hot water supply varies with outdoor temperature; the higher the outdoor temperature, the lower the supply temperature and the lower the outdoor temperature, the higher the supply temperature, subject to a maximum load which is determined prior to construction of the system. In Europe, the major part of the existing DH is in the range of temperature between 90 and 150ºC. Typical values of temperatures Tsupplied, ∆Τ , Treturn for Danmark are shown on the table 4.1.

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Table 4.1. Typical values for temperatures Tsupplied, ∆Τ , Treturn system. Summer Tsupplied 70 - 80ºC 20 - 30ºC ∆Τ Treturn 45 - 55ºC

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for the Danish energy distribution Winter 75 - 85ºC 30 - 45ºC 35 - 50ºC

Comparison of systems at low and high temperature

In some countries, like USA, DH systems that circulate steam or high temperature water are more used than the ones of low temperature. Some disadvantages of low temperature systems have restricted their development. The most important considerations for their use are: • •

•

•

Complexity of design. In fact low temperature water systems are not more complicated than other types. On the contrary, the lower level of pressure and temperature facilitates the connection and in some cases equipment that other type of connection needs here is missing. Low temperature systems are not adequate for big grids. A clear example that shoots down this argument is the case of Denmark, which has one of the bigger grids in Europe. Thanks to the efficiency of insulation of polyurethane the thermal losses are less than 5% and the temperature fault during transportation is not significant. Low temperature systems need tubes much bigger. For a specific mass flow of water used, the thermal energy supplied depends on the difference of temperature between the production point and the consumers ( ∆Τ ). With a good design of the system the ∆ Τ can reach the 55ºC independently of the high or low temperature of the circulating water. Also, the lower rate of pressure and temperature allows better control of the grid, achieving high ∆Τ even for low loads. Low temperature systems need heat exchangers of bigger size. Even though this is truth, it doesn’t seem to be a big disadvantage, mainly because the low temperature that the system uses eliminates the need of installing heat exchangers on the side of the consumers. In the case that a heat exchanger is needed, in big buildings is used a plate heat exchanger which are cost effective.

One of the most fundamental decisions to be made by a designer of a new district heating system is the selection of design operating temperatures. Lower operating temperatures will reduce the cost of heat production from a CHP plant, but to achieve lower temperatures requires additional investment in the heating systems within the buildings. The cost of the district heating network is reduced if the temperature difference between inlet flow and return is maximised. There is therefore a need to establish the optimum design temperatures to achieve the most cost-effective scheme. The research made has shown that it is not worthwhile to reduce the design flow temperature below 90°C as this leads either to a smaller temperature difference and therefore higher network costs or, if the temperature difference is maintained, additional costs for larger radiators. Both of these cost penalties are more significant than the small reduction in heat production cost obtained with using lower flow temperatures. However, there are many other potential benefits from using lower temperatures, in particular the ability of the district heating network to utilise low grade heat sources available from industry, solar heat and heat pumps. The cost penalty from selecting a 70°C temperature instead of 90°C was found to result in an overall increase in the cost of heat of between 4% and 6% of a typical heat selling price. It is possible that, in some circumstances, this relatively small increase is justifiable given the potential environmental benefits in the longer term of maximising the use of waste heat and renewable energy by means of district heating. However, in many cases, the low grade heat sources will contribute only part of the energy supply and will effectively pre-heat the return water. A reduction of return water temperatures will therefore be the more important requirement.

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On the other hand, low temperature DH has some advantages that made their construction more common in Europe. •

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•

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The capital cost of the investment is 50% cheaper compared to high temperature systems. The simplicity in the design of the system, that needs less future predictions (less consideration of improvement and adaptation to the future needs), and the equipment needed for the isolation of the tubes, which is cheaper, better functioning and has better performance than the one of high temperature, make the investment more cost-effective. The relationship between electricity and heating produced is a characteristic parameter for cogeneration plans. This relation depends on the temperature of the water that is going to the consumers and the one of the return. For some energy generation technologies, reducing the supplying temperature means to increase the electrical energy generated. A reduction of the supplying temperature has as an effect energy saving by 2 means: a diminish of the consumption of combustion needed for the generation of heating and electricity and less losses of the distribution system. Less leakage of water. A small part of the total losses in a DH system is caused from leaking of the fluid that circulates the tubes. Normally, the leaking on low temperature and pressure DH systems is not very high (0.5-2%).On the contrary, high temperature systems and steam systems have more serious losses, especially on the returning tube. Low rates of temperature and pressure make the system more secure and with less needs of maintenance.

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In many cases heat exchangers are not used and the connection with the consumers is direct.

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It is easier to expand a system of low temperature and pressure to regions with low load and thermal demands, or to a far away place.

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Systems of low temperature can be adapted easier to a variety of combustibles. Solar energy, geothermal and other heat generators are easily integrated to DH of low temperature systems, with an effectiveness that can cover the thermal needs of a region even in 100% during the summer.

4.4 4.4.1

Pressure constraints Differential pressure constraints

A very important set of constraints on the system arises from requirements for the pressure difference between supply and return. At the consumer this differential pressure must maintain a minimum level to ensure adequate flow through the consumer’s heat exchanger. This pressure differential is consumed in both the heat exchangers and control valves. In the heat exchanger, the pressure losses are caused by fluid dynamic friction. In the control valve, the pressure losses are introduced by a throttling process used to control the flow rate through the heat exchanger and thus control its output. In the supply piping between the heat source and the consumer, pressure losses occur due to friction. Similarly, in the return line from the consumer back to the heat source, pressure losses also occur. There is then, in effect, a requirement at each point in the piping network for a given differential between supply and return pressure necessary to overcome downstream losses, including those in the return system. Ultimately, at the heating plant pumps must be used to provide the total differential pressure needed downstream of that point. In theory it’s possible that pumps can be placed anywhere in the system or even dispersed throughout. In practice this is not done very frequently, owing to the practical considerations of monitoring, controlling and maintaining the pumps as well as availability of power for them. We can write the constraint that arises from all of these differential pressure requirements easily by summing the pressure drops and increases around the system.

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Since the entire district heating system, consisting of the heating plant, the piping system and the consumer, forms an essentially closed loop, the pressure losses and increases around this loop must sum to zero. Thus, we have the following result ∆Ρhp = Σ pipes (∆Ps + ∆Pr ) + ∆Pcv + ∆Phe where: ∆Php = pressure increase across the pump (N/m2) ∆Ps = pressure drop in the supply piping (N/m2) ∆Pr = pressure drop in the return piping (N/m2) ∆Pcv = pressure drop in the consumer control valves (N/m2) ∆Phe = pressure drop in the consumer heat exchangers (N/m2). Each consumer will have at least one segment of the piping system that is not shared with any other consumers. In addition, all consumers will have their own control valve and heat exchanger.

4.4.2

Maximum absolute pressure constraints

Several constraints on the absolute pressure of the water within the system must be considered. First, we consider the upper limit on pressure that results from the absolute pressure limits of the piping. This limit will be established by the prevailing piping code. In the case where all points in the distribution system are at or above the level of the heating plant, the maximum absolute pressure will occur in the supply pipe at the heating plant.

4.4.3

Minimum absolute pressure constraints

Minimum allowable pressure constraints arise from three distinct considerations. 1. Net Positive Suction Head (NPSH) requirements of the pump.The constraint resulting from minimum NPSH requirements necessary to preclude pump cavitation only needs to be satisfied at the inlet to the pump. This pressure requirement will be a function of the saturation pressure and hence the temperature of the liquid at that point. The NPSH requirement is usually specified by the manufacturer of the pump. 2. Minimum pressure over atmospheric necessary to preclude the infusion of air into the system. Pressure necessary to prevent flashing of the liquid.

4.5

Temperatures in District Cooling (DC) systems

The production of cold water for refrigeration demand can be achieved either with absorption machines, or with steam compression chillers. In conventional systems, the temperature supplied is between 4 and 7ºC. For a difference of temperature between the two tubes (to-and-fro) of 6ºC, it is needed 2,4 l/min per kW of refrigeration (approximately 40 g/kJ). In general, DC systems are designed to work in supply temperature difference ∆Τ of 7 or 8ºC, so that they can reach a ∆Τ maximum of 7 to 11ºC and minimum 6 to 7ºC. For grids that are able to storage cool energy the limit temperature is 4ºC and for ice accumulation is 1ºC.

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5 Replicability (IC) The aim of this activity is to replicate the procedure developed in this project and give guidelines to decisor makers who mainly are municipal agents (technicians, politicians,…) In this context, Institut Cerdà is developing a document, which includes the most representative aspects of the decision process and also the criteria to select the technologies which have the proper characteristics to be taken into account to cover the energy demand, specially in residential and commercial sector. In the following paragraphs, the exposition of this document is described.

5.1

Introduction

On the market, it exists different energy technologies for generation which have important energy and environment advantages in relation to the conventional ones. There are several barriers to implement the previous technologies, and they are related to aspects which not always link with economic feasibility, these barriers are the following: o

The lack of information to implement energy-efficient technologies in new construction areas.

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Aspects related to the facility of including conventional technologies in the energy design phase instead of considering efficient energy technologies which have proper characteristics to be viable its application.

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Sometimes it is needed a higher initial investment than conventional systems. This fact makes difficult its implementation, although the initial investment is recovered later, as a consequence of the energy savings, it is important to define the return periods of each installation related to the environmental benefits.

o

As a consequence of the lower penetration on the market (not much demand) of some efficient technologies, the cost is higher than the conventional one. The actual situation and the demand increase of some technologies could lead to an important economical and environmental savings with regard to the traditional energy model.

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Decision Process of an energetic project

Any energetic project which needs a specific study and has an investment associated could be structured as follows: PREDIAGNOSIS OF ENERGETIC SOLUTIONS VIABILITY STUDY

STUDY BY AN ENGINEERING

MAIN EQUIPMENTS

ELECTRICAL COMPANY SUPPLY MANAGEMENT

ENERGETIC PROJECT FUEL

AUXILIARY EQUIPMENT

DETAIL ENGINEERING

LEGAL FRAME AND ADMINISTRATIVE PROCEDURE

CONSTRUCTION SUPERVISION START-UP

DISMANTLING

Before taking the decision of starting an energetic project it is useful to do a prediagnosis of the project, because it allows the user to evaluate approximately the economical and technical feasibility of a project. The aim of this document is establish the methodology of this prediagnosis. The results obtained in this phase allows to: o o o o

Discard quickly some energy configurations which are not viable. Identify those investments which would be suitable in terms of environment and economic and energy savings. Evaluate a first economic feasibility of the project. Identify the critical variables from energy, economic and environment point of view.

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Methodology of work

The most important issue to define energy solutions is the demand needed, as well as the knowledge of the characteristics of the place and the surrounding. The methodology developed to do this study is the following one:

2

1 ENERGY DEMAND AND RESOURCES

ENERGY SOLUTIONS Covered by

Discard technologies

BARRIERS Energy savings and operacional performance

Investment

Appliance

Limit of technologies

TECHNOLOGIES SELECTION 3

PROPOSALS OF TECHNOLOGIES FOR NEW URBANIZATIONS OR REHABILITATIONS ON THE BASIS OF THE ENERGY DEMAND Give guidelines to municipal agents to take decisions Opportunities Weakness Economic and energy indicators Specific needs of each technology Recommendations

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Checklist for an energy prediagnosis

Several criteria exist to make a prediagnosis OF AN ENERGETIC PROJECT. Generally, it is done from a preliminary analysis of economic feasibility of the technology selected with regard to the reference configuration, taking into account all the variables that could affect the project and the impacts that, being positives for the community, would justify an increase of economic costs with regard to the traditional systems:

BARRIERS

TECHNOLOGY

TERRITORY BENEFITS

ENERGY SAVINGS

APLICATION

PREDIAGNOSIS

ENERGY DEMAND

INVESTMENT

DECISION

RESOURCES AND SOURCES

FEASIBILITY

To make the prediagnosis, in a simple but seriously way, it is suitable to follow the methodology which is explained below: Demand analysis: 1. Physical and geographical aspects related to the system. 2. Characteristics of the energy demand of the system specified depending on the energy applications, peak rates: - Electricity demand - Heating demand - Cooling demand 3. Study the typology of the buildings, projected or existing. Configuration of the energy supply 1. Definition of the reference situation 2. Calculation of associated costs of the reference situation. 3. Definition of alternatives -

Technology Fuels Energy sources

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Decisions The decision could be taken from different aspects, social, economical, technical, environmental. Nevertheless, there are some figures to be studied: 1. Cost balance basic calculation of the technological alternative. 2. Calculation of the feasibility with regard to the traditional technologies. 3. Analysis of sensibility. The economic results obtained by this technology can also depend on the following factors: -

Fiscal incentives Subventions to these technologies

In addition to economic criteria, it exist a large number of external aspects which could be evaluated in a feasibility analysis: -

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Energy aspects: o Energy supply Safety. o Network independence. o Use of renewable energies. Energy supply Safety: o Fossil fuel saving. o Stability of the fuels prices. Environmental aspects: o Limitation of the CO2 emissions and harmful gases. o Improvement of the environment. Social aspects: o Jobs. o Increase of the wealth. o Emblematic projects. o Mechanisms of dissemination

If the result of this analysis is positive, there is a possibility to develop a more detailed study of the project feasibility by an engineering or experts on the concrete solutions.