Projected Costs of Generating Electricity - OECD Nuclear Energy ...

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The impurities contained in coal are released during combustion. In addition, nitrogen oxides (NO X ) are formed by the combustion process itself by reactions with nitrogen contained in the coal and in the combustion air. Toxic by-products found in combustion gases include sulphur dioxide, nitrogen oxides, halogens, unburned hydrocarbons and metals. Ash remains from the non-combustible portion of coal feed and unburned carbon. Typically half is collected in the bottom of the boiler and the remainder is carried along in the combustion gases as fly ash. Various environmental control systems must be incorporated into the plant design to limit the formation of pollutants (nitrogen oxides) or remove them from flue gases. Pollution control systems The pollutants controlled from coal-fired plants and the levels to which they are controlled are key cost factors. The tighter the emissions limits, the more expensive the pollution control systems will cost to build and operate, and the more energy they will consume. All the coal-fired plants in this study meet national pollution control requirements, which vary from country to country. The IEA (1997) summarises major pollution control standards for coal-fired power plants within IEA member countries. The pollutants controlled and environmental protection measures associated with coal combustion are nonetheless similar for all the plants in this study. The major pollutants of concern are airborne emissions of sulphur dioxide, nitrogen oxides and particulate matter. Sulphur dioxide is controlled in all cases presented in this report, except Brazil and India, by flue gas desulphurisation systems. The predominant wet scrubber design consists essentially of a reaction vessel in which the sulphur dioxide is absorbed from the flue gas stream by a slurry of limestone or other reagent. Sulphur removal efficiencies of 95% or more are possible. This type of desulphurisation system is expected to be installed on most new coal-fired power plants. Other configurations are possible, including spray dryer systems, dry sorbent injection and regenerable systems (Soud and Takeshita, 1994). The energy needed to operate a wet scrubber system consumes up to 1% of plant output. The system also adds up to 100-250 USD/kWe to plant capital cost (Takeshita, 1995), and also adds to operating and maintenance costs. Energy consumption and costs are closely related to the permissible level of sulphur dioxide emissions from the plant. Nitrogen oxides are controlled by modifications to the coal combustion system itself, to minimise their formation, and post-combustion removal. Staging air within the combustion zone (overfire air) and the use of low-NO X burners are the two primary combustion techniques which result in an immediate reduction in NO X production of up to 60% compared to uncontrolled coal combustion. Low-NO X burners are standard or the minimum NO X control requirement in many countries. Capital costs for these burners are not a significant cost element: typically 10-30 USD/kWe. If NO X emissions must be reduced below levels obtainable using combustion modifications, dedicated NO X removal systems must be installed. Generally selective catalytic reduction (SCR) systems are used for coal-fired stations. These involve the injection of ammonia or urea into the flue gas and the catalytically enhanced reaction of the reagent with NO X to form nitrogen and oxygen. SCR is the most effective NO X control technology, but is relatively expensive. All the flue gas must pass through catalyst beds. The catalyst reactor adds some 50-90 USD/kWe to the capital cost and induces higher plant electrical consumption. The catalyst itself must be periodically replaced at some expense. Half of the conventional coal-fired plants in this study in OECD member countries are fitted with SCR. None of the plants in non-member countries have postcombustion NO X control. Soud and Fukusawa (1996) describe developments in control of NO X emissions. The third major airborne pollutant from coal-fired stations is particulate matter. This is essentially the ash carried along with the combustion gases. Control of particulate matter has been incorporated in nearly all coal-fired power stations in OECD member countries for many years. One of two basic systems is included in all plants of this study. Electrostatic precipitators function by drawing particulate matter to electrically charged plates along the flue gas path. Fabric filters, installed in “baghouses,” 156
mechanically separate out the airborne particles in a large number of fabric bags arranged in parallel. The choice of system depends upon particulate emission limits, fly ash characteristics, total flue gas volume flow and other factors. Several advanced emission control systems are able to remove two or three of the major pollutant streams in a single system. For example, the E-beam process irradiates dirty flue gas with electron beams to remove sulphur dioxide and nitrogen oxides in a single process. Other catalytic and chemical combined removal processes are under development. However, these systems have not seen substantial commercial use yet. Other systems are typically required to control pollution from solid or liquid discharges from coal-fired stations. For example, waste water from power plant processes and runoff from coal and ash storage areas is typically treated before release. Coal ash must be used or disposed of in an environmentally acceptable way which requires, in some instances, special ash treatment to stabilise leachable materials found in coal ash. Fluidised beds Large coal-burning circulating fluidised beds operating at atmospheric pressure that increase efficiency compared with a conventional plant may be considered as commercially proven technology. They function by burning coal in a “bed” or dense cloud of aerodynamically suspended particles. The airflow suspending the particles is sufficiently strong that a portion of the particles is entrained out of the boiler and then recirculated to it via cyclones. As in conventional pulverised coal boilers, the heat released by combustion is captured within the boiler in water-cooled walls and then a series of heat exchangers which cool the combustion gases. Heat exchangers cooling the recirculated coal and ash particles are also used in the production of steam in some designs. The steam raised may be subcritical or supercritical, although to date fluidised bed boilers have employed subcritical steam systems. Sulphur dioxide emissions can be controlled by the addition of limestone or other sorbent to the bed. The limestone captures SO 2 in solid form, primarily as calcium sulphate, and thus avoids the need for post-combustion flue gas desulphurisation. Although NO X formation is minimised because of lower bed temperatures compared to those in a pulverised coal flame, post-combustion NO X control may still be required. The same post-combustion NO X control systems used in conventional coal plants may be used in fluidised-bed plants. Some form of particulate control is typically required (electrostatic precipitator or baghouse). Pressurised fluidised beds are similar in design to atmospheric fluidised beds, but their combustion chamber is held at pressure. This allows them to be combined with gas turbines which compress the combustion air and provide the expansion turbine for hot gases. Systems for cleaning the hot combustion gases must be used in this arrangement in order to protect gas turbine blading from entrained particulate and gas impurities. Pressurised fluidised beds may also be used to gasify coal for power production. No commercial plants of either type have been constructed, although a number of demonstration plants have been built and operated. Rather than circulating fluidised beds, these plants have used “bubbling” beds, or beds of lower fluidising velocity. No pressurised fluidised beds were included in the cost estimates of this study. Advanced steam cycles As previously noted, by using steam above its supercritical pressure the efficiency of steam power cycles may be increased, whether in pulverised coal or fluidised-bed boilers. Overall plant efficiency can be increased from roughly 38% (based on lower heating value) using subcritical steam cycles to 42-45% with supercritical steam. Steam conditions above 25 MPa (245 atmospheres) and 566°C, or 157
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NUCLEAR ENERGY AGENCY INTERNATIONAL
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ORGANISATION FOR ECONOMIC CO-OPERAT
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Table of Contents Table of Contents
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Figures Figure 3.1 Specific overnig
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The introduction of liberalisation
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150 USD/MWh at a 5% discount rate a
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The technologies and plant types co
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locations and/or very favourable co
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conclusions of the study were used
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Chapter 2 Input Data and Cost Calcu
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equipped with emission control devi
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Table 2.2 - Exchange rates (as of 1
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Table 2.4 - Coal plant specificatio
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Table 2.7 - Wind and solar power pl
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Table 2.10 - Other plant specificat
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Figure 3.1 - Specific overnight con
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exchange rates, the coal prices var
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Construction time Gas-fired power p
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USD/MWh 70 60 Figure 3.5 - Levelise
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O&M costs The specific annual O&M c
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Cost ranges for coal, gas and nucle
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Ratio 1.9 Figure 3.12 - Cost ratios
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Table 3.11 - Overnight construction
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Table 3.14 - Projected generation c
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Except for the offshore plant in th
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At 10% discount rate, the levelised
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At 5% discount rate, hydroelectrici
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Table 4.6 - Projected generation co
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A CHP plant typically supplies heat
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Figure 5.2 - Levelised costs of ele
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lower unit capital and operating co
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cost calculation for some 130 power
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It should be stressed that the plan
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Concluding remarks The lowest level
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Portugal Mr. António B. Gomes EDP
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Table A2.1 - Nuclear plant investme
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Overnight Capital Costs: Constructi
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Table A2.7 - Gas-fired (including C
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Table A2.10 - Wind plant investment
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Cost structure of supported green e
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The highest investment cost arises
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The expected development of the per
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● ● Autoproducers. These firms
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Canada The electricity market situa
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Natural gas - combined cycle gas tu
Page 108 and 109: Denmark Basic data Denmark has abou
Page 110 and 111: In the future, both an increase in
Page 112 and 113: nuclear operator Teollisuuden Voima
Page 114 and 115: these power generation methods. Two
Page 116 and 117: Figure 5 - Competitiveness of vario
Page 118 and 119: 2004. It envisages the gradual incr
Page 120 and 121: Table 4 - Gross electricity supply
Page 122 and 123: ● ● ● ● ● ● ● ● ●
Page 124 and 125: Electricity generation costs The to
Page 126 and 127: photovoltaic device. Finally the su
Page 128 and 129: Table 1 - Installed electric power
Page 130 and 131: Japan Consumers in Japan are suppli
Page 132 and 133: BPE will be established not as a bi
Page 134 and 135: Coal Coal fired power plants have b
Page 136 and 137: A new sewage treatment plant with a
Page 138 and 139: The interconnections between Portug
Page 140 and 141: In order to respond to these basic
Page 142 and 143: efficient energies and is reducing
Page 144 and 145: Liberalisation Basic restructuring
Page 146 and 147: External costs for electricity prod
Page 148 and 149: At the beginning of plant operation
Page 150 and 151: and high ash, moisture and sulphur
Page 152 and 153: The White Paper did not contain pro
Page 154 and 155: Table 7 shows the projected load fa
Page 156 and 157: other investment options available
Page 160 and 161: “ultra-supercritical” condition
Page 162 and 163: unmineable coal seams. All three pr
Page 164 and 165: Light water reactors require enrich
Page 166 and 167: concerns. Consequently, the natural
Page 168 and 169: generators and power electronics el
Page 170 and 171: conventional fossil-fired plants. B
Page 172 and 173: ● ● very effective and is used
Page 175 and 176: Appendix 5 Cost Estimation Methodol
Page 177: into account in the real price of g
Page 180 and 181: ● ● ● ● Factors under the c
Page 182 and 183: and small power plants. Although th
Page 184 and 185: The general approach remains useful
Page 186 and 187: Two US economic analyses of nuclear
Page 188 and 189: assume future prices follow a rando
Page 190 and 191: The effects of price risk on techno
Page 192 and 193: The option to delay is embedded in
Page 195 and 196: Appendix 7 Allocating the Costs and
Page 197 and 198: Further Fourier’s law for heat tr
Page 199 and 200: Figure A7.4 - The energy conversion
Page 201 and 202: This yields: β = 0.153 α. If α e
Page 203: It is emphasised that depending on
Page 206 and 207: 1 st oil shock 2 nd oil shock Saudi
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Table A8.2 - Expected lower and upp
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Reliability in electricity systems
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is also highly dependent on the typ
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In the ILEX study 5 and in another
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an increasing share of wind is the
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able to work out the optimal operat
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Appendix 10 Impact of Carbon Emissi
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costs of generation. The introducti
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price at 3.5 €/GJ are the next fa
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Figure A10.5 - Steam coal price var
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The longer term impact on investmen
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Appendix 11 List of Main Abbreviati
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