4. Future Unit Costs
Cost estimates given in the Table 5 and Table 6 and the tables and figures in Appendix C have "learning" factors built into them. These take into account the reductions in cost that occur as plants move from the demonstration stage to initial commercialisation (where a few units are built) to full commercialisation (where many such plants are built). Technological improvements that are expected to occur, such as increased efficiency, are also included.
"Low" and "high" technology uptake scenarios have been included to indicate the spread of values with the "expected value" the most likely case.
In the "low" technology uptake scenario, the costs and efficiencies of advanced generating technologies (i.e. Advanced Gas Combined Cycle and Advanced Combustion Turbine) remain at current levels. Learning is applied to the "expected" technology cases. In the "high" technology uptake scenario, efficiencies of advanced fossil generating technologies are based on the United States Department of Energy, Office of Fossil Energy's Vision 21 programme goals. This scenario represents the upper limits of efficiencies considered to be achievable within the period through to 2015.
Vision 21, builds on a portfolio of technologies already being developed, including low-emissions combustion, gasification, high efficiency furnaces and heat exchangers, advanced gas turbines, fuel cells, and fuels synthesis, and adds other critical technologies and system integration techniques.
Capital costs and efficiencies for each of the technologies will be dealt with in turn. Tables 5 and 6 show the estimated generation costs in 2012 and 2025. The costs are sensitive to changes to capital, fuel and O&M costs, plant factors and discount rates. O&M and fuel costs have been kept at the same level as the 2003 cases.
The effects of the capital costs and efficiency changing through time are shown in more detail in Appendix C. The effects of capital cost and changes in efficiencies of these on the various unit cost components are also shown in tabular as well as graphical form.
Table 5: 2012 Electricity Cost Estimates (7.5% Discount Rate, 20 Year Life, $5.00/GJ Gas, $3.50/GJ Bituminous Coal, 90% Load Factor)| Technology | Cost c/kWh |
| MW | Capital | Fuel | O&M | Tax | Total |
| Combined cycle advanced gas turbine | 400 | 1.1 | 3.4 | 0.4 | 0.3 | 5.1 |
| Combined cycle gas turbine | 250 | 1.0 | 3.7 | 0.4 | 0.2 | 5.4 |
| Open cycle advanced gas turbine | 230 | 0.8 | 4.5 | 0.5 | 0.2 | 5.9 |
| Open cycle gas turbine | 160 | 0.7 | 5.5 | 0.6 | 0.2 | 7.0 |
| Bituminous supercritical with FGD | 500 | 2.4 | 3.2 | 0.9 | 0.6 | 7.1 |
Table 6: 2025 Electricity Cost Estimates (7.5% Discount Rate, 20 Year Life, $5.00/GJ Gas, $3.50/GJ Bituminous Coal, 90% Load Factor) | Technology | Cost c/kWh |
| MW | Capital | Fuel | O&M | Other | Total |
| Combined cycle advanced gas turbine | 400 | 1.1 | 3.4 | 0.4 | 0.2 | 5.0 |
| Combined cycle gas turbine | 250 | 1.0 | 3.7 | 0.4 | 0.2 | 5.4 |
| Open cycle advanced gas turbine | 230 | 0.7 | 4.5 | 0.5 | 0.2 | 5.8 |
| Open cycle gas turbine | 160 | 0.7 | 5.5 | 0.6 | 0.2 | 7.0 |
| Bituminous supercritical with FGD | 500 | 2.3 | 3.2 | 0.9 | 0.6 | 7.0 |
4.1 Technological Trends - Commentary
Technological trends in fossil fuelled electricity generating plant are being driven by the need to reduce environmental discharges, and reduce operating costs. The need to have technologies that reduce the cost of reducing or sequestering carbon dioxide emissions is also a driver. This increases the requirement for greater efficiency and, as the technology matures, to be competitive in the market place. The technology that is followed will be determined to some degree by the relative delivered costs of natural gas and coal.
Hybrid plants using a mixture of gas turbine and coal plant of varying configurations will continue to be investigated. An example of this is to use the exhaust from a gas turbine as a feed heating source for a supercritical pf plant.
4.1.1 Coal Based Technologies
Pulverized Coal
In a conventional plant pulverised coal is burnt in a boiler to produce steam, which is fed into a steam turbine coupled to an electrical generator. Emission controls such as electrostatic precipitators or bag houses, and flue gas desulphurisation (FGD) limit pollutants (particulates, sulphur and nitrogen oxides) to permitted levels. A typical example of this type of plant is Huntly power station (except that it does not have FGD because of low sulphur levels in NZ sub-bituminous coals).
Plant designs with advanced steam parameters have generally not been favoured by the regulated U.S. market economics until relatively recently. In Europe and Japan supercritical pressure designs are more common and have proven experience. Advances in materials development are facilitating design of steam power cycles with higher efficiencies.
The increased need for greater efficiency and operating benefits are favouring supercritical plant. Further advances in materials will lead to even higher pressures and temperatures, the so called advanced or ultra supercritical plant with an efficiency of about 44%. More effective environmental controls will also be a feature of future plants. (A brief description of the difference between a subcritical and a supercritical boiler is given in Appendix H.)
Fluidized Bed Boiler
Fluidised beds suspend solid fuels on upward-blowing jets of air during the combustion process. The result is a turbulent mixing of gas and solids, much like a bubbling fluid. The mixing action of the fluidised bed brings the flue gases into contact with a sulphur-absorbing chemical, such as limestone or dolomite. More than 95 percent of the sulphur pollutants in coal can be captured inside the boiler by the sorbent.
Fluidized bed boilers can burn almost any combustible material, from coal to municipal waste, and are capable of meeting sulphur dioxide and nitrogen oxide emission standards without the need for expensive add-on controls.
Fluidized bed combustion (FBC) is often seen as an alternative to pf firing. This technology has some inherent environmental advantages over pf firing; lower NOx emissions without the need for special equipment and the ability to burn coals with a range of sulphur content without separate FGD equipment.
Pressurised fluidized bed boilers offer the potential of higher efficiencies but appear to be out of favour in the USA and UK.
Gasification
Rather than burning coal directly, coal gasification reacts coal with steam and controlled amounts of air or oxygen under high temperatures and pressures to produce a gaseous mixture, typically hydrogen and carbon monoxide. These hot, coal gases exiting the gasifier are used to power a gas turbine (in the same manner as natural gas). Hot exhaust from the gas turbine is then fed to a heat recovery steam generator (HRSG). The steam from the HRSG is then fed to a conventional steam turbine, producing a second source of power (just as in a combined cycle plant).
Pollutant-forming impurities and greenhouse gases can be separated from the gaseous stream. Unreacted solids can be collected and marketed.
Integrated gasification combined cycle (IGCC) plant is used in a large number of refinery and chemical industry facilities using primarily petroleum feedstocks. The transfer of IGCC technology using coal as a feedstock for electricity generation has not been as successful. Demonstration plants have had higher costs and lower efficiencies than expected. This technology is considered to be an emerging one.
IGCC has a number of potential benefits: high efficiency, can handle high sulphur coals, emissions similar to gas firing and the potential for carbon dioxide capture. It is receiving considerable interest and funding by US Federal agencies with a target of having similar costs to pf plant.
The syngas from the gasifier contains significant amounts of hydrogen so the gas after treatment has the potential for use in fuel cells. The hydrogen and sulphur could also be removed and used as a chemical feedstock for the manufacture of methanol, ammonia, fertilizers and other chemicals.
4.1.2 Gas Based Technologies
Cycle Gas Turbine (Combustion Turbine)
Combustion of the fuel produces a high-temperature, high-pressure gas working fluid. When this is exhausted through a gas turbine this causes the shaft to rotate by expanding the gas through a series of specially designed blades. The rotating shaft drives an electric generator and a compressor for the inlet air used by the gas turbine. Many turbines also use a heat exchanger called a recuperator to add turbine exhaust heat into the combustor's air/fuel mixture.
Gas turbines are compact, lightweight, easy to operate, and come in sizes ranging from several hundred kilowatts to hundreds of megawatts.
Examples of this type of plant are the earlier gas turbines at Otahuhu power station. Current gas turbines are more efficient.
Cycle Advanced Gas Turbine
This type of gas turbine can operate at higher temperatures through the use of more exotic materials, sophisticated cooling and other enhancements to achieve higher efficiencies.
Combined Cycle Gas Turbine
Fuel, generally natural gas (but can be other gaseous or liquid fuels), is burned in a gas turbine coupled to an electrical generator. The exhaust (a hot gas stream) from the gas turbine is then passed into a heat recovery steam generator (HRSG), which can be fired or unfired. The steam is then fed to a conventional steam turbine to provide a second source of power. Otahuhu B Power Station and Taranaki Combined Cycle Power Station at Stratford are examples of this type of plant but at the time of ordering they would have been considered to be more in the advanced class of combined cycle plant.
Combined Cycle Advanced Gas Turbine
This is a type of combined cycle plant utilising higher temperatures through the use of more exotic materials and other enhancements to achieve higher efficiencies.
Developments will continue in gas turbine plant relating to increases in firing temperatures (materials and cooling techniques) multi-staged firing and the thermodynamic cycle (intercooling, reheat, and hybrid cycles).
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