Future Options for Brown Coal based Electricity Generation - the Role of IDGCC

Transcription

1 Future Options for Brown Coal based Electricity Generation - the Role of IDGCC T.R. HRL Developments Pty Ltd 677 Springvale Road Mulgrave Vic 3170 AUSTRALIA johnt@hrl.com.au Abstract Brown coal is a substantial component of Australia s energy supply, providing the fuel source for about 25% of its electricity. In the state of Victoria, the Latrobe Valley brown coals support more than 6000 MW of generating capacity. The current technology is pulverised coal fired steam cycle plants, which are fitted with electrostatic precipitators and generally have a good environmental record. Coal sulphur is low and emission controls are not needed to meet air quality objectives. Similarly the low nitrogen content of the coal, combined with the characteristics of the combustion system, leads to low NOx emission levels. Emissions of trace elements are also low. However, the level of CO 2 emissions is high, currently above 1200 kg/mwh, because of the high moisture content of the coal. This is the major environmental challenge facing brown coal at the present time. A number of initiatives are under way to meet this challenge. For new plants, several technology choices are available, offering different levels of CO2 reduction. Supercritical steam plants give improved efficiency and are already commercial. Integrated Gasification Combined Cycle (IGCC) is an advanced technology for converting coal into electricity where the coal is first gasified and then the gas is burned in a gas turbine to produce electricity. Overall, the conversion efficiency of an IGCC power plant is about 30% higher than a conventional steam power plant, with correspondingly lower CO2 emission intensity. IGCC also offers lower pollutant emissions than conventional plants. An efficient drying system is needed for the full benefit of the new technology to be realised. HRL is developing an IGCC technology for wet brown coal that closely integrates the drying and gasification processes. This technology, known as Integrated Drying Gasification Combined Cycle (IDGCC), uses the hot fuel gas produced in the gasifier to dry the incoming coal under pressure in a direct contact entrained flow dryer. This cools the gas, reducing the requirement for costly heat exchangers. The integrated coal drying process reduces the cost of drying the coal, eliminates expensive gas cooling heat exchangers and also increases the power produced by the gas turbine. When these advantages are combined with the use of cheap brown coal, the cost of electricity produced is highly competitive with alternative systems. The IDGCC process has been demonstrated at 10 MW scale in HRL s Coal Gasification Development Facility at Morwell. HRL plans to proceed to an 800 MW brown coal IDGCC plant by the end of the decade. The Victorian Government has granted an exploration licence over sufficient coal for 40 years operation of that power station. HRL will build a 100 MW intermediate scale brown coal IDGCC plant in the Latrobe Valley in the next four years as the first commercial demonstration of this patented technology. Successful development of IDGCC technology opens the way for oxygen-blown brown coal IGCC suitable for CO 2 capture and sequestration (CCS) in the period and will bridge to the hydrogen economy. Oxygen-blown brown coal gasification has already been tested by HRL in its pilot scale gasifier in Mulgrave. INTRODUCTION Brown coal is a substantial part of Australia s energy supply, providing the fuel source for over 25% of its electricity. In the state of Victoria, the Latrobe Valley brown coals support more than 6000 MW of generating capacity and produce more than 90% of the state s power requirements. Thus brown coal is a key component of the energy mix in Australia and makes a significant contribution to the economic prosperity of the state. 371

2 Three major open cut mines produce approximately 60 million tonnes per annum combined output. The coal is very high moisture content, greater than 60% wet basis, but has very low ash content, 2-4% dry basis and low sulphur, about 0.3% dry basis. The current technology is pulverised coal fired steam cycle plants, which are fitted with electrostatic precipitators and generally have a good environmental record. Because coal sulphur is low, emission controls are not needed to meet air quality objectives. Similarly the low nitrogen content of the coal, combined with the characteristics of the combustion system, leads to low NOx emission levels. Because of low levels of trace elements in Latrobe Valley coals, emissions of these components are also low. However, the level of CO 2 emissions is high, currently above 1200 kg/mwh, because of the high moisture content of the coal. This is the major environmental challenge facing brown coal at the present time. CURRENT UTILISATION OF LATROBE VALLEY BROWN COAL Current Technology Current technology for pow er generation from Latrobe Valley coal is similar to that used for higher rank coals, i.e. steam power stations using pulverised coal fired boilers and reheat steam cycles with multiple stage feed heating. The unit capacity ranges up to 500 MW, although larger units have been constructed elsewhere, notably Germany. The largest units in the Latrobe Valley (Loy Yang) are 500 MW. Typically the boilers are tower type construction (German technology) with all the tube banks located directly above the furnace. A key feature for high moisture coals is the mill-drying system, which uses hot gas from the upper furnace to dry the coal within beater wheel/fan mills. Dried pulverised coal, evaporated water and drying gas are all fed to the burners. A schematic of a brown coal power plant is shown in Figure 9. Ash fouling has been a problem with Latrobe Valley coal, both in the furnace and in tube banks. The boilers have generous size furnaces and gas passes plus large numbers of sootblowers to manage the ash fouling. As a result the furnace is large, flue gas flow is high, efficiency is low and the cost of plant is high. Emissions Emissions are a major concern for all coal-fired power generation and regulatory authorities are setting increasingly stringent limits as coal use grows. Low-rank coals also need to meet these limits if they are to be accepted and used for future power generation. The applicable limits vary from country to country depending on their perception of the problems they face. In Australia the limits are not as stringent as in other countries with high population densities and high levels of industrial activity. Emissions of NOx from Latrobe Valley coals have generally been low compared to higher rank coals. The nitrogen in low-rank coals releases mostly into the gas phase during devolatilisation, making staged combustion an effective control technique. In Victoria, it has been possible to meet the current standards without any combustion modifications. Sulphur emissions are highly dependent on the sulphur levels in the coal. For Latrobe Valley coals the sulphur is typically 0.3% (dry basis) and some of the sulphur is captured in the fly ash, so no control measures are necessary to meet Victorian emission limits. 372

3 Figure 1. Schematic Layout of Brown Coal-Fired Power Station Electrostatic precipitators (ESP) are used to control dust emissions. Bag filters have not been used because of the large flue gas flow and high flue gas temperature which was initially above the safe limit for the filter material. ESP s have given excellent results provided that they have been designed to take account of the characteristics of the ash. For example, ESP performance in the Latrobe Valley was greatly improved when the design allowed for the very low bulk density and low cohesiveness of some ashes from coals containing high levels of soluble aluminium. Trace element concentrations in Latrobe Valley coals are low with consequently low emissions. Measurement of emissions from Victorian brown coal fired power stations showed that the concentrations of many of the trace inorganics were well below the detection limit for the sampling and analysis methods employed. The majority of the trace inorganic constituents remaining in the gas stream after the power station dust collection system were associated with the particulate fraction of the gas stream. Cadmium and mercury were found to be the main trace inorganics present in the gaseous fraction. Efficiency and CO2 Emissions Overall thermal efficiency of Latrobe Valley brown coal stations is low. The main reason is the heat loss in the latent heat of water vapour in the flue gas due to the high moisture content of the coal. Also the flue gas temperature is high to minimise dewpoint corrosion in the back end of the boiler. The sent-out efficiency of the Loy Yang power station is 28% (on Higher Heating Value basis) compared to about 36% for high-rank coal fired power stations. Efficiency could be higher by design, but to date the economic incentive has been low because the low cost of the fuel. Table 1. CO2 emissions from different fuels and power cycles. Process Efficiency % CO2 emissions (HHV) kg/mwh sent out Brown Coal - p.f.-fired subcritical steam cycle Brown Coal - IDGCC Black Coal - p.f.-fired subcritical steam cycle Black Coal - IGCC Natural gas - steam cycle Natural Gas - GTCC CO2 emissions have become a major world environmental issue with growing concern over the 373

4 greenhouse effect. Low-rank coals produce higher amounts of CO2 per unit of electricity sent out compared to higher ranked coals. This is because the conversion efficiency is low. Effectively, carbon is burnt to provide the heat to dry the coal. Table 1 shows the relative emissions of CO2 from different fuels and power cycles. Cost Capital cost of current technology brown coal fired plants is higher than equivalent output plant for high-rank coals. The high moisture content leads to large gas flows and low flame temperatures. The low temperatures in turn lead to large heat exchanger areas and higher cost. The costs of the mills and drying shafts are also high and there are extra costs in managing ash fouling such as increased furnace size and large numbers of sootblowers. Despite the relatively high capital cost of brown coal plants, the cost of electricity sent out can be competitive because the coal cost is so low. Latrobe Valley brown coal occurs in thick seams under shallow overburden and is mined easily from large open cut mines. The marginal cost of electricity from this is low and in the highly competitive electricity market of recent years the Latrobe Valley generators have been able to maintain high market share even if at low profitability. New brown coal plant capacity using current technology would not be commercially competitive in this environment. ADVANCED TECHNOLOGY FOR BROWN COAL POWER The major challenges facing low-rank coals are cost and CO 2 emissions. CO 2 emissions are higher for low-rank coals because of the low conversion efficiency. New plant options for improved efficiency include supercritical steam plants and integrated gasification combined cycle (IGCC). Supercritical lignite fired power plants have been constructed in Germany over the past decade and have become state of the art for steam power plants. The most recent plant is the 1000 MWe Unit K at Niederaussem near Köln (Heitmüller et al, 1999). This plant has steam conditions 274 bar pressure 580C/600ºC-steam/reheat tem perature. In addition to the high steam cycle conditions the plant has advanced heat recovery from the flue gas to both the combustion air and feed water, and new high efficiency steam turbine blade design. Overall the net efficiency is estimated to be 45.2% (LHV) corresponding to 37.7% (HHV). If this technology was used for the wetter Latrobe Valley coals (62% moisture instead of 53%) the overall efficiency would be about 34.5% (HHV) (McIntosh et al, 2000). This is a substantial improvement over current technology (28% HHV). The CO2 emission intensity would be about 19% lower than current technology. Integrated gasification combined cycle (IGCC) is an advanced power generation technology that offers substantial increase in efficiency over current steam plant technology. In IGCC the coal is first gasified and then the gas is burned in a gas turbine to produce electricity. The heat in the gas turbine exhaust is then used to generate steam to drive a steam turbine to produce additional electricity. Overall, the conversion efficiency of an IGCC power plant is about 30% higher than a conventional steam power plant, with correspondingly lower CO 2 emission intensity. IGCC also offers lower pollutant emissions than conventional plants. For wet brown coals IGCC requires the addition of a drying process before the coal can be gasified HRL has developed a new gasification process specifically for high moisture, low-rank coals (Anderson et al, 1998). The process is called Integrated Drying Gasification Combined Cycle or IDGCC. It combines a simple entrained-flow dryer with an air blown fluidised bed gasifier by using the hot product gas from the gasifier to dry the coal under pressure. The gas is used in a gas turbine combined-cycle, and although the heat of evaporation is still lost, the evaporated water produces useful power as it expands through the gas turbine. 374

5 IDGCC TECHNOLOGY IDGCC Process The IDGCC process is shown in Figure 2. It consists of an air-blown, pressurised fluidised bed gasifier that is fed with coal from an integrated drying process. The feed coal is pressurised in a lock hopper system and then fed into dryer where it is mixed with the hot gas leaving the gasifier. The heat in the gas is used to dry the coal whilst the evaporation of the water from the coal cools the gas without the need for expensive heat exchangers. The coal dryer is smaller and cheaper to build than conventional coal dryers because it operates under pressure. NITROGEN COAL PRESSURISATION LOCKHOPPER BUFFER / WEIGHING HOPPER COAL DRYING AND GAS COOLING DRYER DRIED COAL CO2 ASH/ CHAR GASIFIER COOLED GAS CYCLONE AIR AIR HOT GAS CLEANED GAS DUST FILTER ASH/ CHAR CLEANING COMPRESSOR AIR COMBUSTOR GAS TURBINE BOILER TURBINE TO STACK EXHAUST GASES STEAM STEAM TURBINE WATER PUMP STEAM TURBINE HEAT RECOVERY ALTERNATOR CONDENSER Figure 2. Diagram of the IDGCC Process. The air for gasification is extracted from the gas turbine compressor then compressed again before being fed into the gasifier at 25 bar pressure. The gasifier operates at about 900 C which is below the melting point of the coal ash. Unconverted carbon and ash is removed from the bottom of the gasifier and also from the ceramic filter. This waste char material is burnt in an auxiliary boiler to recover as much as possible of the energy from the coal. The final ash product is then similar to that from a conventional brown coal boiler. Dust emissions from the process are very low because of the very effective ceramic filters that remove the dust from the coal gas before combustion. The filters are reverse pulse cleaned on-line. In the IDGCC process the filters operate at about 300 C which is much lower than in some IGCC processes. Coals containing high levels of sulphur require additional action to absorb the sulphur containing gases before they reach the gas turbine where it will form SO 2 in the turbine combustors. The sulphur can be absorbed in the gasifier by adding limestone or dolomite with the coal and the sulphur becomes incorporated into the ash. The sulphur compounds can also be absorbed in a separate fluid bed system that uses a sorbent that is regenerated in another bed and then re-used. Nitrogen compounds in the coal are partially converted into ammonia in the gasifier. This ammonia will form NOx in the gas turbine combustors. The ammonia can be absorbed from the fuel gas and converted to fertiliser as a by-product and the NOx levels from the gas turbine can be reduced to quite low levels. The water vapour from the coal becomes part of the product gas. This reduces the heating value of the gas but it can still be burnt in commercially available gas turbines fitted with appropriate burners and gas control equipment. The added moisture in the fuel gas has the beneficial effect of increasing the power produced by the turbine and thus reducing the cost of electricity produced by the plant. 375

6 Technical Performance of an IDGCC Power Plant The IDGCC process has much higher energy conversion efficiency than conventional steam power plant. For Latrobe Valley coal the conversion efficiency of coal to electricity sent out is predicted to be 38-41%, based on the higher heating value (HHV) of the coal. This compares with 28% for the most recent steam power plant in the Latrobe Valley, about 35% for a black coal fired steam power plant and about 38-41% for black coal fired IGCC plant. GT CC - Natural Gas IGCC - Black Coal IDGCC - Low Rank Coal Boiler - Black Coal Boiler - Low Rank Coal Carbon Dioxide Emission kg/mwh Figure 3. Typical Ranges of CO 2 Emissions for Different Fuels and Technologies This substantial increase in efficiency leads to a corresponding reduction in emissions of CO2 as shown in Figure 3. The CO2 emission rate for a brown coal fired plant is reduced from 1160 kg/mwh for a steam power plant to 850 kg/mwh for the IDGCC plant. This is lower than the rate for conventional black coal plant and only slightly higher than a black coal IGCC. This means that low rank coals can be considered equally with higher rank coals for power generation when considering their impact on greenhouse gas emission rates. The shaded part of the bars in Figure 3 represents the effect of a range of plant efficiencies and coal composition. Simulations of a number of process configurations have been performed using commercial software such as ASPEN and GTPRO. A typical configuration for a 125 MW scale plant has a thermal conversion efficiency for Latrobe Valley coal to electricity sent out of 37.9% based on the HHV of the coal, as shown in Table 2. Table 2. Predicted Data for Victorian Brown Coal 125 MW-Scale IDGCC Gas Turbine Model: GE 6FA Input: Product Gas: Raw Coal Flow Rate (t/h) 93.1 Gas Heating Value (Net MJ/kg) 4.0 Coal Moisture (% w.b.) 50.0 Coal ash content (% db) 5.0 Gas C omposition (vol %) Gross Dry Specific Energy (MJ/kg) 26.3 CO 15.0 Output: H Gas Turbine Output (MW) 87.4 CH4 2.2 Steam Turbine Output (MW) 51.8 CO2 9.0 Power used in Station (MW) 12.3 H2O 25.0 Electricity Sent Out (MW) N2 + Ar 34.7 Net Efficiency on HHV 37.9 % Trace gases 0.6 Net Efficiency on LHV 43.2 % Total CO2 Emissions (kg/mwh)

7 IDGCC Cost IDGCC is cheaper than a steam cycle plant fuelled by low rank coal and it can compete with black coal fired plant. The integrated coal drying process reduces the cost of drying the coal, eliminates expensive gas cooling heat exchangers and also increases the power produced by the gas turbine. When these advantages are combined with the use of cheap low-rank coal, the cost of electricity produced is highly competitive with alternative systems. Economic evaluations for a full-scale 800 MW power station for a number of possible technologies for base load power generation have shown the economic superiority of the IDGCC process for a power plant in south-eastern Australia. This is illustrated in Figure 4, which shows the cost of electricity produced by three different technologies for a range of power station sizes. The higher capital cost of the coal-based options is balanced by their lower fuel cost compared to natural gas. The IDGCC option offers the lowest cost of energy sent out to south-eastern Australia where the cost of low -rank coal is quite low. 7 6 Black Coal PF 5 2 x 130 Natural Gas CC 4 2 x x x x x 410 Plant Size, MW Brown Coal IDGCC Brown Coal Black Coal Coal Price, A$/tonne (Note: A$1.00 = US$0.65 approx) Fuel Cost, A$/GJ Figure 4. Cost of Electricity from IDGCC Compared with Other Technologies IDGCC Development Program The IDGCC process has been developed through the following stages: 1. Laboratory scale tests. 2. Atmospheric pressure gasifier at 50 kg/h (dry coal feedrate). 3. Pressurised Gasifier at 300 kg/h (dry coal feedrate), 10 bar. 4. Pressurised gas combustion test rig, at 500 kg/h (gas flowrate), 6 bar. 5. Pressurised coal drying test rig at 1500 kg/h (wet coal feedrate), 10 bar. 6. Integrated gasifier, dryer and 5 MW gas turbine at 10,000 kg/h (raw coal feedrate), 25 bar. Stage 6 of this program, the Coal Gasification Development Facility (CGDF) is discussed below. CGDF Design and Construction The Coal Gasification Development Facility was constructed at Morwell, in the Latrobe Valley in Victoria, commencing in September Th e facility was commissioned in July

8 The facility has a throughput up to 10 tonne per hour of raw coal, at the full pressure of 25 bar. This represents a process capacity of 10 MW output. An EGT Typhoon gas turbine of nominally 5 MW generating capacity operating in simple cycle mode is used. It does not include the heat recovery steam generator or the steam turbine as these are already commercially proven technologies. The CGDF includes the following key elements that needed proof of concept: - 1. The pressurised coal feed system. 2. The pressurised coal drier. 3. The coal gasification unit. 4. The hot gas filtration unit. 5. Combustion of the coal gas in gas turbine. 6. An ammonia scrubber. 7. Sulphur absorption test rig. When operating at the maximum coal feed rate, the gasification process produces more gas than can be burnt in the gas turbine. A separate flare stack is used to dispose of the excess gas. There are some periods when this flare is required to take the full gasifier output, while the gas turbine operates on auxiliary fuel. The facility is shown in Figure 5. The gasifier/drier is in the main structure, and the gas turbine, exhaust stack and control building are behind the structure. The height of the main structure is about 30 metres. A range of coals was tested, concentrating mainly on Morwell coal from the Latrobe Valley. Each coal was tested initially in short run operation to obtain data over a range of operating conditions, with some extended runs to investigate longer-term effects such as ash fouling behaviour and dust filter performance. Plant Operation and Results The plant achieved 85 runs between commissioning in June 1996 and the end of the test program in December Full operation of the integrated system, including combustion of the coal gas in the gas turbine was achieved after 14 runs, following the change-over of the gas turbine to dual-fuel combustors. The turbine has been operated at full power output on coal gas, giving up to 5.2 MW compared to its site rating of 4.3 MW on liquid fuel. The generator was synchronised and connected to the national power grid for all the tests. The plant is easy to start by preheating with nitrogen and then introducing char into the gasifier through a separate feed system, followed by the introduction of air and steam through the fluidising jets. Initially the gas turbine is operated on liquid fuel, with a water spray into the dryer inlet to control the coal gas temperature. Only a short time (several hours) is needed to reach steady operating conditions before introducing raw coal. The gas quality produced is dependent on the amount and distribution of air and steam in the gasifier bed. Different settings were tested to determine the conditions needed produce gas with a heating value at the design level of 4.0 MJ/kg. Formation of ash clinkers in the bed was closely monitored since this is potentially a problem with coals having ash with low fusion temperature. For example, work in the smaller pilot gasifier showed that the rate of clinker formation was dependent on the fluidised bed temperature and the levels of sodium and silica in the coal. The bed temperature is controlled by adjustment of the air and steam flows to the gasifier. 378

9 Figure 5. The Coal Gasification Development Facility at Morwell The gasifier proved to be very stable and easy to operate. The fluidised bed, with its large particle residence time, can accept short term variations in coal feed rate and moisture content with little change in product gas quality. The integrated dryer operates well, giving the correct level of gas cooling with sufficient drying of the coal to give stable gasifier operation. The ceramic filter initially suffered some element failures due to operational problems but later it operated well with no further breakages and very effective dust removal. The ammonia scrubber was effective in removing ammonia from the product gas and reducing NOx from the turbine to low levels. Large reductions in sulphur emissions were demonstrated using additive in the gasifier and also with a regenerable sorbent system. Overall the CGDF testing plus the supporting research has shown that the IDGCC technology is technically feasible. The concept of integrating the drying with gasification was proven and found to work well. COMMERCIALISATION A series of process and cost studies were run in parallel with the laboratory and large gasifier plant trials. These studies included 125 and 400 MW plants and indicated favourable economics from a range of coal types. Sent-out efficiencies of 41-43% (HHV) were predicted for the more highly reactive Latrobe Valley coals in the larger plant. The 125 MW plant has a predicted efficiency of 36% (HHV) and CO2 emissions of 950 kg/mwh sent out for coals of 2% ash and 62% moisture (currently, the PF station operating on this coal is achieving 28% HHV, and emitting 1160 kg/mwh of CO2). The lower efficiency of the smaller plant is the result of 379

10 higher heat losses and lower carbon conversion efficiency. HRL plans to proceed to an 800 MW (2 x 400 MW) IDGCC plant in the Latrobe Valley by the end of the decade. The Victorian Government has granted an exploration licence over sufficient coal for 40 years operation of that power station. This plant is expected to have a CO2 emission intensity of about 820 kg CO 2 per MWh and produce electricity at a cost of about 3 cents per kwh (1998 costing). The next step in the development is a commercial demonstration at 125 MW to keep scale-up risk to acceptable levels. A demonstration scale greenfields IDGCC plant would cost about $250M and generate power at 4.6 cents/kwh sent out. Such a small plant however would not have been competitive against MW stations supplying the grid with power at 3.5 cents/kwh on a long run levelised basis. Accordingly, HRL is exploring other modes/structures for this demonstration. A re-powering or piggy-back version of an IDGCC plant is now being developed that can be located on an existing power station site and make use of available infrastructure such as coal supply, grid connection, site services, etc. The economics look attractive, particularly where the host plant needs steam to re-power existing steam turbines. Successful development of this technology opens the way for oxygen-blown brown coal IGCC suitable for CO 2 capture and sequestration in the period Oxygen-blown brown coal gasification has already been tested at pilot scale in the HRL gasifier in Mulgrave. REFERENCES Anderson, B. et al (1998). Development of Integrated Drying and Gasification of Brown Coal for Power Generation. Institute of Chemical Engineers Conference: Gasification The Gateway to the Future, Dresden, Germany, September Heitmuller R.J., Fischer H, Sigg J, Bell R.M. and Hartlieb M (1999). Lignite-fired Niederaussem K aims for efficiency of 45 per cent and more, Modern Power Systems, May McIntosh M, Simpson M and Huynh D (2000). Predrying of Lignite Fuels to improve Power Plant Efficiency, Japan-Australia Joint Technical Meeting on Coal, Fukuoka, December