Dr Heather Johnstone, Chief Editor
The European Union’s Industrial Emissions Directive (IED) replaces seven existing EU Directives; one of which is the Large Combustion Plants Directive (LCPD). Under the LCPD, power plant operators were required to limit the emissions to atmosphere of certain pollutants, in particular nitrogen oxides (NOx) and sulphur dioxide (SO2).
Power plant operators were also given the option to ‘opt out’ of the LPCD obligations on the condition that they ceased plant operation by the end of 2015 or after 20 000 operating hours beginning from 1 January 2008, whichever came sooner. With Europe’s ageing combustion power fleet, many operators saw the opt-out as the preferred option because at the time the investment needed to meet the new emissions limits was not deemed economically viable.
The LCPD’s requirements are still valid under the IED, so many power plants are due to cease operations by the end of 2015, reducing EU generation capacity by about 130 GW, or 16 per cent. Given the ongoing decommissioning of ageing nuclear plants and recent changes in attitude towards new nuclear development, plus the expectation that demand for electricity will increase, a significant energy supply gap could open.
Conventional thinking says that you would expect to see a significant increase in the demand for new-build plant. But the planning process for developing new power plants can be challenging. So what about the reuse of existing sites? Could there be new opportunities for older plants that were opted out under the LCPD legislation to help meet any energy shortfall in the short term?
Parsons Brinckerhoff posed the question in a study released at the end of last year which investigated available options for such power plants to continue operating beyond 2015, on the condition they meet the ‘new plant’ requirements of the IED, and compared the relative costs and practicalities associated with four potential options:
- Plant upgrade (installation of pollution control measures);
- Plant refurbishment (replacement of main plant equipment such as boilers and turbines);
- Plant conversion (conversion to alternative fuel source or technology);
- Reuse of site (complete plant replacement on existing site).
The parameters of a typical, utility-scale thermal power plant which would be expected to be opted out under the LCPD regulations were used as the base reference plant – based on a four unit, subcritical pulverised fuel plant, with each unit having a gross electrical power output of 500 MW. Lignite was chosen as the most appropriate fuel for the evaluation, representing a ‘worst case’ scenario.
Option 1: Plant Upgrade
Plant upgrading is considered as additions and/or changes to the plant without major changes to the major components of the power island. About 95 per cent of the sulphur in coal is emitted as sulphur dioxide (SO2), so the most effective means of cutting emissions is through sourcing an alternative fuel. Another option is to remove the SO2 directly from the exhaust gases using a flue gas desulphurisation (FGD) plant, which would normally remove about 95 per cent from the flue gases.
While offering the benefit of reduced SO2 emissions, FGD increases energy consumption. Auxiliary power consumption varies with system design, but based on the reference model, the study calculated the increase in auxiliary power consumption as about 6.5 MW for each 500 MW unit. The addition of FGD is also likely to reduce the station availability by up to 2 per cent.
For NOx emissions, low-NOx burners were not considered in the study as most power plants are likely to have already installed them. But selective catalytic reduction (SCR), which can have removal efficiencies of the order of 90 per cent, was investigated. As with FGD, this involves a considerable auxiliary load, including an uprating of the ID fans for a greater gas-side pressure drop.
Any existing plant is expected to need to install both FGD and SCR to meet the IED requirements. In the study, the cost of installing the FGD and SCR for the reference plant was estimated at €780 million ($1 billion). But an additional cost from changes in performance is anticipated. For a typical 2000 MW power plant, the introduction of FGD and SCR is expected to cut net plant output by about 37 MW and raise plant heat rate by about 2 per cent. In the analysis, assuming that the fuel input to the boiler is the same, lost revenue could total €200 million, presented as net present value (NPV) over a 25-year period.
The study’s figures are based on the assumption that no further upgrade or modification work is required to the existing power island equipment, and that the plant is otherwise in a suitable condition to allow further long-term operation. In reality, at least some refurbishment work is likely to be required. But as this will vary between plants, it was excluded.
Option 2: Plant Refurbishment
Plant refurbishment is considered as the replacement of major items of the power island including the boiler and the steam turbine, without changing the fundamental arrangement to provide a more efficient plant.
The study noted that this is not a replacement for the emissions control methods described above. Emissions controls would have still have to be implemented, but a more efficient plant will emit less per unit of generation, requiring smaller, less costly emissions control plant.
Many options are theoretically available but the study focused on three that had a practical application for the size and type of plant under consideration. First, replacing the existing boiler with a new subcritical boiler allows a small increase in boiler efficiency, reducing fuel consumption and emissions. Although it is likely that such a refurbishment would be accompanied by other refurbishments, this option looked purely at a replacement boiler.
Replacing the steam turbine in addition to the boiler not only allows for newer, more efficient equipment but enables the steam conditions to be increased, giving a further increase in efficiency. The existing feed heating plant and other auxiliary equipment could still be utilised.
Second, to maximise efficiency, replacing the existing subcritical plant with a new supercritical plant was considered. Based on current market trends and the availability of proven designs, the configuration for the supercritical option was changed to two 1000 MW blocks. Although supercritical units would give a higher efficiency, to date the largest operating supercritical circulating fluidised bed (CFB) units are 460 MW, so only subcritical CFB boilers were considered. The steam conditions were assumed to be unchanged from the reference conditions so the existing steam turbine would be retained. Based on the lower furnace temperature in a CFB boiler, the NOx emissions are lower than for a pulverised fuel boiler and it is likely that SCR would not be required. FGD would also be unnecessary because the limestone is injected directly into the fluidised bed.
For comparison purposes, each of the options considered that the gross plant output is maintained at a maximum of 2000 MW, in line with that of the reference plant. The analysis found that any of the options could be applied to meet the IED limits, although there is a wide range of associated costs. The CFB option was the most attractive, with the lowest installed capital cost and a marginal improvement in efficiency. Conversely, the supercritical option represented the highest improvement in efficiency, but its high capital cost suggests that this option would be less attractive to the power plant operator.
Option 3: Plant Conversion
As an alternative to refurbishment, there are several plant conversion options, which generally involve switching to an alternative fuel source, while retaining as much of the original plant equipment as practicable.
One option is repowering the steam power plant, which generally involves using an external source of heat to replace or supplement the thermal output of an existing boiler. The external source of heat can be supplied by gas turbines. Gas turbine repowering can improve the thermodynamic performance of the coal fired steam plant and displace some or all of the original coal consumption with natural gas, which would produce lower emissions.
Many gas turbine repowering configurations are possible, but boiler replacement repowering, where gas turbines are installed to convert a coal fired steam cycle unit to full combined-cycle, is considered the most effective. It requires the greatest capital investment and would therefore normally only be considered when the boiler is approaching the end of its useful life, but this high CAPEX can be offset by gains in efficiency and output.
For comparison with the reference design, the repowering of one boiler unit was considered. The resulting generator output of the repowered unit was 432 MW and the net output of the resulting CCGT cycle 1289 MW. To maintain a capacity similar to that of the original, it was assumed that one of the other boiler units is kept in service, with FGD and SCR installed. The repowering option is based on installing three F-Class gas turbines with HRSGs supplying steam to one of the original steam turbine units.
The analysis found that repowering has a relatively low capital cost and results in a significant increase in plant efficiency. But, despite the increased efficiency, the switch from lignite to natural gas significantly raises fuel cost.
Option 4: Site Reuse
Reuse or repowering of the site involves demolishing the plant and completely replacing the power plant equipment. This would typically involve replacing the entire plant with a conventional CCGT arrangement.
To provide a comparison with the boiler replacement repowering described above, the same F-Class gas turbine model was used. Two power blocks each comprising two gas turbines, two HRSGs and one steam turbine produced a net plant output of 1779 MW.
As with the previous repowering example, the site reuse option has a relatively low capital cost and a significant increase in plant efficiency. But, once again, the switch from lignite to natural gas raised fuel cost despite the increased efficiency.
A financial analysis into the relative costs of each option made a high-level comparison, looking at the overall capital cost and costs associated with changes to the plant performance. Other costs, such as operating and maintenance (O&M) and lost revenue during plant modifications, were not considered in the study. The financial analysis was based on the following three major cost components: change in revenue for generated output (expressed as a cost); change in fuel costs; and capital cost of modification.
For the comparison, the revenue and fuel costs were expressed as NPV, based on an assumed operating life of 25 years and a discount rate of 10 per cent. This therefore assumes that the existing plant has a remaining life of 25 years.
The installation of FGD and SCR represented the lowest cost option. This was as expected, since this option generally represents the fewest modifications to the existing plant. However, this is unlikely to give a realistic picture because it is based on the assumption that the plant will operate for a further 25 years without any further remedial work or refurbishment and without any loss in availability.
In reality, any plant in such a condition is likely to have already been modified and is not expected to have opted out under the LCPD regulations. This option is therefore considered as a benchmark for the other options and has been used as the base reference for the financial comparison, with all other costs being shown as additional to this amount.
The boiler replacement options represented the next lowest cost options, although a CFB boiler costs significantly less to install than a pulverised fuel type boiler as it has no need for FGD and SCR, which cuts capital cost and raises output and efficiency. Again, these options assume the steam turbine plant is in good condition and suitable for continued operation.
Should the steam turbine plant also need to be replaced, the subcritical option appears to represent a lower-cost solution than the supercritical option. With a low-cost fuel such as lignite, the fuel savings associated with the improved efficiency would not cancel out additional capital costs associated with the supercritical plant but this might not be the case with more expensive fuels such as black coal.
The highest-cost options are the two repowering options, involving the introduction of gas turbines. Efficiencies are significantly improved but the high cost of gas hikes the overall costs much higher than for the other options. Repowering with gas fuelled plants is therefore the least preferred option for operators, only for consideration where there are major problems with land availability and/or the prevailing planning and permitting processes.
To 2015 and beyond
Although based on a simplified approach and with several general assumptions, the analysis demonstrates that there are various options available for opted-out plants to continue operation beyond 2015.
For the reference model, the study found it was possible to meet IED emissions requirements through all the considered options, although the actual modifications required will be specific for each plant under consideration. Many financial variables will also be specific for each plant, although the current price of gas could make the upgrading of existing coal fired plants financially viable in a significant number of cases.
Plant upgrading appears to be the most cost-effective option. But this assumes the plant is suitable for continued operation for a further 25 years without further major refurbishment work. In reality, any such plant is likely to have already been upgraded and is not expected to have opted out under the LCPD regulations. Of the other options, plant refurbishment appears to offer the best solution, with the CFB boiler upgrade the most financially attractive. Again, the CFB option assumes the steam turbine and associated plant can operate without substantial refurbishment for a further 25 years.
The least attractive options involved switching to natural gas (plant conversion and repowering). This is purely based on current high gas prices on the international market. But carbon pricing and carbon trading could have a major influence, so these options should not be fully ruled out.
The analysis by Parsons Brinckerhoff makes no claim to be definitive, but the clear recommendation is that current power plant operators who have opted-out plants should certainly consider investigating the respective merits of these options for their own plants.
A copy of the full report Continued Operation of ‘Opted-Out’ Large Combustion Plants under the IED, authored by Steve Lloyd and Gary Craigie, can be downloaded at: #regional/uk_europe.aspx
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