Yet a beacon of green energy is exactly what Tilbury power station has become. In December 2011, Tilbury B, a 1062 MW coal-fired plant opened in 1967, was successfully converted to a 742 MW biomass plant. Tilbury thus became the largest biomass burning power generation facility in the world, beating the previous coal-to-biomass record holder, GDF Suez’s 180 MW Rodenhuize plant in Belgium, by some distance.
Rather than invest in flue gas desulphurisation and other emissions reduction measures, owner RWE npower opted Tilbury out of the European Commission’s Large Combustion Plant Directive (LCPD) in 2007, restricting the plant to a further 20,000 operating hours between 2008 and 2015.
Having conducted trials in September 2010 to prove the technical feasibility of burning biomass exclusively in a coal unit, RWE npower took the decision to convert the plant’s three 350 MW units to biomass two months later.
Tilbury B generated its last kilowatt hour from coal on 4 March 2011. In the nine months between coal and biomass generation, Tilbury’s engineering manager Dave Dyson worked frantically to ensure the plant can burn 2.3 million tonnes of wood pellets, enough for the remaining 8000 hours, by 31 March 2013, when the number of Renewable Obligation Certificates (ROCs) allocated to biomass conversion plants reduces from 1.5 to 1.
A Financially Bold Decision
Dyson says the decision to convert Tilbury B to biomass was brave. ‘The cost of the conversion is in the tens of millions, but the value at risk is in the hundreds of millions,’ he says.
‘We had fixed-price coal contracts and forward power prices set. Virtually all the power produced from coal was sold forward. We had to unwind all those contracts and that secure income. Instead we’ve taken on contracts for 2.3 million tonnes of wood without having proven we can use it.’
Fuel supply is the critical factor for coal plants to switch to biomass (Source: Drax)
Burning coal, Tilbury would operate near baseload in the winter months of December, January and February, two-shifting in spring and autumn, with often no units running for weeks at a time in summer. Over the course of a year, this would amount to around 4500 hours. In order to use up the 8000 hours by 31 March next year and avoid a financial hit of around £20/MWh (US$31.14/MWh), however, Tilbury will run at sub-optimal periods, that is, when the price of electricity is low.
‘Dark spreads [the theoretical gross income produced by the sale of a unit of electricity, less the cost of the fuel to produce the electricity] could be vastly lower than under a purely commercially driven aspect, but we need to burn the hours up,’ says Dyson. ‘At times our revenues from the power price may be barely above the ROC price.’
Tilbury’s Major Advantage
The ‘design life’ of the conversion may be only 8000 hours, but surprisingly little was spent on converting Tilbury from coal to biomass. The UK’s Drax coal power plant, for example, spent £80 million ($125 million) on new biomass burners and fuel conveying and filtering equipment, plus a railway upgrade which will enable the plant to co-fire up to 10% biomass, or around one million tonnes per year.
Tilbury has one distinct advantage for biomass conversion: its own jetty on the river Thames, which can accommodate Panamax class vessels of up to 60,000 tonnes and saves an estimated £30 million ($47 million) per year in rail freight costs. Dyson’s biggest challenge is dust and most of the investment was spent on equipment that mitigates dustiness, including two new Kone ship unloaders, as the existing ones were too abrasive; an elutriator, or particle separator; and a dedicated pipeline which pneumatically conveys dust to the furnace.
Tilbury’s jetty on the river Thames, which can accommodate Panamax class vessels of up to 60,000 tonnes, saves an estimated £30 million ($47 million) per year in rail freight costs. (Source: RWE npower)
While coal is typically stored outdoors in huge heaps, biomass needs to be kept dry. Unlike Drax and other biomass co-firing coal plants, there is no virtually no biomass stored onsite at Tilbury. Instead the wood pellets arrive on a vessel and are unloaded and burned during the course of a week. Once the ship’s payload is empty and it departs, another vessel arrives within hours and the process starts again.
Dyson explains: ‘We store only enough onsite to see through the few hours where there is no ship on the jetty, around six hours’ margin, so we have to have a slick, just-in-time shipping turnaround. I suspect the fuel handling team will have significantly less hair by April 2013!’
Impact on Efficiency and Emissions
Due to the lower calorific content and bulk density of biomass versus coal, Tilbury’s generation capacity is reduced by around 30% to 742 MW, which in turn reduces the thermal efficiency of the plant to 35.3% from 37%.
Physical changes to the combustion system are more tweaks than transformation; small modifications have been made to the fuel mills, feeders and burners. When biomass is put through the grinder, it splinters and chips, not breaking down into a fine dust like coal. Combined with the lower calorific value, this causes the burners to respond differently.
Therefore, the plant’s low NOx burners have been modified to ensure a more stable flame and to minimise the required amount of support fuel, tall oil. This is achieved by creating a fuel mixing zone (and therefore a flame) nearer to the front of the burner.
Corrosion is also a challenge for biomass conversions. The high chlorine content will corrode and diminish the existing boiler fuel pipes. As operation is limited to 8000 hours, however, this is not expected to present a major problem.
Based on the results of the biomass trial in September 2010, Dyson expects NOx emissions to fall from 480 mg/m
3 to 220 mg/m
3, SOx to fall from 800 mg/m
3 to 200 mg/m
3, and the volume of ash produced from 40,000 tonnes/TWh to 4000 tonnes/TWh. Lifecycle carbon dioxide emissions are predicted fall from 0.81 million tonnes/TWh to 0.11-0.18 million tonnes/TWh, a 78%-87% reduction.
Tilbury & Biomass – a One-off?
As things stand, Tilbury B will close once the 8000 hours have been used up. In July 2010, RWE npower submitted an environmental assessment scoping report to the UK Infrastructure Planning Commission for Tilbury C, a proposed 2000 MW combined cycle gas turbine and 400 MW open cycle gas turbine plant. This replaced RWE’s previous proposal to build a 1600 MW supercritical coal plant with carbon capture and storage (CCS).
RWE, however, is also considering the possibility of re-permitting and re-consenting Tilbury B to enable it to continue to operate as a dedicated biomass plant beyond the LCPD limit. ‘Phase II would be a completely different proposition and we won’t make a decision until well into the second quarter of 2012,’ explains Dyson.
‘It would require a vast upgrade to meet more stringent NOx and SOx emissions standards and we still have to work out if biomass is commercially viable with just one ROC. Phase II totally depends on plant and environmental performance of Phase I.’
Dyson says the critical aspect of whether other coal plants in the UK and elsewhere can convert to biomass is fuel supply. ‘In theory there is no technical reason why other coal plants couldn’t replicate Tilbury but whether they could be as much of a commercial success is doubtful. The big question concerns fuel supply logistics. Biomass is more expensive than coal and trying to get enough of it to an inland power station is a challenge. Most European plants will have the same problem.’
Sourcing Fuel: The Central Issue
Around 30% of Tilbury B’s biomass is sourced from RWE’s own 750,000 tonnes/year wood pelletisation plant in the US city of Waycross, Georgia; a further 50% will come from the US and Canada. The remaining 20% comes from Europe, either the Baltic States or southern Europe. All fuel is debarked softwood pellets.
Dyson believes it is unlikely RWE will develop a similar biomass facility in the UK. ‘Sustainability is an issue in Europe. It doesn’t have the same scale as the US. If we could source biomass sustainably in the UK we would do so, but there are no obvious opportunities to develop that at present.’
According to consultancy firm McKinsey, however, there should be no shortage of sustainable biomass. In a 2010 report, Sustainable Bioenergy, McKinsey concluded there is enough land available for biomass to exceed currently mandated consumption levels by a factor of two by 2020, even after all other needs were met, i.e. food and feed crops; domestic firewood; projected demand from the forest products industry; no deforestation; and only environmentally sustainable use of virgin land.
Biomass is more expensive than coal and getting it to inland plants can be challenging (Source: Drax)
Furthermore, the market is responding to greater demand for biomass. In November 2011, the Dutch energy exchange APX-ENDEX launched the world’s first biomass exchange. At present the Amsterdam-based exchange trades only non-cleared products where the physical settlement is arranged bilaterally by the counterparties, but later this year it will offer clearing services for wood pellet contracts, providing financial security to market participants.
The exchange has been developed in co-operation with the Port of Rotterdam, which is expecting a boom in biomass handling due to the Dutch government’s Energy Report 2011 that will make biomass co-firing at coal plants mandatory. According to Koen Overtoom, commercial director of the Port of Amsterdam, the Netherlands, Germany, Scandinavia and the UK will require 15 million tonnes per year of biomass by 2020. Of that figure, Dutch ports will handle 13.5 million tonnes, up from 1.5 million tonnes at present, with the Port of Amsterdam alone accounting for 6 million tonnes.
Drax – A Totally Different Conversion Proposition
At 3960 MW, Drax is the second largest power plant in Europe. Unlike Tilbury, Drax complied with the LCPD, thus allowing it to run without restriction. In 2016, however, another European regulation, the Industrial Emissions Directive (IED), will force coal plants to install selective catalytic reduction (SCR), which removes NOx from flue gases.
The cost of IED compliance for each of the plant’s six 660 MW coal units would probably run to hundreds of millions of pounds. Throw in the UK Treasury’s carbon floor price and full auctioning of Phase III European Union Emissions Trading Scheme (EU ETS) carbon permits and one can see why Drax’s production director Peter Emery is considering other fuel options.
Drax currently co-fires up to 8% biomass, burning approximately 1.2 million tonnes in 2011, mostly wood chips, straw pellets, oat and sunflower seed husks, and it is now considering converting the entire plant to biomass. ‘When it became clear that UK government policy was not just pricing carbon into power production via the EU ETS but also the carbon floor price, we felt we had to do something radical,’ says Emery.
Drax currently co-fires 8% biomass - mostly wood chips, straw pellets and oat and sunflower seed husks (Source: Drax)
‘If we can’t compete in a world post-2016 with a very high carbon price we would opt out of the IED. Plants like Tilbury which opted out of the LCPD may just close rather than convert to biomass. Plants that opted in may find that the economics stack up. So biomass will enable us to be competitive and enable us to develop the business.’
Drax is converting one of its 660 MW units to biomass. If it was to convert fully, says Emery, the capacity of each unit would be reduced to around 500 MW, each burning 2.5-3 million tonnes per year.
Sourcing this volume of biomass would be a major challenge: Drax is unable to source enough biomass at the right price in order to co-fire the permitted 12.5% limit, let alone a 100% conversion.
‘The biomass market isn’t there, and sourcing it is not as simple as having a group of traders with telephones,’ Emery explains. ‘We’re having to negotiate deals to build pellet plants and set up shipping contracts, or encourage British farmers to grow miscanthus, willow or eucalyptus. Could we get hold of 15-18 million tonnes of biomass tomorrow? Yes. But biomass that has been harvested, pelleted and processed for power plants? Clearly not. Our challenge is to develop the supply chain, which may take 20-30 years.’
Drax wants the UK government to think again about reducing the number of ROCs allocated to biomass conversions. ‘There’s a massive potential for biomass to be industrialised in Britain and the ROCs would help us to develop the infrastructure. If the government commits to a firm biomass policy over the next 15-20 years, the rest will follow.’
Conversion = Addiction to Subsidy?
Based on 2010 generation of 26.4 TWh at an average power price of £51.60/MWh ($80.33) and burning 15 million tonnes of biomass at £80-£100/tonne ($124-$156), Drax could expect revenues (including one ROC) to comfortably outstrip the higher fuel costs by hundreds of millions, even with the anticipated 25% drop in output. Add in exemptions from the EU ETS and the carbon floor price, and biomass conversion looks attractive.
But converting to 100% biomass would mean Drax is reliant on subsidy to be commercially viable. Is it fair to ask British taxpayers to keep Drax alive this way? ‘This is about starting a brand new industry,’ says Emery. ‘The idea is not to generate super profits versus coal, but to give an adequate return on investment for burning biomass. The government has got renewables targets to hit, it wants to reduce CO
2, and the beauty of co-firing and unit conversion is that it’s cheap. It’s broadly half the cost of offshore wind and broadly in parity with onshore wind, but biomass is also fully dispatchable. The taxpayer would think that’s very fair.’
Is Drax doomed without biomass? ‘We are not doomed, but the direction of government policy means that coal-fired generation in its current guise is doomed. Biomass gives us a route to market with cost-effective low-carbon generation.’
As
REW goes to press, German utility E.ON has announced that it plans to convert one of two 500 MW units at its coal-fired Ironbridge power plant in the UK to biomass, with the option to convert the second unit at a later date. The utility has applied for planning permission to build a fuel store on-site. The plant chose to opt out of the LCPD, and will open in 2013.
