Renewed CHP drive
18 Mar 2010
Renewable combined heat and power needs the right investment climate. Patrick Raleigh reports
Schematic view of the 50MW CHP plant being built at the Scottish plant of papermaker Tullis Russell that will reduce its carbon footprint by 72%
Renewable combined heat and power (CHP) facilities - those using renewable fuels, to supply heat for industrial processes in large factories - are a key component of the UK’s low-carbon strategy.
The Government expects to see 10GWe of CHP capacity installed by the end of this year and to be approaching 14GWe by 2015. This compares to an estimated 5.5GWe in 2008, which then accounted for around 7% of the UK’s electricity supply.
To maintain the momentum, the Government is to introduce the Renewable Heat Incentive (RHI) scheme, in April 2011, which will provide financial support for the installation of renewable CHP heating.
Tariff levels have been calculated to bridge the financial gap between the cost of conventional and renewable heat systems. However, industry is concerned over government proposals to abandon grandfathering of the Renewables Obligation Certificate (ROC) subsidies system, which currently pays power generators for every unit of renewable energy they produce.
While contact temperature sensors or probes can influence the temperature of the target object, sometimes even damage the product itself, the non-contact method ensures precision measurements without damaging the target object
Between now and 2013, plant owners can make a one-off choice to move to the RHI, although the precise treatment for biomass/fuel-derived ROCs is yet to be confirmed, said Dr Tim Rotheray, policy manager, Combined Heat & Power Association (CHPA).
CHP schemes that use a renewable energy fuel earn a premium on each MWh of electricity produced under the Renewables Obligation (RO) mechanism. Ofgem estimated this year’s RO buy-out price at £37.19 per megawatt-hour (MWh) - though companies using all the heat from a CHP unit can claim double ROCs.
“The proposal from government as it stands is to divorce heat and electricity generation so that, from 2013, the RO uplift for renewable CHP will be irrevocably scrapped,” explained Rotheray. CHP plant operators, he said, would essentially be driven to the RHI scheme.
Producers would then be entitled to standard incentivisation for power production under ROCs and will then receive incentivisation for heat under the RHI.
“But the two won’t be equivalent,” notes the CHPA expert. “As it stands, ROCs are guaranteed for 20 years.” The length of support as proposed under the RHI, however, varies according to the fuel type used. Support for biogas is proposed to last for 10 years; the maximum duration of incentivisation for any biofuel is 15 years.
The level of support received for CHP plant will be commensurate with production of heat using other forms of generation, according to Rotheray. But he added that this will not really reflect the overall high levels of efficiency delivered by CHP.
The CHPA is in talks with officials at the Department of Energy and Climate Change on the issue and, said Rotheray, will be pushing for operators of CHP plant to receive fair and flexible treatment under the RHI.
Investment issues surrounding ROCs and the RHI were highlighted at a recent CHPA conference by Phil Piddington, head of Cogen Asset Management, the cogeneration division of RWE npower - builder, operator and owner of 16 CHP plants in the UK and Republic of Ireland providing over 2,000 MW of heat and power capacity.
“An appropriate banding treatment is required under the RHI (and RO) to ensure this is not frustrated by ’co-firing’ restrictions,” said Piddington. “Grandfathering of RO rights for committed projects is vital, as projects benefiting from RO support need to be on a level playing field with RHI-based projects when RHI is introduced.”
Grandfathering of RO rights for committed projects is vital, as projects benefiting from RO support need to be on a level playing field with RHI-based projects PE ojects when RHI is introduced from 2011
Piddington cited a current project at RWE npower Renewables, which is working in partnership with papermaker Tullis Russell to supply its plant with steam and electricity from a £200 million, biomass CHP plant at Markinch in Fife. The 50MW unit will replace the existing coal-fired power plant at Tullis Russell, and is scheduled for operation in late 2012.
The “double ROCs” underpin the Tullis Russell project, said the Cogen boss, explaining that renewable CHP already benefits from a Feed-in Tariff, an extra 0.5ROCs, giving 2ROCs/MWh. The project has also received £1 -million, Scottish Regional Selective Assistance grant.
Range of biofuels
The Tullis Russell plant’s on-site production of heat and electricity is currently achieved from a combination of its own coal- and gas-fired cogeneration plant. Operation of the coal-fired plant is to be closed down under Large Combustion Plant Directive regulations and the new biomass plant will secure continuing energy supplies.
The CHP plant will use circulating fluidised bed boiler technology and will be Waste Incineration Directive compliant, allowing use of a wide range of biomass fuels. It will be fuelled on around 400 kilotonnes per annum of used wood and virgin wood sourced from local and national sources. The plant will reduce Tullis Russell’s Markinch site carbon footprint by 72%, helping to reduce annual carbon emissions by 250,000 tonnes.
Finland-based Metso, a supplier of technology and services, will provide the site’s main biomass boiler, while Aker Solutions will project manage construction, provide support services and procure some of the equipment for the 50MW plant under a £115 million contract.
Stephan Lohr, RWE head of biomass, said: “This project is RWE’s largest investment to date in biomass-based power generation and part of our ongoing commitment to invest Euro1 billion per annum in renewable energy. In addition to this project, we are developing plans for a similar biomass plant in Lincolnshire, with an installed capacity of 65MW.”
Timing the key for GSK project
GlaxoSmithKline has recently installed a CHP unit at its Coleford, Gloucestershire site. The facility produces well known drinks brands such as Lucozade and Ribena, with a capacity of 1 billion units a year.
Some years previously, a feasibility study had concluded that the site’s heat load was too low for a gas turbine (GT)-based CHP scheme. However, the project was resurrected in 2007 due to a potentially heavy load increase associated with the development of the site’s infrastructure.
The CHP scheme received the eventual go-ahead in 2008 following the approval of an on-site bottling facility. A formal tendering process awarded Centrax the contract for a 5MW GT-based CHP system as a key element in GSK’s policy to reduce its carbon footprint.
In terms of heat load, the system was required both to ensure reliable supply of steam and to “match site demand for steam with flexibility to follow production,” said Ian Clulow, regional sales manager at Centrax Gas Turbines.
In terms of electricity supply, the target was to reinforce a weak grid connection arising from issues relating to the overhead line supply through the Forest of Dean, noted Clulow. GSK, he added, was also clearly keen to avoid any network outages and interruptions to production.
The heat requirement on site was for 8-20 tonnes/hour of steam at 10 barg, while electrical power demand ranged from 3-12MW using a gas supply rated at 2 barg.
- For the project, Centrax supplied:
- A 501KB7 gas turbine generator set rated at 5MW;
- An auxiliary and supplementary fired heat recovery boiler;
- Water treatment plant;
- Fuel gas compressor;
- Blackstart diesel generator set.
GSK, meanwhile, looked after areas including the civil works, MV connection, a chilling plant and planning and permits on the project.
According to Clulow, the project presented a number of challenges, not least because of the limited space available with the existing building and noise issues arising from the plant’s closeness to residential areas.
The project management team also had to work to strict CDM (construction, design & management) criteria and HSE requirements. Moreover, GSK’s production lines remained operational during the work, while the installation had to be carried out alongside several other construction projects at the site.
In terms of plant monitoring, the Energy Centre was fitted with a SCADA system based on a Centrax in-house generator set monitoring system. This, said Clulow, was expanded to include boiler, gas compressor, water treatment plant, diesel generator and MV systems.
The monitoring system was designed to handle inputs from an independent and dedicated plant operating system and outputs from GSK’s central control system. Another important component was a remote diagnostics link to the Centrax HQ.
