General Electric is to build a 500MW gas-fired power station at Baglan Bay in South Wales that could become the model for baseload generating plants over the next two decades.
The unit at the Baglan Energy Park will be the first commercial application of the US manufacturer’s H system power plant. It is designed to achieve a new threshold of generating efficiency – 60% compared with 58% for the most efficient combined-cycle gas turbine (CCGT) plant.
The 60% target has long been seen as the `four-minute mile’ of the power generation industry and, given that fuel is the largest lifetime cost of a CCGT, could translate into a saving of £10m-£13m over the life of a 400MW- 500MW plant.
The H system achieves this benchmark chiefly through the use of steam cooling, which enables it to operate at a temperature 100 degrees C above that of existing turbines, and has the additional benefit of reducing emissions of nitrous oxide and carbon dioxide.
It was for these reasons – and the impact on local regeneration and employment – that the government granted consent to the Baglan project in April last year, even though it did not meet the criteria of the stricter policy on consents for gas-fired projects. Building is due to start in the next two months.
GE may be leading the field publicly in the development of a unit that will achieve the 60% efficiency target, but the other big turbine manufacturers are also on the case.
Japan’s Mitsubishi Heavy Industries has unveiled its own 60% unit, while Siemens and Alstom Power – which inherited the heavy gas turbine business of ABB after Alstom bought their joint venture on May 11 – both have developments under way. Siemens is expected to make an announcement at the end of the year.
Jim Thompson, director of marketing for the gas turbine segment of Alstom Power, confirms that they are working on higher-efficiency turbines.
He adds that the steam cooling option being developed by GE is a step change for gas turbine technology. It means building baseload generating capacity in big blocks of about 500MW, because the cooling system does not lend itself to operation at reduced power, or being switched on and off within a 24-hour cycle.
He says it is uncertain how well the steam-cooled units will match demand for new plant in markets where much of the base load requirement is met by ageing coal-fired or nuclear plants.
`I think the jury is out on that. You’re talking about a machine that is very large, and the second question is operating flexibility – they won’t be as capable of load-following as the current class of turbines.’
So while Alstom is looking at steam cooling, it is also examining alternatives such as improving the efficiency of its latest GT24 and GT26 units, currently around 58%, which use sequential two-stage combustion, unlike other units on the market.
Thompson says the two-stage system allows the turbine to maintain high efficiency on part load and adds: `Since this machine is still in the early years of its product life, we believe it has further potential for even higher efficiencies.’
The introduction of new electricity trading arrangements in November should, in theory, make the UK a fertile market for such higher-efficiency technology.
The new arrangements will replace the electricity pool with a more competitive system of bilateral contracts, a futures market and spot market, which the government expects to produce a 10% overall cut in electricity prices.
Under this sort of pressure, generators might be expected to jump at new technology that could give them a competitive edge. However, the big non-nuclear UK generators – National Power, PowerGen and TXU Power (formerly Eastern Group) – will view any new developments with caution, given the chequered history of `leading edge’ gas turbine technology in this country.
Since the introduction of gas-fired generation over the past decade, technical problems have led to some extended delays in commissioning new plants, long outages, and claims for liquidated damages against contractors totalling more than £100m.
GE’s 9F series was probably the worst culprit, with unexpected vibration causing turbine blades to crack on National Power’s 680MW plant at Little Barford and others. General Electric has not disclosed how much this cost to solve, but it included flying one of the turbines to the US and back.
That experience explains why GE – which insists it has no ambitions to become a power station operator – is building the Baglan Bay plant itself, and will operate it until the H series has proven its reliability.
Siemens also had blade-cracking problems with its V64.3A units at TXU’s 390MW King’s Lynn plant. And the latest innovative generating technology to run into difficulties has been Rolls-Royce Power’s Trent unit, adapted from the company’s successful aeroengine of the same name.
`The combustors were shaking themselves to bits,’ says an industry source, `although I think they are now getting on top of the problem.’
John Curran, technology development manager at TXU Power, says any generator contemplating constructing a new plant with a `next-generation’ technology will have to balance the gains on offer against the probable loss of generating time. `There will always be a trade-off between availability and efficiency.’ He adds: `If it were my money, I don’t think I’d go for leading-edge technology.’
Curran points to TXU Power’s existing portfolio of three gas-fired plants (one of which is still under construction at Shotton) and says the oldest, a 240MW unit at Peterborough, is a good example. `Peterborough, which uses tried and trusted plant – just under 50% efficiency – has had fantastic availability.’
No dash for gas
Thompson at Alstom Power concurs that there is unlikely to be any sudden dash for next-generation technology. `We think the market for the current class of machines – the 9Fs and the GT26s – will be very strong for the forseeable future.’
He believes the next generation of turbines will make an impact in the next 5-10 years.
Andrew Nind, managing consultant at energy adviser Caminus, says the impact of higher-efficiency technology will depend on what happens to the `other costs of generation for new plant’.
There is unlikely to be a `dash for gas’ when the moratorium on such projects is lifted in November because of the existing excess capacity. But Nind believes CCGTs will progressively dominate the UK generating market and that future electricity prices will be determined by the `entry level’ cost of new gas-fired plants.
The big issue is the price of fuel, which is proportionately much greater for gas-fired plants than any other form of generation. As long as gas prices remain reasonably low, there will be no great incentive for generators to take on the technology risk.
However, should they escalate sharply over the next five years, those additional two percentage points of efficiency will suddenly take on a lot more significance – particularly if by that time General Electric and others have ironed out the inevitable teething problems at Baglan Bay and other demonstration plants.
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