When Canadian IPP Bayside Power decided to repower its Courtenay Bay oil fired power plant, it was not just attracted by the usual efficiency and environmental gains that repowering offers, but also by the deregulated merchant power markets of the USA.
In August 1998, Canadian independent power producer (IPP) Bayside Power awarded the turnkey contract for the repowering of its Courtenay Bay generating station in St John to ABB Alstom Power. Within two years, the oil-fired plant will be a high efficiency natural gas fired combined cycle unit selling power to the deregulated merchant power markets of the north-eastern USA.
Bayside Power, a subsidiary of Westcoast Energy Inc. of Vancouver, British Columbia, is developing the repowering project under contract to NB Power, the New Brunswick utility that owns the Courtenay plant. The project, Canada’s first major combined cycle repowering project, is due to be commissioned in late 2000 or early 2001.
The conversion of Unit 3 of the New Brunswick plant from residual fuel oil to natural gas operation will involve the replacement of the existing boiler with a gas turbine, an electrical generator and a heat recovery steam generator. Unit 3’s existing steam turbine will remain in place and will be incorporated in the combined cycle. The repowering will increase plant output from 100 MW to 265 MW and will increase thermal efficiency to 56 per cent. Emissions from the plant will also be substantially reduced.
ABB Alstom Power will supply all equipment for the repowering, including a GT24 advanced gas turbine and plant control systems. The Brussels-based engineering company will provide all the engineering, procurement and construction work as well as the associated distribution systems and the balance of plant equipment.
ABB Alstom Power will also be responsible for the complete installation and commissioning of the new unit. When complete, the repowered plant will supply electricity to New Brunswick during the winter months and to the deregulated US power markets in the summer.
The availability of natural gas supplies from the Sable Offshore Energy Project development encouraged NB Power to examine repowering options for several of its power plants. But as competition in the USA developed, the utility also saw new opportunities, and like many US utilities, began to re-evaluate its generating assets.
The New England power market was opened to competition in July 1997 when Nepool, the New England Power Pool, was replaced by an Independent System Operator, ISO New England, following orders from the US Federal Energy Regulatory Commission. Whereas Nepool involved monopoly utilities sharing their resources, ISO New England introduced markets for generation products, such as energy, capacity and ancillary services. To facilitate competition, several New England states passed legislation requiring utilities to divest generation capacity. The market has since seen a large number of new entrants and power marketers, and has opened opportunities for Canadian producers.
Structural market changes have also occurred in New Brunswick, Canada. NB Power has taken steps to allow third party suppliers to access its transmission system, opening up possibilities for independent generators.
To be competitive in these deregulating markets, NB Power realised that it would need to enhance the efficiency, flexibility and availability of its units, manage fuel risks, and reduce environmental impact. It decided that repowering an existing plant to a combined cycle unit would help it to achieve this with a relatively low capital investment. In addition, repowering can extend the operational life of a steam power plant for several decades, and has several other benefits (see box).
Recognising the opportunities presented by repowering Unit 3 of the Courtenay power plant, NB Power requested proposals from potential developers for the project in early 1997. Bayside Power won the project, and in mid-1997 signed a letter of intent with NB Power.
Under contract to Bayside Power, ABB Alstom Power will repower Unit 3 of the power plant with a 183 MW GT24 gas turbine, a heat recovery steam generator (HRSG) with provision for duct firing, and the existing 100 MW steam turbine generator of Unit 3. The gas turbine generator and the HRSG will be installed in their own enclosure to the north east of the existing power plant building on land leased by Bayside Power from NB Power. Provisions will also be made to accommodate a second gas turbine generator and HRSG in the future.
The project will allow Courtenay Bay station’s Unit 3 oil-fired boiler and also its Unit 2 – an oil-fired boiler and steam turbine generator – to be shut down, representing 116 MW of capacity in total. Units 1 and 4 of the Courtenay plant will remain unaffected by the repowering project.
Natural gas for the repowered unit will be supplied by a new pipeline, constructed by Maritimes and Northeast Pipeline, that carries gas from the Sable Offshore Energy Project to parts of New Brunswick and New England. Some fuel gas compression will be required on site to increase the supply pressure near the gas turbine.
Under normal operating conditions, the repowered unit will operate as a baseload power plant in combined cycle mode. The steam turbine generator will in this case supply around 70-80 MW of power unless duct firing is used in the HRSG, which would allow steam turbine generator output to increase to 100 MWe. Actual capacity and generation will vary considerably, though, depending on the time of year and the electrical load required. The repowered plant’s NOx emissions will be 25 vppmd.
NB Power will have exclusive use of the power generated by the unit during the winter months from November to March, selling power to the local market. In the summer, Bayside Power will contract for transmission services from NB Power, and sell power into ISO New England or to NB Power.
The Courtenay bay project is the first repowering project in Canada being undertaken using a GT24 gas turbine. Repowering with the 50 Hz GT26 turbine is currently being carried out at Senoko power station in Singapore, and has also been successfully implemented at the RDK4S plant in Germany.
The GT24 is ABB Alstom Power’s latest and most advanced heavy duty gas turbine technology. The design incorporates a single-shaft rotor welded from forged discs and rings with two-bearing support, ABB Alstom Power’s sequential combustion design, an EV burner in an annular combustor with a SEV burner.
The GT24 subsonic compressor consists of 22 stages with controlled diffusion airfoils, which provide a good surge margin and optimise the behaviour of the compressor at part load. Part load efficiency is further improved by providing three rows of variable guide vanes for reducing the air flow at gas turbine start-up and during part load operation.
The turbine section consists of five stages: a single, high pressure stage after the first EV (environmental) combustor, and four low pressure stages after the SEV burner. The turbine blading is made out of single crystal, directionally solidified and conventional materials. An advanced blade cooling concept helps to minimise the cooling air needed for protecting the turbine blading from the hot temperatures of the combustion gases. The first stages use a combination of film, impingement and convective cooling.
The sequential combustion system is based on the concept of two annular combustors in the gas turbine, splitting the combustion process into two stages. This ‘reheat’ design allows the development of an optimum exhaust temperature of 640°C, which can be maintained over a wide part load range. The result is a higher gas turbine efficiency and higher power density compared to other combustion turbines.
The compressor feeds combustion air into the EV burners of the first annular combustor, where the air is mixed with natural gas creating a homogeneous lean fuel/air mixture. The mixture ignites into a single low temperature premixed flame within the combustion zone. Hot gases exiting the combustor drive a single stage, high pressure turbine, before entering the Sequential EV (SEV) annular combustor.
More fuel is injected into the second burner set and ignites spontaneously in the SEV, thereby reheating the air before expanding it further in a four-stage low pressure turbine.
Hot gases exit the gas turbine exhaust at 640°C and are used in the triple-pressure HRSG to provide condensate and feedwater preheating for the steam cycle. To enhance flexibility, the HRSG has natural gas-fuelled duct firing for use at times of high electric demand. The gas temperature at the HRSG inlet is 800°C.
The guaranteed live steam flow and the guaranteed live steam pressure produced by the high pressure (HP) section of the HRSG are 85.3 kg/s and 537.8°C respectively based on a live steam pressure of 125.1 bar upstream of the steam turbine stop valves.
The steam turbine consists of three sections: a high pressure turbine stage, an intermediate pressure turbine stage (IP), and a low pressure turbine stage (LP). Steam exiting from the HP stage is reheated to 537.8°C before it enters the IP stage. The steam exiting the IP stage enters directly into the LP stage. The steam system is also equipped with HP and LP bypass systems for bypassing the existing steam turbine.
The combined cycle power block will normally operate as a base load unit, but may be required to operate under varying load conditions depending on demand, particularly during summer months when Bayside will market power generated into the US deregulated markets. The operating conditions could vary between 75 per cent and 100 per cent of base load.
In addition, the power block will need to respond quickly and smoothly to changes in demand, particularly during the summer months when it will sell into the more volatile competitive market of the northeast USA. If the steam turbine cannot follow the swings in demand adequately, the HRSG duct firing will be started to make up any shortfalls.