Operating power plants in a competitive environment is a challenging business. The natural environment can sometimes make life harder, however, especially when temperatures can reach as low as -40°C.
In 1999, Canadian energy company TransAlta started construction of a new cogeneration facility in northern Alberta, Canada. Just two years later, the new plant started operating, supplying electricity to the Alberta grid and process steam to an oil sands refining facility near Fort McMurray, Alberta.
The northerly location of the new cogeneration facility – named Poplar Creek – means that the plant must be able to operate in temperatures ranging from -45°C to +30°C while still meeting emissions regulations. The plant must also be reliable and operate competitively to enable TransAlta to sell electricity into the Alberta wholesale market and to maintain secure supplies of steam to the oil sands facility, which is owned by Canada’s Suncor Energy.
The Poplar Creek plant is designed to operate reliably at temperatures ranging from -45°C to +30°C
The 350 MW cogeneration plant consists of two natural gas fired combined cycle units, with equipment supplied by Alstom and Nooter Eriksen. It was constructed in phases and is fully operated and maintained by TransAlta as part of the company’s international portfolio of power plants.
The Poplar Creek plant generates steam for the Suncor oil sands facility
Poplar Creek was constructed following an agreement between TransAlta and Suncor Energy signed in 1999 for the supply of energy to Suncor’s oil sands facility. The facility, located 22 km north of Fort McMurray, is Suncor’s main oil sands mining and upgrade facility, and opened in 1967 as the world’s first commercial scale oil sands processing site.
Oil sands are a form of hydrocarbon reserve – in its crude form it is made of sand, water and bitumen. The bitumen must be extracted and separated from the sand and water, and then upgraded into a variety of petroleum products.
Canada’s oil sands reserves are concentrated in the Athabasca basin and according to the Oil & Gas Journal, represent the world’s second largest reserves of oil after Saudi Arabia. The Canadian government estimates that recoverable reserves stand at 315 billion barrels, of which 175 billion barrels are currently economically recoverable.
Under its current leases, Suncor’s reserves stand at 13 billion barrels of bitumen – equivalent to over 10 billion barrels of oil. Current production levels stand at around 225 000 barrels per day, and the company has ambitious investment plans to double this by 2012.
The Poplar Creek cogeneration plant houses two Alstom GT11N2 gas turbine generator units
Suncor’s Fort McMurray site stands at the heart of this planned expansion, and in March 1999, it contracted TransAlta to supply the long-term power and energy needs of the site. TransAlta therefore embarked on developing the $315 million Poplar Creek power station.
In May 1999, TransAlta announced that it had contracted Alstom to supply two gas turbines, two steam turbines and associated equipment for the Poplar Creek plant. It also signed a contract with Fluor Daniel and Fluor Constructors Canada Ltd. for the engineering, procurement and construction of the plant. Fluor Daniel performed engineering and procurement services for the project, while Fluor Constructors Canada Ltd. and Bechtel Canada Co. carried out construction management and construction services.
The Poplar Creek combined cycle cogeneration plant consists of two gas turbine units, each comprising an Alstom GT11N2 gas turbine generator unit, a heat recovery steam generator (HRSG) and a 75 MW steam turbine.
Each GT11N2 gas turbine produces an output of 117 MW and has a rated electrical efficiency of 33.9 per cent. It was chosen by TransAlta for its rugged design and reliability, according to Joseph Hobi, Alstom project manager, and Martin Schuetz, Alstom product manager.
The GT11N2 gas turbine is composed of a solid welded rotor and a four-stage turbine section, the first two stages of which are air cooled. The turbine inlet temperature is 1085°C. The 14-stage compressor produces a pressure ratio of 15.1:1, while the first three stages of the compressor are equipped with variable compressor guide vanes to adjust air flow at start up and to provide high efficiency and low emissions at part load. The machine is equipped with an Alstom EV burner combustor, comprising 36 burners designed to optimize fuel-air mix and achieve good flame stability. On natural gas, lowest achievable NOx emissions are less than 25 vppm.
The two HRSG units were supplied by Nooter Eriksen, and are both single pressure natural circulation units. They are equipped with duct burners and produce 181 400 kg/h of steam unfired and 453 600 kg/hr of steam when fired. Steam is fed to the steam turbines as well as into the site’s main steam system.
One of the main challenges for the project partners was to design a plant that would operate reliably in a wide range of temperatures; while the higher end of the guaranteed temperature scale (+35°C) was not too much of a problem, say Hobi and Schuetz, the lower end of the scale (-42°C) presented a challenge, especially as the plant is not able to exceed NOxemissions of 25 ppm.
“The region is extremely cold in the winter months and has moderate temperatures in the summer,” explains Hobi, “Yet the plant must be able to produce power and steam at all times.” Between the months of December and March, says Schuetz, temperatures are permanently below zero.
The GT11N2 gas turbine produces an output of 117 MW
The winter temperatures can present a challenge to the operator of the plant because it is difficult to achieve stabilized combustion and still meet the NOx requirements at temperatures of -10°C or lower, says Schuetz. “At temperatures lower than -10°C, flame conditions in the combustor become very unstable and are difficult to control,” he explains.
The term used for these unstable flame conditions in a combustor is ‘pulsations’. Pulsations can lead to trips and protective load shedding, and therefore have implications for the long-term performance of both the plant and equipment.
Pulsation of the flame can be overcome through a combination of design an operational factors, says Hobi. At Poplar Creek, an air preheater is used to heat the gas turbine inlet air to above -10°C, helping to alleviate the problems associated with extreme cold temperatures. In addition, the operator can adjust operational procedures when temperatures are low. Poplar Creek uses a damping system in its combustor to damp the vibrations caused by pulsations.
At low temperatures, the mixture of air and fuel entering the gas turbine at Poplar Creek is adjusted to help stabilize the flame in the combustor and eliminate pulsations. “The operator runs a richer mixture in terms of fuel,” says Hobi, “But then NOx emissions tend to be higher so it is a case of finding the right balance.” Emissions of NOx are not allowed to exceed 25 ppm, and a permanent NOx monitoring system is required at the plant.
The cold temperatures can have a benefit, explains Schuetz: at cold temperatures, the gas turbine output increases. In theory, at temperatures of -30°C, the output of the 117 MW GT11N2 gas turbine could reach as much as 140 MW. However, the need to meet NOx requirements through the use of the air preheater prevent such increases, and the maximum output of the turbines is likely to reach just 120 MW.
The first unit at Poplar Creek was commissioned in simple cycle in March 2000, followed by the second unit three months later. The steam cycle was completed with the addition of the heat recovery boilers and steam turbines in the following months, and the plant entered commercial operation in combined cycle mode in spring 2001.
According to Alstom, the Poplar Creek power plant has now been operating reliably for over a year, and is one of the highest revenue-generating power plants in TransAlta’s portfolio.
TransAlta figures for the first quarter 2002 show that the availability of the plant was 96.8 per cent, and that its electricity sales of 716 GWh netted the company revenues of $30.5 million. Plant availability for the same period in 2003 showed an improvement, allowing electricity sales through long term contracts and merchant activity to increase to 751 GWh, and revenues to rise to $50.4 million.