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At the 14th Annual Electric Power Show in Baltimore in May, Mark Crisson, President & CEO of the American Public Power Association, led off the keynote session. His overarching theme: Shaping the future through innovation.
“The industry has seen more changes in the last decade than in the last 100 years,” he said, “in terms of generation, delivery and customers; and the biggest challenges are reliability, affordability and environmental responsibility.” He cited three areas of future innovation: Materials, environmental controls and consumer technology.
Crisson stressed the importance of concrete maintenance in power facilities, and the use of embedded sensors, robotic inspection and fiber optic strain gauges to perform nondestructive testing. He also cited the application of extruded Inconel piping that could withstand 5,000 psi and 1,400°F; powder metallurgy processing; and the electrocoagulation removal of total suspended solids, hardness and heavy metals.
He was followed by Howard Gruenspecht, acting administrator, U.S. Energy Information Administration, who reviewed the 2012 Annual Energy Outlook. Assuming current laws remain unchanged, U.S. energy consumption will grow by 23% from 2010 to 2035, while the annual growth rate will slow, he said, reflecting an extended economic recovery and increasing energy efficiency in end-use applications.
The electricity mix will gradually shift to lower carbon options, led by growth in renewables and natural gas; and non-hydro renewable sources will more than double between 2010 and 2035, fromless than 200 billion kWh/yr to 450 billion kWh/yr.
U.S. dry gas resources will rise from about 1,900 trillion cubic feet of proved reserves and unproved shale gas in 2010 to 2,214 Tcf in 2012. Shale gas will offset declines in other U.S. natural gas production, from a 23% share in 2010 to a 49% share in 2035. The Henry Hub spot price of gas is projected to gradually rise from $2.36 per million Btu today to around $7.00 per million Btu in 2035. In general, the electricity mix will shift to lower-carbon options, led by growth in renewables and natural gas.
Operating costs for existing coal and gas plants will depend on the value placed on carbon dioxide emissions. For example, at $20 per ton CO2, the operating cost of a natural gas plant at $3.00 per million Btu would be equivalent to the operating cost of a coal plant at $2.00 per million Btu (Figure). If the value of CO2 rises to near $60 per ton, natural gas at $7.00 would be equivalent to coal at $2.00. Environmental operating costs and retrofit costs for pollution controls at existing coalfired plants can also raise the bar for their continued operation.
A conference session—Trends in Large Frame Gas Turbine Technology—described each OEM’s new technology, covering heat rate, efficiency, operational flexibility and reliability.
The opening paper, by Sasha Savic, product manager at Alstom, focused on the GT24. It delivers 230 MW at 40% efficiency, he said, and the corresponding CCPP can achieve more than 700 MWgross output in a 2-on-1 configuration.
GT24 turbine validation was done in steps, said Savic. As a first step the turbine internal cooling schemes and their internal heat transfer were validated in an in-house facility using Perspex models and a thermo-sensitive liquid crystal measurement technique. The second step was done during two engine test campaigns in the GT26 Test Power Plant. The first validated hot gas parts; the second validated the LP Turbine performance characteristics over the entire range of operation conditions. .
Compressor validation was done at the GT26 power plant. To gain a full compressor map over the entire speed, ambient temperature and pressure ratio range, a 22-stage, scaled-rig was built and tested. “Compressor mapping was carried out up to the surge limit, beyond the GT24 operating line requirements,” said Savic.
Burner validation measured and analyzed mixing and emission behavior, flame stability limits and acoustic behavior. Out of the single burner test rig different burner fuel configurations were selected for full-engine tests at Alstom’s Birr, Switzerland power plant.
Next up, Carlos Koeneke, VP project engineering and quality assurance, Mitsubishi Power Systems, updated validation of the M501J. First fire of the M501J took place in February 2011 at the T-Point Validation Plant in Takasago, Japan.
“The J gas turbines operate with a record turbine inlet temperature of 1,600°C,” said Koeneke. Long term validation of the first M501J under demand conditions started in July 2011. To date, the unit has accumulated in excess of 5,300 actual operating hours and 62 starts.
Testing of theM501J was done while connected to the grid, which imposes a rotating speed that is dictated by the grid frequency. “Testing a prototype off the grid allows for adjustments of the operating speed to confirm ‘under’ and ‘over’ frequency characteristics of the new engine as well as compressor surge margins,” said Koeneke.
The first of six M501Js for a Japanese project was already delivered; manufacturing of the remaining units, to be installed in a single shaft combined cycle configuration, is ongoing. An additional ten M501J units have been sold in Korea.
Other presentations included Siemens’ SGT6-5000F and SGT5-8000H by Pratyush Nag, director engineering H-Class GT Product LineManagement.
Nag provided an overview of Siemens’ large-scale gas turbine portfolio.He said 313 SFT6-5000F units are under contract and 238 units in operation. Reliability is at a level greater than 98%; availability is greater than 92.6%. Nag reviewed service capabilities of the SGT-8000H, claimed to be the world’s most powerful gas turbine, which included on-site rotor de-stacking; roll-out and roll-in of the turbine vane carrier without rotor lift; and replacement of Stage 1 without a cover lift. The SGT-8000H fleet includes units at Irsching, Germany, Cape Canaveral Energy Center, Florida, and Bugok Industrial Complex, Andong and Ansan, South Korea.