These are heady days for GE Power Systems advanced gas turbine developers. With commercial demonstration operation of the first H machine (a 50 Hz, 9H version), at Baglan Bay (pictured above), closely followed by the announcement of the site for the world’s first 7H (the 60 Hz version of the H) and the introduction of the equally innovative LMS100 gas turbine (MPS, January 2004) we see major steps in the integration of the most advanced aircraft engine technology into industrial power generation applications.
In January 2003 Hydro-Québec announced that it would partner GE in implementing a twin unit 836 MW gas-fired combined-cycle power plant employing 7H technology. The Québec government authorised an improved version of the original project and the federal government favourably concluded its evaluation under the Canadian Environmental Assessment Act. However, in February 2004 the Québec government, responding to criticism of the plan, effectively put the project on hold pending the outcome of a study, with public consultation, examining the province’s energy needs to 2010 and whether the plant was justified. A report has been requested from Québec’s Régie de l’Energie (Energy Board), for completion by 30 June.
The proposed site for the Suroît 7H plant is at Beauharnois, southwest of Montreal. It had been scheduled to enter commercial service in mid-2007. Interestingly, Canada’s commitment to the Kyoto Protocol was cited as one of the determining factors in Hydro-Québec’s selection of H technology for the new plant.
The Suroît 7H plant, asssuming approval, would be built under an existing partnership with Beauharnois-Salaberry RCM and the municipality of Beauharnois.
Québec’s environmental hearing board, BAPE, reviewed the Suroît project and urged that a concerted continent-wide effort be made to reduce greenhouse gas emissions. “If this technology had been used for all gas-fired combined-cycle plants built in the last two years in North America, the emission of 5.5 million tons of GHG would have been avoided,” declared Hydro-Québec President and CEO André Caillé.
Shipment of the 7H combined cycle system for the Suroît project will be covered under a previously announced agreement signed by GE and Toshiba of Japan in 1998. Under this agreement, GE has H System integration and performance responsibility, and will design and manufacture the H gas turbines and supply the integrated control systems for the power train. Toshiba will manufacture the GE-designed compressors, along with Toshiba-designed generators and steam turbines.
Following the loss of the Sithe Energies Heritage site in upstate New York, where the growth in electricity demand had substantially diminished, the new 7H two unit field test site in Canada was seen as good news for GE. But now the project must wait for a further final approval.
The 7H has already been successfully tested at full-speed, no-load conditions at GE’s Greenville, SC, gas turbine manufacturing facility.
9H at Baglan Bay
Meanwhile at Baglan Bay, in Wales, UK, five months of validation testing were completed in May 2003. The results appear to have been the predicted success for what must be the most careful and painstaking gas turbine development programme of all time.
This was the first field operation of a gas turbine with steam cooling of both stationary and rotating blades. In the course of testing the single unit was run over a variety of operating points including baseload at full 480 MWe output and extended load up to 530 MWe at 6.7°C.
The tests, involving more than 7000 sensors placed on the equipment, have validated GE’s innovative closed-loop steam-cooled technology and have successfully demonstrated the overall plant design. Extensive testing also has validated more than 100 critical-to-quality characteristics, “We are very pleased with the results of the field tests,” said Mark Little, VP, GE Power Systems – Energy Products. “Our ongoing analysis of test data is correlating well with pre-test engineering predictions.”
The Baglan Bay plant has not cracked the psychological 60% combined cycle thermal efficiency barrier, nor, says GE, was it intended to. The primary purpose of Baglan Bay is to validate the gas turbine technology capable of achieving 60% in combined cycle. But the system’s 2 to 3% increase over the current state of the art will represent a huge benefit in commercial operation performance.
Following successful completion of the characterisation testing, a planned outage was scheduled to replace highly instrumented turbine components with standard non-instrumented components. Following conclusion of the outage in late August 2003, GE completed some additional tests as part of the pre-commercial commissioning, which included a series of start-ups and shut downs followed by borescope inspection.
The plan was to restart the plant for an 8000 hour commercial demonstration run in September 2003 but this has been delayed. On 22 October GE declared that during initial operation following the replacement of the rotor, control and monitoring instrumentation indicated that three of the second stage buckets were operating at elevated temperature as compared to expectations.
According to a GE statement, “Thorough inspection of the stage two buckets re-confirmed that the elevated temperature was the result of a localised cooling flow restriction caused by foreign material collecting in the steam cooling path during the supplier’s manufacturing process. A full evaluation of the supplier’s process is now under way.”
The unit was shut down for inspection, root cause analysis and any required corrective actions. A further statement declared, “The inspections have confirmed that the elevated temperature was not the result of a design issue.”
During the same outage, following a thorough inspection of the entire power plant, evidence of leakage was observed in the HRSG, which was corrected. Again, it was reported that the HRSG issue was not related to the H System design. The HRSG is massive (see upper photo, p22) but of fairly standard design, with three pressure levels plus reheat.
The plant was subsequently restarted and at the time of writing had been feeding some 530 MW into the network for several months.
Welsh political and business leaders gathered with GE Power Systems executives and global customers at the Baglan Bay power station on 12 September 2003 to celebrate the commercial operation of the world’s “most powerful and most efficient gas turbine technology.”
“This is a major milestone not only for GE, but for the entire power industry,” said John Rice, president and CEO of GE Power Systems.
The closed-loop steam cooling system permits the higher firing temperatures required for increased efficiency while retaining combustion temperatures at levels consistent with low emissions.
The H System was developed as part of the US Department of Energy’s ATS (Advanced Turbine System programme), which would later lead into the Vision 21 programme conceived to map out the DoE’s R&D aspirations for the new millennium.
One giant step…
H technology was previously described in the June 1995 and May 1999 issues of Modern Power Systems. But development of the H technology concept first began in 1992, which tends to indicate how long the gestation period for this radically advanced concept has been. Every aspect of the new technology has been exhaustively tested and proven in research rigs and twice on the full scale pre-shipment test stand at Greenville.
In addition to the new steam cooling system, the H turbine has single-crystal first-stage buckets and nozzles to withstand higher temperatures over a long service life.
The use of steam cooling resolves the conflict between higher firing temperature and lower NOx. A typical advanced air-cooled first stage nozzle has a nominal 155°C (280°F) temperature drop, because in this open loop cooling system the air that is used to cool the nozzle mixes with the main flow stream, thereby reducing its temperature upstream of the first stage bucket.
In the closed loop steam cooled nozzle, the steam does not mix with the main flow stream and therefore does not dilute its temperature, and so the flow stream temperature is only reduced by the effect of flow across the cooled nozzle. With a temperature drop of only 45°C (80°F), the steam-cooled nozzle design can maintain the same combustor exit temperature, and therefore the same NOx levels, and yet benefit from a 111°C (200°F) increase in firing temperature over the F class machines.
Much of the H design is based on proven turbine technology. The H compressors were based on the compressor designed for the CF6-80C2 aircraft engine and the aeroderivative LM6000 gas turbine.
Swozzles and spoolies
GE’s well tried and proven DLN can annular combustors can limit NOx to below 9 ppmv utilising lean premix flow fed to “swozzles” – a new word not as yet included in the OED which is formed by the conjunction of “swirler” and “nozzle”.
But the key distinguishing feature of the H gas turbine is the steam cooling in the turbine. The first two stages are steam cooled, the third stage is air cooled, and the fourth stage is uncooled. By using four stages, the H turbine is able to optimise work loading of each stage and achieve higher turbine efficiency.
The rotor steam delivery system used to provide steam to cool the stage 1 and 2 turbine buckets relies on “spoolies” to effectively deliver steam to the buckets without detrimental leakage of steam, which would lead to performance loss and adverse thermal gradients within the rotor structure. The basic concept for power system steam sealing is derived from many years of successful application of spoolies in GE aircraft engines, eg, the CF6 and CFM56 engine families.
In each of the attempts to build large utility scale superconducting generators to date similar devices have been successfully used to introduce liquid helium or hydrogen into the rotors, and if these fluids have been transported in this way without excessive loss steam should probably not be that much of a problem.
In the preliminary design phase, parametric analysis was performed to optimise spoolie configuration. Component testing began for both air and steam systems. Sample spoolies in the component tests were instrumented to validate the analysis.
In the conceptual design phase, material selection was made to account for application with steam. Coatings to improve durability of the spoolies were also tested. In the preliminary design phase, parametric analysis was performed to optimise spoolie configuration. Component testing began for both air and steam systems. Sample spoolies in the component tests were instrumented to validate the analysis. Again, the combination of analysis and validation tests provided confirmation that the design was proceeding with the right concept.
Over 50 component tests have been conducted on these spoolies evaluating coatings, lateral loads, fits, axial motion, angular motion, temperature, and surface finish.
The detailed design phase focused on optimisation of the physical features of the sub-system, spoolie-coating and seat.
Steam is supplied from the high pressure (HP) steam turbine exhaust and the HRSG IP superheater to the closed circuit steam cooling system that cools the gas turbine stage 1 and 2 hot gas path parts. The cooling steam is returned to the steam cycle in the cold reheat line to the reheater. Thus, the closed circuit gas turbine steam cooling system operates in series with the reheater.
The gas turbine cooling steam system is integrated with the steam bottoming system to reliably provide steam at all operating conditions. During normal loaded operation the supply of cooling steam is from the HP steam turbine exhaust and the HRSG IP superheater. The steam is filtered prior to supply to the gas turbine. The steam is delivered to the gas turbine stationary parts through casing connections and to the rotor through a rotating steam delivery system.
To further optimise the combined cycle efficiency and material selection, air extracted from the compressor discharge is cooled using water from the IP economiser. The cooled cooling air is readmitted to the turbine and compressor to cool compressor wheels and selected gas path components. The energy extracted from the compressor discharge air is returned to the steam cycle by generating steam which is admitted to the IP drum.
9H HRSG
The immediate object of the Baglan Bay tests is to confirm the performance of the 9H gas turbine. The H System HRSG water chemistry is consistent with other GE large combined cycle systems, with no feedwater polishing required. A full flow condensate filter is implemented to remove any particulate.
No doubt a major factor in performance optimisation will be the effects of the blade cooling steam diversion on the HP steam heat, exhaust mass flow and temperature characteristics of both the gas and steam turbines. The HRSG has a reduced capacity reheat section since the blade cooling steam will benefit from the heat extracted in the turbine blades.
Control of the HP steam temperature is accomplished by a steam attemperation system. This system eliminates the potential for contaminants to enter the steam as can occur with attemperation using feed water. Attemperation steam is extracted after a single pass through the superheater. The remaining steam passes through the intermediate high temperature section of the superheater. The attemperation steam is mixed at the final superheater inlet to control the temperature of the steam to the steam turbine.
In addition to supplying steam for main steam attemperation, steam is extracted from the HP superheater downstream of the first pass for the start-up cooling steam supply to the gas turbine and LP steam turbine.
Since supply of high purity steam to the gas turbine is an essential requirement of the system,
• all gas turbine cooling steam is purified by evaporation in a steam drum;
• HP steam temperature is controlled by steam attemperation (as already noted);
• condensate is subject to full flow filtration;
• piping in the HP and cooling steam supply system upstream of the shutoff valves is either alloy or stainless steel or is covered by the nitrogen blanket system to prevent corrosion during standby periods;
• a nitrogen blanketing system is used in the HRSG;
• non-corrosive materials are used in piping, filters and equipment downstream of the cooling steam shut off valves; and
• full flow cooling steam filtration is used.
A start-up steam supply system is included, which extracts steam from the HP superheater after the first pass and mixes it with steam from the superheater discharge to supply steam to the cooling steam system at the required temperature. During start up the IP bypass valve is modulated to maintain the pressure of the cooling steam above the gas turbine compressor discharge pressure to preclude gas leakage into the steam cycle.
During gas turbine starting, acceleration to rated speed, and operation at spinning reserve load the gas turbine is cooled by air extracted from the compressor discharge. The air is filtered prior to supply to the gas turbine. The cooling air from the gas turbine is discharged to the gas turbine exhaust. Shut-off valves isolate the cooling system from the steam cycle while it is operating with air-cooling.
Power and heat
Project financed by GE Capital and built by GE on land leased from BP Chemicals Limited, the Baglan Bay power station is being operated by GE’s European Operations & Maintenance group and is providing electricity and steam to the Baglan Energy Park and BP Chemicals’ Baglan isopropanol plant, with the remaining electricity going to the UK national grid. The power is being traded on the open market on a merchant basis with the help of a trading agreement with natural gas supplier Centrica on an indexed basis.
In addition to the 9H system, the power station also includes a 33 MW combined heat and power plant based on a GE LM2500 gas turbine. It burns a mixture of natural gas and waste fuels from the isopropanol plant including PPG and “DIPE” and it supplies electricity, process heat, demineralised and attemperated water and process cooling to the chemical plant as well as the Baglan Energy Park.
GE originally evaluated a two unit 1000 MWe commercial power generation facility, Fleetwood in Lancashire, to replace some of the output of the decommissioned 2000 MWe Pembroke power station. Before that an 1100 MWe plant with three 9F gas turbines and a single steam turbine, to be developed by Entergy, was mooted. The area is currently a net importer of electricity from England at great expense.
After the initial setbacks from the natural gas moratorium in the late 1990s, the Blair government eventually conceded that one of two 9H units planned for commercial operation on the Baglan site could be installed as a “research project” to benefit industrial and social development in the area as long as it met the exclusion requirements of being able to supply heat as well as power and had black start facilities which would allow it to supply power in the event of the loss of grid supply.
The combined cycle output of up to 530 MW of power achieved during test operation is essentially twice the output of the 7FA. The Frame 9H gas turbine which measures a mere 12m in length, has a diameter of 5m and weighs 400 t which is very little bigger than the 9FA plant. Compared to F technology plants the H System gives about 45 per cent more MW per square foot.
Japanese partners and projects
All future shipments for the H System will be covered under a “risk and revenue sharing agreement” signed by General Electric and Toshiba of Japan in June 1998, and referred to earlier.
Under this agreement, GE has H System integration and performance responsibility, and will design and manufacture the H gas turbines and supply the integrated systems controls for the power train. Toshiba will manufacture the GE-designed compressors, along with Toshiba designed generators and steam turbines.
GE has an order from Tokyo Electric Power Company (TEPCO) to supply three 109H systems for TEPCO’s Futsu thermal power station Group 4 project in Japan. The combined output of the three systems will be 1520 MWe.
TablesComparison of combined cycle plant performance characteristics
