This article focuses on today’s industrial gas and steam turbines that are designed to be more energy efficient, more reliable, and longer lived than their predecessors. Many of the older models still have plenty of life left in them, though, and turbine operators would have to pay many millions of dollars to replace their old turbines with new ones. Ultraviolet flame detection systems rendered unreliable due to age were replaced by a parametric flame detection system designed by Dresser-Rand Control Systems. The new system uses all 16 of its thermocouples to detect flame in the four gas generator combustors, making use of an algorithm that identifies temperature increases during startup. Structural Integrity has provided its creep monitoring system as a permanent installation, but will offer an offsite monitoring program to broaden the system’s appeal to utilities looking to trim personnel. Future turbine control upgrades will rely on more integrated controls, which treat plant operation as a complete system rather than as individually distinct machine controls.
Today's Industrial Gas and steam turbines are designed to be more energy-efficient, more reliable, and longer-lived than their predecessors. Many of the older models still have plenty of life left in them, though, and turbine operators would have to pay many millions of dollars to replace their old turbines with new ones. But there is a compromise. Increasingly, process operators, utilities, and manufacturers are choosing a more economical strategy-to retrofit aging turbines with modern instruments and controls that are designed to enhance their performance.
"Gas turbines have long been automated. Today, operators can update the original turbine control and measurement systems, primarily to improve their reliability, and secondarily to provide operators with n1.ore accurate information on the condition of the machine," said Bill Rowen, president and chief engineer at The Turbine Engineering Consultancy in Schenectady, N.Y. "The latter benefit means that operators can prevent expensive, unscheduled maintenance shutdowns , and improve turbine availability, especially for turbines used in peaking service."
Rowen was manager of steam and gas turbine control engineering at GE Power Systems in Schenectady before retiring to found his consultancy in 1995. He chairs ASME International's Codes and Standards subcommittee dealing with controls and electrical and auxiliary systems Rowen also chaired the Controls and Diagnostics Comnuttee of the International Gas Turbine Institute from 1986 to 1988.
A variety of control technology is available for updating turbines. For instance, Dresser-Rand upgraded Pemex's booster station gas turbine controls to enhance the ma chines' reliability. Structural Integrity's Creep-FatiguePro system has enabled Kansas City Power & Light to reduce the number of shutdowns for turbine inspections and to defer parts replacement.
The Jonas Inc. Particle Monitor is helping steam turbine operators from Indiana to Denmark reduce particle damage.
GE Power Systems' blade tip clearance measurement technology, which is currently in tests, is intended to reduce turbine losses and improve efficiency.
Noting that some users of industrial turbines may shy away from the costs associated with control upgrades, Rowen suggested they quantify the value of increased reliability in dollars. "Determining how much a day's downtime will actually cost goes a long way in justifying whether or not to enhance their controls and instruments," he remarked.
In February 1997, Petroleos Mexicanos contracted with Dresser-Rand Control Systems in Houston to engineer, design, and install two station control systems and to retrofit unit control systems for 14 Ruston (now Alstom) TB5000 gas turbines at its Jujo and Paredon booster stations in the state of Tabasco, Mexico. The 5,OOO-horse syspower turbines were installed with Ruston control systems in the late 1970s, and drive Dresser-Clark (now Dresser-Rand) compressors.
The retrofit included improving the reliability of the gas turbine fuel control systems, upgrading the compressor surge control systems, and adding instrumentation to the stations and the turbines to allow for more precise monitoring.
The Houston-based engineering company retrofitted the Pemex station with new control consoles that included dual operator interface screens. Unit control panels were installed on each of the eight turbines serving the Paredon booster station, and each of the six turbines at Jujo.
GE Fanuc programmable logic controller (PLC)-based systems provide both supervisory control and data acquisition for the unit control systems and station functions.
The Dresser-Rand retrofit team installed Genius input/output blocks-that is, a distributed I/O system with enhanced diagnostics-in the turbines and in the console panels themselves. The field installations were done to minimize installation downtime and cost, according to Ted Cossins, the Dresser-Rand project engineer.
The combination of the Genius blocks and PLCs make it possible for a single set of twisted-pair wire to transmit data that would otherwise require hundreds of separate wires.
The compressor units at Paredon and Jujo are arranged The compressor units at Paredon and Jujo are arranged by the station and unit PLCs in order to maximize the equipment's operating efficiencies. Both booster stations are connected to Pemex's district maintenance office in El Castano, about 50 kilometers from the stations, via a high-speed Ethernet link , which enables maintenance staff to monitor the turbines remotely.
The new control systems replaced a myriad of separate control components, devoted to sequencing, fuel control , surge control, flame detection, and a host of other monitoring functions.
Reliability was increased by integrating these control functions into the PLCs, and by reducing the number of components that can fail. Integrated controls also require less room than multiple controls, and reduce the spare parts inventory.
Ultraviolet flame detection systems rendered unreliable due to age were replaced by a parametric flame detection system designed by Dresser-Rand Control Systems. The new system uses all 16 of its thermocouples to detect flame in the four gas generator combustors, making use of an algorithm that identifies temperature increases during startup.
In contrast to the original flame detection system, which used eight of its thermocouples for protection and the other eight for control, the parametric system integrates all 16 thermocouples into the PLC and uses them all for more precise starting, control, and protection of the gas generator.
Cossins and his colleagues removed the original pneumatic surge control systems and replaced them with electronic systems equipped with a PLC-based algorithm that uses a universal performance curve. This patented Dresser Rand technology offers benefits that traditional surge control methods do not-for example, extremely accurate surge control by defining the surge point over a wide range of gas mole weights and other process conditions.
A major goal of the Pemex retrofit was to improve reliability of the fuel delivery system, specifically the fuel control valve actuator. Dresser-Rand found a way to retain the original actuator by replacing its electronics originally, five circuit boards placed inside an explosion proof box on the turbine skid-with a single electronic assembly mounted directly on the existing electronics box. This minimized installation costs and used existing hardware. The new assembly is directed by a 4-20 mA signal it receives from the unit control panel to operate the fuel gas throttle valve.
"Retrofitting of the control systems has significantly improved the reliability of the units and the efficiency of the stations," said Jorge Aldana, Pemex division maintenance department chief for compression systems. "The turbo compressors are now operating more safely, and malfunctions are quickly identified and corrected. The new systems will be an integral component of our preventive maintenance program."
The parts of older power plant turbines and those that are cycled frequently are subject to service-induced creep and fatigue damage. This damage is an unavoidable consequence of operation at temperatures of 1,000°F or more, and of the temperature changes that occur during cyclic operation. These stresses create tiny cavities in low-chrome alloy steels that eventually link up to form cracks.
The onset of this damage depends on the temperatures reached, and on the severity and frequency of temperature changes. The Electric Power Research Institute in Palo Alto, Calif. , recognized the close relationship between turbine life and plant-specific operating conditions, and sponsored the development of a creep monitoring system called Creep-FatiguePro, developed by Structural Integrity Associates Inc. of San Jose, Calif. Structural Integrity had already designed a fatigue monitoring system, FatiguePro, for EPRI that is widely used by the nuclear industry.
Creep-FatiguePro is a predictive tool that collects temperature, pressure, and flow rate data as frequently as once per minute to predict creep damage. The system is used for monitoring damage accumulation and remaining life in boiler components and piping as well as turbines.
"Plant operators use this information to optimize their inspection intervals and enable their turbines to run longer between inspections," explained Mario Berasi, a member of the American Society of Mechanical Engineers and an associate at Structural Integrity. "Creep-FatiguePro also identifies the most damaging operating procedures, so that operators can alter those procedures to extend the life of the turbine."
A major advantage of Creep-FatiguePro is that in most installations, the system relies on existing plant thermo couples, pressure transducers, and flowmeters to collect information, while eliminating the expense of additional instrumentation.
"We also write a front-end computer program so that the monitoring system can interface with the power plant's distributed control system," said Berasi.
The computer program reads data collected from the instruments and translates it into data files for the Creep FatiguePro system, which is run on a personal computer.
The system calculates component stresses, creep and fatigue damage, and damage accumulation rates. It also charts creep fatigue crack growth rates in order to predict when a crack will be initiated, or where crack failure will occur.
The first Creep-FatiguePro system. was installed in September 1993 at Unit 2 at Montrose, a pulverized coal-fired power plant located near Clinton, Mo., which is owned and operated by Kansas City Power & Light in Kansas City, Mo. This turbine is an ABBI Combustion Engineering boiler with a General Electric turbine generator unit nominally rated at 170 MW. The Creep-FatiguePro system monitors the turbine rotor, casing, and steam chest, as well as the boiler outlet headers, and main and hot reheat system.
In 1995, KCPL calculated that using Creep-FatiguePro to predict the remaining life of steam piping and outlet headers would permit the utility to extend the intervals between inspections from four years to six, reducing outage costs by $100,000 over 20 years.
More accurate performance life assessments of the turbine casing, rotors, steam lines, and headers are expected to enable KCPL to defer replacement of parts by two years or more, for an estimated saving of $740,000 over 20 years.
With a total installation price tag of$220,000, the monitoring system is expected to save the utility $620,000 over 20 years. The estimates led KCPL to install Creep-FatiguePro monitoring system.5 on the other two Montrose units in 1996.
Unit 1 is a CE boiler GE turbine generator similar to Unit 2. Unit 3 is a CE boiler Westinghouse turbine generator unit with a nominal capacity of 190 MW
The Creep-FatiguePro system collects instrument data on-site and transmits it to a personal computer in KCPL's corporate offices in downtown Kansas City. "I perform an archival file search to gather the operating data that has been collected for one or two weeks and combine it into a single file," said Glenn Beckerdite, a mechanical engineer and senior engineer at KCPL. "A batch file converts this information into a file that is compatible with the Creep-FatiguePro software. I transfer this data via a LAN system to a dedicated personal computer that periodically crunches the information for study."
Structural Integrity has provided its creep monitoring system as a permanent installation, but will offer an offsite monitoring program to broaden the system's appeal to utilities looking to trim personnel
"We will install the minimum equipment needed to collect data on-site, and will monitor it at our offices and report to the utility, suggesting how to minimize creep and fatigue damage, when to schedule inspections, and how to extend the useful life of critical plant equipment," said Berasi.
Preventing Particle Damage
Jons Inc. Consultants in Wilmington, Del. , developed a particle monitor to measure the flow of exfoliated oxides and predict their effects on solid particle erosion and on steam turbine efficiency in power generation or industrial turbines and reduce costly downtime. Otakar Jonas, a corrosion engineer and member of ASME who founded Jonas Inc., presented a paper describing the monitor at the International Joint Power Generation Conference held in Baltimore last August.
The particles in question are solid iron oxides, mostly magnetite, that form on the surfaces of boiler superheater, reheater, and steam piping. When the temperature drops during turbine shutdown, they exfoliate. These particles accumulate in the superheater and reheater tubes. During startup and operation, the particles become abrasives that erode valves and turbine blades.
The Jonas system inserts a particle monitor directly into the steam piping . As particles strike the probe, the impact generates shock waves. A resonant, high-frequency transducer translates these vibrations into electrical signals proportional to the kinetic energy of the particles.
In the latest version of the particle monitor, which was introduced in 1998, the signals are amplified, digitized, and then analyzed by a personal computer using proprietary Jonas software.
"The PC outputs the mass of particles in the pipe per second on a continuous basis, the number of particles passing per second, and typically, every eight seconds, the mass distribution of particles," Jonas said. "Through our experience and field data, we use that information to determine when the exfoliation occurs and to what extent, then correlate it to operation and design. This enables us to predict the extent and location of erosion damage, and to propose and verify solutions."
Plant operators use the particle monitor findings to apply proper engineering solutions to erosion. "For example, they can reduce the rate of temperature changes to reduce spalling. Also, during startup, turbine operators can remove the particles by leaving the steam drain valves open, or use the turbine bypass. Another strategy is chemically cleaning the superheater and reheater," said Jonas.
A prototype Jonas Particle Monitor was first installed at Potomac Electric Power Co.'s Morgantown Station's Unit 2 in 1986. This is a 580-MW coal-fired supercritical unit. Armed with real-time knowledge of oxide exfoliation, plant operators have several options for corrective measures, such as to reduce the high-pressure turbine inlet flow velocity by changing the sequencing of control valves to full arc admission, thereby reducing particle damage. Other Jonas Particle Monitors have been installed at the Pennsylvania Power & Light Montour station, Southern California Edison's Ormond Beach station, Public Service of Indiana's Gibson station, and at the Fynsvaearket power plant of ELSAM in Denmark.
Operators of the Gibson, Ind., station reduced the release of solid oxide particles during startup by adjusting the ramping up of throttle pressure. They also used the instrument to monitor the effectiveness of steam flow after repairs to that unit.
In a Sacramento Municipal Utility District geothermal system in California, the monitor was used to reduce transport of impurities into the turbine as well as to extend intervals between cleanings and improve its efficiency.
The future of turbine automation may lie in new measurement technologies still in the laboratory stage but headed toward commercialization. One promising technique is the blade tip clearance measurement technology developed by GE Power Systems in Schenectady, N .Y.
This new technology was developed to increase the power and efficiency of industrial gas turbines' power and efficiency by minimizing the loss at the clearance between the rotor blade tips and the turbine casing. This space changes with the temperature within the turbine. During startup, the rotor blades expand faster than the turbine casing, tightening the gap. As the casing expands during operation, the clearance opens up.
The smaller the clearance, the more efficient the turbine. However, too narrow a clearance 'means the blade tips will rub the casing and wear down, eventually increasing clearances and lowering efficiency.
"We reasoned that if we could accurately measure how the blade tip clearance changes during the startup, shutdown, and operation of turbines, we could alter turbine design to optimize blade tip clearances," said Michael Ingallinera, a mechanical engineer and manager of product life data acquisition at GE Power Systems. "This knowledge could also enable turbine operators to adjust their turbines' operation to minimize turbine losses, for example, modifying the supply of cooling air to affect clearances."
Ingallinera co-authored ASME paper GT-97-466, which describes this measurement concept. The paper was presented at the International Gas Turbine Institute's Turbo Expo conference in Orlando, Fla., in 1997 .
GE Power Systems engineers partnered with three instrument manufacturers-BICC Thermoheat of Hebburn, England; RotaData Ltd. of Derby, England; and Capacitec of Ayer, Mass .to jointly develop the new measurement technology. "This enabled us to use their instrumentation expertise and, after the system was perfected , to purchase ready-made components," said Ingallinera.
The General Electric researchers tested the system on their MS6001FA gas turbine. They installed two capacitive probes in the turbine shroud connected to nearby oscillators. The probes set up a capacitive field that corresponds to a particular frequency generated by the oscillator. As the blade tip passes near the probe, that frequency changes proportionally to the distance between the blade tip and the casing.
A converter transforms the oscillator output to a varying voltage that traces the profile of the blade tip. This signal is used to judge the quality of the signal and its variance over time. The oscillator output is also converted to a de voltage that is fed into GE's test computer system, along with pressure, temperature, rotor speed, and other operating data, to take real-time measurements of the blade tip clearance.
"The system not only confirmed the trend we had expected, but gave us reliable quantitative data," Ingallinera said. "For example, clearances decrease during startup due to centrifugal loading, then close up as the rotors heat up and expand faster than the turbine casing, then open up again as the turbine casing heats up."
While the blade tip clearance measurement system has proven itself in turbine design, it has some way to go before there is commercialization on operating turbines. Currently, we have to maintain and cool the capacitive probes for a commercial turbine operating environment. In addition, the system's range is limited," explained Ingallinera.
However, a c0l11ll1ercialized system would more than pay for itself, according to Rowen of The Turbine Engineering Consultancy, "because it would enable operators to exercise active clearance control. Instead of building bigger blade tip clearances to accommodate blade profile changes during startup, operators could run tighter clearances, for example, by actively cooling the turbine shrouds." (This strategy was described in an article in Mechanical Engineering, "Turbines for the Turn of the Century," in June 1994.)
According to Rowen, future turbine control upgrades will rely on more integrated controls, which treat plant operation as a complete system rather than as individually distinct machine controls. "This is particularly apropos for steam-cooled configurations, where the steam and air cycles must be integrated," he said. Tomorrow's controls will also be more sophisticated to provide data needed to conduct predictive, and even adaptive, maintenance.