Upgrading controls will maximize power plant operations
By Douglas J. Smith, Senior Editor
In order to remain competitive, electric utilities are optimizing power plant operations by upgrading and/or installing state-of-the-art control systems
With deregulation moving at a full pace, the U.S.?s electric utility industry no longer has a monopoly on the generation of electricity. Because of competition from non-utility electric generators, and the need to meet new and ever tighter emission standards, electric utilities are trying to improve the reliability and availability of their existing power plants.
As a power plant ages maintenance tends to increase while breakdowns become more frequent. This is also true for instrument and controls systems. However, one of the most cost effective solutions for improving the reliability, availability, and operation of older electric power generation plants is to upgrade and modernize a plant?s instruments and controls.
Jacksonville Electric Authority (JEA), Fla., supplies electricity to the City of Jacksonville, and its surrounding areas, from four different power plants. At its Northside power plant there are four GE Frame 7 peaking combustion gas turbines. The station also produces 800 MW from oil and gas-fired base-loaded steam turbine generators. Due to the areas economic growth, the reliability of the peaking units became more critical. When peaking power is required one or all four of the gas turbines must be on-line in less than 10 minutes.
However, because the gas turbine?s controls were old, and spares parts difficult to obtain, the reliability of the controls used for bringing the gas turbines on-line became a major concern. As a consequence, JEA decided to upgrade the controls systems in order to improve and maintain the reliability of the peak units.
JEA has replaced the Northside power plant?s gas turbine controls with state-of-the-art digital controls. The controls on each of the gas turbines have been replaced with a remote final driver to interface with the plant?s existing valves, a real power sensor for load control and sensing, and a panel-mounted CRT monitor for starting, stopping and monitoring the gas turbines (Figure 1). In addition, two operator interfaces and a main operator control panel were added. All of the systems were supplied by Woodward Governor Co., Rockford, Ill.
One of the operator interfaces was installed in the gas turbine?s control room which is located adjacent to the turbines (Figure 2). The other operator interface was installed in the station?s main control room and is connected to the turbine control systems through fiber optic cables. Identical data is available at either of the operator interfaces.
Woodward?s digital controls have replaced the Frame 7 turbine?s original speed controls, combustion monitor and atomizing air skid controls. In addition, the new controls system monitors the turbine?s vibrations and temperatures. The new controls also include flame detection, automatic error checking sequencing, and speed and fuel control during startup.
Northside?s operator interfaces, which are computer based, provide the operators with a full spectrum of information about the operation of the turbines (Figure 3). They also function as annuciators and data loggers and are used for trending and diagnostic analysis of turbine operations. This allows the operators to reduce costly shutdown and maintenance by detecting problems at an early stage.
In addition to providing the operators with instant visual operating data, the CRTs and the operator interfaces supply easy-to-read alarms and trip information. This information includes temperature profiles, speed algorithms, start sequencing and other operating data. Turbine operating efficiency is enhanced by regulating the startup sequencing and by monitoring the turbine?s temperature and vibrations during startup.
During startup of a gas turbine, the start permissive and sequencing screens are used by the operators to watch the entire startup as the control system takes the gas turbine through each step. Not only does this allow for better turbine operating efficiency, but it is able to extend the life of the turbine by minimizing thermal shock.
Prior to installation of the new control system, JEA had difficulty determining the cause of excessive turbine vibrations. However, the new vibration monitoring system gives the operators more detailed information about vibrations. As a result, the operators not only know the severity of the vibration, they are able to determine the cause of the vibration.
According to Woodward Governor, the new control system fitted to the Frame 7 gas turbines at Northside power plant has already saved hours of time in troubleshooting. Likewise, the plant?s operators are now able to operate the turbines more efficiently and reliably.
Base load to peaking
Because of newer fossil-fueled units, and a nuclear power plant, Union Electric Company (UE), St. Louis, Mo., had no need to continue base load operation of the two units at its Meramec station. For this reason, UE reassigned the units to peaking duty. However, the existing plant pneumatic control systems were found unreliable for peaking operation (Figure 4). As a result, the operators had to spend more time operating the systems manually and, because of this, the plant?s efficiency suffered.
Because UE needed the peaking capacity of the Meramec station to supply its growing customer base, the plant?s reliability was very important. Unfortunately, it was not feasible to continue to use the old microprocessor based distributed control system (DCS) (Figure 5).
Meramec?s DCS integrates the combustion controls, burner management, motor logic controls, data acquisition, and annunciator and sequence-of-events systems into one central control system. According to Don Luecknotte, a controls engineer with Burns & McDonnell, Kansas City, Mo., the most important feature of the DCS at Meramec is the system?s ability to provide an integrated, coordinated and flexible interface with the plant operators. At Meramec this is important because daily cycling of the units requires constant operator interaction.
Each of the Meramec units is operated from a cathode ray tube- based (CRT) operator console and generator control subpanel. The subpanel contains the synchronization and emergency controls systems. The CRT?s graphics have replaced the station?s conventional switchboards that originally housed the descrete gauges and switches. Engineers from UE and Burns & McDonnell developed the CRT?s graphics. The graphics, grouped by function, represent the plant?s processes, subsystems and control displays.
An upgraded control room allows for central control of the plant by the operators. The operators, using touch screens, or a track ball, can change a process or equipment setting by pointing to icons on the CRT screen. Operators can also use customized keyboards to check plant operations and/or change plant controls as needed.
More than 1,500 plants devices, including control valves, pressure switches and electronic switches, send and receive signals through cables linked to eight data control units (DCUs). The DCU can communicate with one another or with input/output modules.
Should a process variable go out of range the DCS sends a signal to the controlling device to correct the problem. However, in some instances the system may sound an alarm. An archive subsystem of the DCS keeps a record of process variables, events and operator actions.
As a result of the upgraded control system the operators at Meramec are now able to monitor and operate the plant more efficiently by responding more quickly to changes initiated by themselves or by occurrences in the field.
Control upgrades at Wagner
Baltimore Gas & Electric Co. faced many challenges when it decided to upgrade the controls on Units 3 and 4 at its H.A. Wagner generating station. The station is located on the Chesapeake Bay south east of Baltimore, Md. A major challenge was designing a control system for units with different boilers and turbines.
Unit 3 is a 322-MW coal-fired, supercritical once-through unit while Unit 4 is a 400-MW oil-fired unit. Although the steam turbines are both manufactured by Westinghouse Electric Corp., Unit 3 is a cross-compound, double-reheat, double-flow exhaust design and Unit 4 is a impulse-reaction, two-cylinder tandem-compound, double-exhaust, condensing reheat turbine.
Most of the original controls were installed in a large central control room. The controls included annunciator, recorders and electronic analog control system components. Modifications carried out in the 1970s and 1980s had added
balanced draft controls, a microprocessor-based boiler temperature monitoring system, a performance monitoring computer and partial burner management subsystems.
Wagner?s control modernization program was designed to improve the operation, life and maintenance of Unit 3 and 4. A major part of the upgrade was the installation of electronic analog controls and balanced draft controls into a new DCS. The plant?s modulating control loops for the boilers and the turbines, plus other miscellaneous controls, were also incorporated into the DCS.
To eliminate the old steam turbine control panel on Unit 4 a new operator interface, for the existing analog electro-hydraulic control system, was added. A new central control room building was constructed and rooms have been fabricated in the plant to house the DCS and burner management systems? (BMS) input/output (I/O) cabinets.
While all of the old benchboards have been replaced with new cathode ray tube (CRT) consoles some of the old vertical boards have been retained. The hard-wired coal handling programmable controller interface and the watt-hour meters have been retained. However, all of the recorders have been eliminated. The motor controlled equipment, originally controlled and operated from switches on the benchboard, are now operated via the DCS operator console. In addition, synchronization of the units is now carried out through conventional control stations and/or a DCS interfaced auto-synchronizer.
All of the field transmitters have been replaced with new electronic transmitters and the old hardware, used for alarm monitoring, data acquisition and performance monitoring, has been eliminated. These functions are now carried out by the DCS.
Some of the thermocouple controls, together with all of the instrument and thermocouple wire, have been replaced. Furthermore, the old pneumatic damper drive units were replaced with electric drive units. Burner management logic and I/O has been installed in a separate system with its own communications link to the DCS. Each of the units have been fitted with new uninterruptible power systems (UPS).
Unit 3 has approximately 2,900 I/Os, 12 DCSs cabinets and three BMS cabinets while Unit 4 has approximately 2,300 I/Os, 10 DCS cabinets and six BMS cabinets. The DCS operator interface utilizes eight CRT stations and four keyboards on each unit. One CRT on each unit is dedicated to alarm display.
Downtime of the units was reduced by constructing the control room and installing the new cabling, cabling trays and wiring during plant operations. At the same time, the I/O wiring was also terminated in the DCS cabinets. As a result, only the field end of the cabling needed to be terminated during the outage. Most of the operator interface functions are accomplished through touchscreen, keyboard and CRT graphic displays.
Wagner control details
Wagner?s DCS, supplied by Westinghouse Electric, uses redundant processors, data highways and operator-controlled touch screens. The DCS has 10 distributed processing units for Unit 4 and 12 for Unit 3. All plant controls, including data acquisition, alarm monitoring, combustion control and performance monitoring functions, are carried out through the DCS. The BMS, together with the flyash and emissions monitor?s programmable logic controllers, are connected to the DCS through data links. Separate relay cabinets provide all of the digital output interfaces to the field devices.
Burner management logic for the pulverizers, feeders, burner ignitors and burner trips, on Unit 3, and Unit 4?s oil burners, ignitors, valve manifolds and fuel trips were developed and installed as part of the burner management systems.
Synchronization of the generator is carried out manually or by an auto-synchronization. The latter interfaces with the DCS. Except for synchronizing, all of the binary and motor control stop/starts and indications, previously carried out from the benchboard or vertical boards, are now done through the DCS. Voltage regulation and excitation is also carried out through the DCS.
Lewis Creek control upgrade
Because of decreasing reliability of its outdated boiler control and data acquisition systems on Unit 1 and 2 at its Willis, Texas, Lewis Creek station, Gulf States Utilities decided to replace the systems with the latest microprocessor-based technology. The project was carried out in three phases: Phase 1 was the installation of central information systems on both units and a new water treatment control system; in phases 2 and 3 new boiler control systems were added to Units 2 and 1 respectively.
In the past, Gulf States had used sole sourcing for purchasing control systems. However, in today?s environment Gulf States felt that sole sourcing was no longer applicable. As a consequence, the specification was written to include several vendors of distributed control systems. Developing the specification, obtaining and evaluating the bids, and negotiating a strategic alliance agreement with the successful vendor took four man-months.
Gulf States required a three-year agreement during which time the utility would purchase and install six boiler control systems and two central information systems. Under the strategic alliance agreement Gulf States agreed to identify and purchase, over a period of three years, specific products and services. Under this agreement Gulf States identified the distributed control systems and central information systems it would purchase for upgrading of the Lewis Creek control system upgrade.
Gulf States says the strategic alliance has the following benefits:
Y Favorable pricing, as the agreement with the supplier, guaranteed Gulf States the lowest price offered to any other preferred customer with auditing provisions.
Y Eliminated the cost of lengthy and detailed specifications.
Y Eliminated the justification for sole sourcing.
Y Eliminated the cost of multiple bid evaluations.
Y Allowed for sharing of strategic goals and the free interchange of information between Gulf States and the equipment?s vendor.
Y Reduced the cost of spare parts and training.
According to Gulf States, a major reason for the success of the project was the plant?s operations staff that was involved in the project from the beginning. Using the graphical interface software, Gulf States was able to construct its own graphics. For operations training the graphical interface software was installed on a personal computer with a Windows-type operating system. Not only did this help the operators learn this operating system, it also helped them later during the development of the system?s graphics.
Acceptance tests for the first unit were carried out at the vendor?s factory. This included functionality testing of the boiler control loops, the installation of the fiber optic highway cable, the removal of the old cabinets and the installation of new ones.
Gulf States believes that part of the project?s success has been the involvement of the operators from the beginning. The end result is that the new control system upgrade will pay back its cost many times over. END
Market for power plant
controls looks promising
According to a CSR market data report, U.S. electric utilities have plans to spend $546,795,000 during a 30-month period between October 1, 1994 and April 1, 1997 for electric generating plant controls and monitoring systems. Nuclear power will account for 30 of the 400 projects identified by CSR (Figure 6).
CSR is a Division of PennWell Publishing Co., Tulsa, Okla.
CSR said that one of the factors for the decrease in capital spending in 1994, over that of 1993, is the mandate for electric utilities to install continuous emission monitoring systems. Because of this requirement, electric utilities have reduced the capital dollars they plan to spend on power plant control and monitoring systems.
Figure 7 shows the average budget of planned nuclear and non-nuclear projects since 1986. Despite the decrease in the total dollar value for nuclear power plant control projects in 1994, as shown in Figure 6, the average cost of the projects has increased since CSR?s 1993 survey. Although there are fewer projects, more dollars will be spent for each project. Since 1986, the average cost for non-nuclear project has remained steady, according to CSR.
The current CSR survey shows that electric utilities plan to award 267 projects, worth $340,170,000, for the 12 month period starting October 1, 1994. According to CSR?s past experience, only 58 percent of the projects will actually start in that time frame. The remaining 42 percent will be delayed or, in some instances, canceled.