American utilities are building very few new coal-fired and nuclear plants, and power generation companies are turning to alternatives to increase the reliability and output of existing infrastructure. Learn how an uprated generator can meet needs of additional output and reactive power.
By Jeff Muha and Kirk O’Brien, GE Power & Water Active Voltage Conditioner
Global demand for electricity supply continues to grow. Power generation providers constantly evaluate capacity additions and the tradeoffs between alternatives. Since American utilities are building a very small number of new coal-fired and nuclear plants, power generation providers are turning to alternatives that can increase both the reliability of existing power generation equipment and power output. Upgrades exist for boilers, reactors and turbines that increase the shaft horsepower of the power train. And, options to increase combustion turbine output are being pursued actively. Other major equipment within the power plant, including the generator, must also be considered as part of any power plant uprate project.
A synchronous AC generator should provide two key functions as part of a power plant uprate. Of course, it can serve as the conduit of the power from the plant to the grid. Second, the generator should supply reactive power, otherwise known as VARs (volt ampere reactive), to the power system to allow the real power (MW) to be transmitted to – and consumed at – the load centers, while maintaining stable power system voltages. Transmission system operators and regulators are increasingly emphasizing that the generator must supply more VARs and maintain rated power factor to accompany any increase in real power output. Also, synchronous generators supply dynamic VARs, which are important for voltage stability during system transients such as transmission line faults. An uprated generator can address needs for both additional MW and VARs. Additionally, a generator uprate can be used to simply address a need for increased VARs, where there is a system VAR capacity concern in a local grid. In this case, additional VAR capacity can be achieved by upgrading and uprating the generator without impacting the turbine, boiler, or reactor.
The generator is actually a set of sub-systems that should be considered individually to allow a new nameplate with a higher rating to be placed on the generator. The reactive capability curve (RCC) is included in every generator instruction book and represents a good means of picturing how the various sub-systems interact to define the generator capability (see Figure 1). Common sub-systems are listed in Table 1 along with some key uprate considerations.
The method of cooling the generator plays a key role in the uprate evaluation. Generators can be segregated into two basic cooling methods for the stator and rotor windings:
1. Direct cooling — The cooling fluid such as air, hydrogen or water comes in direct contact with the copper conductors and extracts the losses and transports the heat to heat exchangers. The fluid flows through cooling passages in the conductors.
2. Indirect cooling — The heat generated in the conductors should first flow through the conductor insulation. The cooling fluid, air or hydrogen indirectly cools the conductors by cooling the stator core or rotor shaft that is in contact with the exterior of the insulated conductors.
An uprate evaluation for an indirect-cooled stator winding will focus on the insulation thermal capability as defined by industry standards and an uprate may push the winding temperatures closer to – or beyond – temperature limits. A replacement winding with a new, more highly-rated insulation system may be warranted. A direct-cooled stator winding is often cooled by water flowing through hollow copper conductors for the largest power producing generators. The combination of solid and hollow strands in the stator bar can be engineered to obtain more current-carrying capability while maintaining adequate water cooling.
Vibratory mechanical forces on the stator winding (at twice the electrical frequency) will increase by the square of the percent increase in generator kVA, just like the losses and heating of the conductors. The mechanical support system of the stator winding in the slots of the stator is assessed to determine its ability to accommodate an uprate. In some cases, laboratory testing is necessary for validation of new product limits or technology advances.
Outage time constraints and economics generally preclude replacing the generator stator core as part of an uprate. Even if the stator winding is replaced, the core may represent a pinch point for the overall generator uprate. The highest temperatures of the stator core will occur in the ends of the core in the under-excited (“leading”) power factor realm; axial flux densities are highest for leading power factors. (Refer to Fig. 1.) The core end profiles and other features like splits of the teeth help to reduce the heating caused by axial flux. Statistical core-end test data from generators with the different core end structures allows the capability of the core end region to be assessed for an uprate. An OEM should be the most accurate source of generator test data to allow analytical methods to be properly calibrated.
As discussed previously, VAR requirements by the power system may require the field winding to carry higher field current and the increased losses must be rejected to generator heat exchangers. An uprate study will assess the capability of the existing winding to accommodate the higher current and in some cases a more effective cooling approach may be required to maintain acceptable temperatures. Conversion from indirect to direct cooling is very effective and will require that a new rotor be procured. A replacement rotor may be beneficial for other reasons:
1. A new field can be installed faster than a rotor rewind during a short outage
2. A new rotor may allow a fleet of identical fields to be rewound off critical path of the outage schedules. Higher capability of a direct-cooled field winding may also be accomplished by rewinding the existing rotor with a new field winding. A wide variety of different cooling approaches have been used over the years. Modern analytical tools calibrated with data from tests of full-size rotors are used to determine the uprate capability of a field winding.
The ability to uprate an existing field winding is also impacted by existing conditions such as:
An uprate assessment initially assumes that all components are in the “as new” condition. Reliability issues associated with the age of components and technical service notices should be considered. Testing and inspecting all major generator components is strongly recommended, allowing the owner and the OEM to assess the impact of the additional demands placed on the generator components by the power uprate.
The mechanical uprate evaluation of the rotor focuses on the shaft, coupling and coupling hardware the rotor mechanical components affected by a generator uprate. The torque carrying capability of the shaft and coupling hardware is assessed along with the torque loads these parts will see under steady state operation and transient torque events.
Generator uprates are often implemented as part of life extension efforts for the field and stator windings. The required upgrades of the windings needed for an uprate would be incorporated into the configuration of the new windings and their insulation systems.
A generator uprate often impacts the generator heat exchangers (coolers) and excitation system. The coolers are part of the overall ventilation system. Therefore, evaluating the capability of the existing coolers may not suffice; a new cooler configuration and its impact on the ventilation scheme of the generator may need to be evaluated in some cases. The need to uprate the excitation system will be driven by requirements by the transmission company or independent system operator (ISO) to maintain the original power factor and to increase generator VAR output. A large variety of excitation systems, both rotating and static, are used with generators and each represents a unique assessment. For a rotating system, the rotating exciter is essentially a small generator and the same uprate issues as the main generator must be addressed. The technology of controls and rectifiers may be obsolete and replacing the controls with modern digital technology may be required.
Simple and combined cycle gas turbines are frequently upgraded and uprated. The power output of the gas turbine and the generator increases as the ambient temperature decreases. For an uprate capability assessment, the generator and its auxiliaries must be evaluated for all ambient conditions: hot, cold and rated days. For example, on cold days, the generator should provide higher power. Since the generator coolers are also likely providing colder cooling gas to the generator, this is often less of a technical concern. For hotter days, the capability of the generator coolers, the off-base cooling skid (Figure 3), or cooling tower may represent a rating “pinch-point.” Or, one of the other systems like the isolated phase bus, step-up transformer, generator collector system, or excitation system may represent the pinch point for an uprate for either hot or cold day operation. The uprate capability of the systems surrounding the generator as a consideration in any uprate study.
Power plant uprates often involve changes to the overall rotor train such as new turbine rotors or a new generator field. Such changes can impact torsional response and the torsional stresses imposed on the generator rotor and other train components by transient events like full load rejections. Torsional and lateral natural frequencies of the rotor train may also be altered by train modifications and may end up too close to running frequencies. The OEM can best model and analyze the overall torsional and lateral response of a modified rotor train. It can suggest ways to mitigate the risk of failure of rotor train components, particularly the turbine buckets.
Some key deliverables should be expected from a generator uprate project. Top on the list, of course, are a new nameplate and the upgrades to various sub-systems needed to achieve the higher output. In addition, a full generator uprate project would include new performance curves, reactances and time constants, as well as operating settings and parameters for the excitation system, heat exchangers and other equipment that’s been upgraded. Uprate evaluations that are focused only at the stator winding or field, for example, may fall short of meeting the needs of power plant owner executing a plant uprate project. For example, updated data for power system modeling is often requested by the regional ISO and is often provided as part of the project.
A plant owner considering a plant uprate should be cognizant of the technical challenges and risks associated with increasing the power output of an existing generator that could be up to three to four decades old. A significant percentage of the world’s power-producing generators have been in service for more than 25 years. Increased electromagnetic forces, mechanical forces and temperatures are the key technical obstacles that must be surmounted when asking an older generator to produce more power. Enhancements leveraging modern technology can allow power plant owners to take advantage of higher power output while extending the life of the equipment. Advances in engineering and manufacturing processes, testing, and validation enable operation at elevated levels that could not be realized when these generators were first commissioned. The flange-to-flange generator is central to the evaluation but other systems like the exciter and heat exchangers should be assessed as well. Through the evaluation of the various generator sub-systems and through the application of modern technology, uprates of generators among today’s fleet can be achieved.
Jeff Muha, Generator Technical Leader, GE Power & Water — Power Generation Products; Kirk O’Brien, Generator Principal Engineer, GE Power & Water — Power Generation Services
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