GENERATOR TYPE SELECTION FOR HYDROELECTRIC POWER PLANTS BASIC AND TUTORIALS

Synchronous generators and induction generators are used to convert the mechanical energy output of the turbine to electrical energy. Induction generators are used in small hydroelectric applications (less than 5 MVA) due to their lower cost which results from elimination of the exciter, voltage regulator, and synchronizer associated with synchronous generators.

The induction generator draws its excitation current from the electrical system and thus cannot be used in an isolated power system. Also, it cannot provide controllable reactive power or voltage control and thus its application is relatively limited.

The majority of hydroelectric installations utilize salient pole synchronous generators. Salient pole machines are used because the hydraulic turbine operates at low speeds, requiring a relatively large number of field poles to produce the rated frequency.

A rotor with salient poles is mechanically better suited for low-speed operation, compared to round rotor machines which are applied in horizontal axis high-speed turbo-generators.

Generally, hydroelectric generators are rated on a continuous-duty basis to deliver net kVA output at a rated speed, frequency, voltage, and power factor and under specified service conditions including the temperature of the cooling medium (air or direct water). Industry standards specify the allowable temperature rise of generator components (above the coolant temperature) that are dependent on the voltage rating and class of insulation of the windings (ANSI, C50.12-1982; IEC, 60034-1).

The generator capability curve, describes the maximum real and reactive power output limits at rated voltage within which the generator rating will not be exceeded with respect to stator and rotor heating and other limits. Standards also provide guidance on short circuit capabilities and continuous and short-time current unbalance requirements (ANSI, C50.12-1982; IEEE, 492-1999).

Synchronous generators require direct current field excitation to the rotor, provided by the excitation system described in Section entitled “Excitation System”. The generator saturation curve, describes the relationship of terminal voltage, stator current, and field current.

While the generator may be vertical or horizontal, the majority of new installations are vertical. The basic components of a vertical generator are the stator (frame, magnetic core, and windings), rotor (shaft, thrust block, spider, rim, and field poles with windings), thrust bearing, one or two guide bearings, upper and lower brackets for the support of bearings and other components, and sole plates which are bolted to the foundation.

Other components may include a direct connected exciter, speed signal generator, rotor brakes, rotor jacks, and ventilation systems with surface air coolers (IEEE, 1095-1989).

The stator core is composed of stacked steel laminations attached to the stator frame. The stator winding may consist of single turn or multi-turn coils or half-turn bars, connected in series to form a three phase circuit.

Double layer windings, consisting of two coils per slot, are most common. One or more circuits are connected in parallel to form a complete phase winding. The stator winding is normally connected in wye configuration, with the neutral grounded through one of a number of alternative methods which depend on the amount of phase-to-ground fault current that is permitted to flow (IEEE, C62.92.2-1989; C37.101-1993).

Generator output voltages range from approximately 480 VAC to 22 kVAC line-to-line, depending on the MVA rating of the unit. Temperature detectors are installed between coils in a number of stator slots.

The rotor is normally comprised of a spider attached to the shaft, a rim constructed of solid steel or laminated rings, and field poles attached to the rim. The rotor construction will vary significantly depending on the shaft and bearing system, unit speed, ventilation type, rotor dimensions, and characteristics of the driving hydraulic turbine.

Damper windings or amortisseurs in the form of copper or brass rods are embedded in the pole faces, for damping rotor speed oscillations. The thrust bearing supports the mass of both the generator and turbine plus the hydraulic thrust imposed on the turbine runner and is located either above the rotor (“suspended unit”) or below the rotor (“umbrella unit”).

Thrust bearings are constructed of oil-lubricated, segmented, babbit-lined shoes. One or two oil lubricated generator guide bearings are used to restrain the radial movement of the shaft.

Fire protection systems are normally installed to detect combustion products in the generator enclosure, initiate rapid de-energization of the generator and release extinguishing material. Carbon dioxide and water are commonly used as the fire quenching medium.

Excessive unit vibrations may result from mechanical or magnetic unbalance. Vibration monitoring devices such as proximity probes to detect shaft run-out are provided to initiate alarms and unit shutdown.

The choice of generator inertia is an important consideration in the design of a hydroelectric plant. The speed rise of the turbine-generator unit under load rejection conditions, caused by the instantaneous disconnection of electrical load, is inversely proportional to the combined inertia of the generator and turbine.

Turbine inertia is normally about 5% of the generator inertia. During design of the plant, unit inertia, effective wicket gate or nozzle closing and opening times, and penstock dimensions are optimized to control the pressure fluctuations in the penstock and speed variations of the turbine-generator during load rejection and load acceptance.

Speed variations may be reduced by increasing the generator inertia at added cost. Inertia can be added by increasing the mass of the generator, adjusting the rotor diameter, or by adding a flywheel. The unit inertia also has a significant effect on the transient stability of the electrical system, as this factor influences the rate at which energy can be moved in or out of the generator to control the rotor angle acceleration during system fault conditions.

INDUCTION GENERATORS - GENERAL CHARACTERISTICS BASIC AND TUTORIALS

An induction or asynchronous generator is one that operates without an independent source for its rotor field current, but in which the rotor field current appears by electromagnetic induction from the field of the armature current.

 The rotor field then interacts with the stator field to transmit mechanical torque just as it does in a synchronous generator, regardless of the fact that it was the stator field that created it (the rotor field) in the first place.

This may seem reminiscent of pulling yourself up by your own bootstraps, but it does actually work. The catch is that some armature current must be provided externally; thus, an induction generator cannot be started up without being connected to a live a.c. system. Another practical concern is that, as we show later in this chapter, induction generators can only operate at leading power factors. For both reasons, their use is quite limited.

Their one important application in power systems is in association with wind turbines. In this case, induction generators offer an advantage because they can readily absorb the erratic fluctuations of mechanical power delivered by the wind resource.

They also cost less than synchronous machines, especially in the size range up to one megawatt. In terms of mechanical operation, the most important characteristic of the induction generator is that the rate of rotation is not fixed, as in the case of the synchronous generator, but varies depending on the torque or power delivered.

The reference point is called the synchronous speed, which is the speed of rotation of the armature magnetic field (corresponding to the a.c. frequency) and also the speed at which a synchronous rotor would spin. The more power is being generated, the faster the induction rotor spins in relation to the synchronous speed; the difference is called the slip speed and typically amounts to several percent.

The rotor may also spin more slowly than the armature speed, but in this case, the machine is generating negative power: it is operating as a motor! While induction machines are usually optimized and marketed for only one purpose, either generating or motoring, they are all in principle reversible. (The same is true for synchronous machines, though their design tends to be even more specialized.)

Figure below shows a curve of torque versus slip speed for a generic induction machine. Zero slip corresponds to synchronous speed, and at this point, the machine delivers no power at all: neglecting friction, it spins freely in equilibrium.

This is called a no-load condition. If a forward torque is exerted on the rotor in this equilibrium state (say, by a connected turbine), it accelerates beyond synchronous speed and generates electric power by boosting the terminal voltage. If the rotor is instead restrained (by a mechanical load), it slows down below synchronous speed and the machine is operating as a motor.

Now we call the torque on the rotor negative, and it acts to push whatever is restraining it with power derived from the armature current and voltage.

The synchronous speed of a given induction machine may be equal to the a.c. frequency (3600 rpm for 60 Hz; 3000 rpm for 50 Hz) or some even fraction thereof (such as 900 or 1800 rpm), depending on the number of magnetic poles, which in this case are created by the armature conductor windings instead of the rotor.

Note that unlike the synchronous generator, where the stator magnetic field has two poles but the rotor field may have any even number of poles, an induction generator must have the same number of poles in the rotor and stator field (because there is no independent excitation).