Power Generation Riddle No.3 - Variable speed generators
What defines a variable speed generator, can they be synchronous and asynchronous, as i understand it is that all the term variable speed generator actually means is that the speed can change, which results in the unwanted frequency change, this is taken care of by the converters and inverters (and some other clever electronics) and you have a constant frequency output?

Also is there a difference between the generation aspects of a pumped storage scheme and a normal hydro scheme, there shouldn't be, (apart from the pumping aspect)

#1
Sat, January 15th, 2011 - 19:55
In the following, the most commonly applied variable speed turbine (wind turbine) configurations are classified both by their ability to control speed and by the type of power control they use.
Applying speed control as the criterion, there are four different dominating types of wind turbines, as illustrated in Figure below.

Note:
SCIG=squirrel cage induction generator;
WRIG=wound rotor induction generator;
PMSG=permanent magnet synchronous generator;
WRSG=wound rotor synchronous generator.
The broken line around the gearbox in the Type D configuration indicates that there may or may not be a gearbox

Type A: fixed speed
This configuration denotes the fixed-speed wind turbine with an asynchronous squirrel cage induction generator (SCIG) directly connected to the grid via a transformer (see Figure). Since the SCIG always draws reactive power from the grid, this configuration uses a capacitor bank for reactive power compensation. A smoother grid connection is achieved by using a soft-starter.
Regardless of the power control principle in a fixed-speed wind turbine, the wind fluctuations are converted into mechanical fluctuations and consequently into electrical power fluctuations. In the case of a weak grid, these can yield voltage fluctuations at the point of connection. Because of these voltage fluctuations, the fixed-speed wind turbine draws varying amounts of reactive power from the utility grid (unless there is a capacitor bank), which increases both the voltage fluctuations and the line losses. Thus the main drawbacks of this concept are that it does not support any speed control, it requires a stiff grid and its mechanical construction must be able to tolerate high mechanical stress.

Type B: limited variable speed
This configuration corresponds to the limited variable speed wind turbine with variable generator rotor resistance, known as OptiSlip. It uses a wound rotor induction generator (WRIG) and has been used by the Danish manufacturer Vestas since the mid-1990s. The generator is directly connected to the grid. A capacitor bank performs the reactive power compensation. A smoother grid connection is achieved by using a soft-starter. The unique feature of this concept is that it has a variable additional rotor resistance, which can be changed by an optically controlled converter mounted on the rotor shaft. Thus, the total rotor resistance is controllable. This optical coupling eliminates the need for costly slip rings that need brushes and maintenance. The rotor resistance can be changed and thus controls the slip. This way, the power output in the system is controlled. The range of the dynamic speed control depends on the size of the variable rotor resistance. Typically, the speed range is 0-10%above synchronous speed. The energy coming from the external power conversion unit is dumped as heat loss. Wallace and Oliver (1998) describe an alternative concept using passive components instead of a power electronic converter. This concept achieves a 10% slip, but it does not support a controllable slip.

Type C: variable speed with partial scale frequency converter
This configuration, known as the doubly fed induction generator (DFIG) concept corresponds to the limited variable speed wind turbine with a wound rotor induction generator (WRIG) and partial scale frequency converter (rated at approximately 30% of nominal generator power) on the rotor circuit (Plate 4, in Chapter 2 shows the nacelle of a Type C turbine). The partial scale frequency converter performs the reactive power compensation and the smoother grid connection. It has a wider range of dynamic speed control compared with the OptiSlip, depending on the size of the frequency converter.
Typically, the speed range comprises synchronous speed -40% to +‏30 %. The smaller frequency converter makes this concept attractive from an economical point of view. Its main drawbacks are the use of slip rings and protection in the case of grid faults.

Type D: variable speed with full-scale frequency converter
This configuration corresponds to the full variable speed wind turbine, with the generator connected to the grid through a full-scale frequency converter. The frequency converter performs the reactive power compensation and the smoother grid connection.
The generator can be excited electrically [wound rotor synchronous generator (WRSG) or WRIG) or by a permanent magnet [permanent magnet synchronous generator (PMSG)>.
Some full variable-speed wind turbine systems have no gearbox (see the dotted gearbox in Figure). In these cases, a direct driven multipole generator with a large diameter is used, see Plate 3, in Chapter 2 for instance. The wind turbine companies Enercon, Made and Lagerwey are examples of manufacturers using this configuration.

But about pumped storage hydro power generation:

Pumped storage hydro power production is a means of actually saving electricity for future use. Power is generated from water falling from a higher lake to a lower lake during peak load periods. The operation is reversed during off-peak conditions by pumping the water from the lower lake back to the upper lake. A power company can obtain high-value power during peak-load generation periods by paying the lower cost to pump the water back during off-peak periods. Basically, the machine at the lower level is reversible; hence, it operates as a hydro-generator unit or a motor– pump unit.
One of the problems associated with pumped storage units is the process of getting the pumping motor started. Starting the pumping motor using the system’s power line would usually put a low-voltage sag condition on the power system. The voltage sag or dip could actually cause power quality problems.
In some cases, two turbines are used in a pumped storage installation.
One of the turbines is used as a generator to start the other turbine that is used as a pump. Once the turbine is turning, the impact on the power system is much less, and the second turbine can then be started as a motor–pump.

#2
Tue, January 18th, 2011 - 07:54
Sorry i am unsure how to ask another question asociated with this one, so i am just going to "write an answer",
Firstly thank you so much for your help Hamid, it has really cleared up a few problems.
thought i have a few more questions.

Firstly regarding this "see Plate 3, in Chapter 2 for instance" are you refering to a text book and if so which one?
My second question is, can the wind turbine which you described "Type D" be used for a hydro dam scheme? Also are you aware of any companies which manufacture variable speed generators (for hydro generation (a dam)) in the 40MW region/capacity?
Lastly regading my last question in my initial question, can the generator used in a pumped storage scheme be used in a hydro generation scheme (meaing a lake/dam reservoir)

Regards

Chris

#3
Tue, January 18th, 2011 - 15:49
1-Yes, I used following text books.
a-Wind Power in Power Systems
Edited by
Thomas Ackermann
Royal Institute of Technology
Stockholm, Sweden

b-Electric Power System Basics
For the Nonelectrical Professional
Steven W. Blume

2- Fundamentally the wound rotor synchronous generator (WRSG) type can be used in both system but there are many electrical and mechanical characteristics difference between hydro generator and synchronize generator which can be used in mentioned type D configuration. Also induction electrical machine operating in motor/generator conditions can be use in wind power plant and pumped hydro power generation system; because in both them bidirectional power flow is necessary. Conventional pumped hydro uses two water reservoirs, separated vertically. During off peak hours water is pumped from the lower reservoir to the upper reservoir. When required, the water flow is reversed to generate electricity. Some high dam hydro plants have a storage capability and can be dispatched as a pumped hydro. Underground pumped storage, using flooded mine shafts or other cavities, are also technically possible. Wind turbine in 40MW range is not applicable, however it seems using type A, B configuration in pumped hydro generation is possible theoretically.
The WRSG which applied in wind power plant (type D) is the workhorse of the electrical power industry. Both the steady-state performance and the fault performance have been well-documented in a multitude of research papers over the years, (see L. H. Hansen et al., 2001).
The stator windings of WRSGs are connected directly to the grid and hence the rotational speed is strictly fixed by the frequency of the supply grid. The rotor winding is excited with direct current using slip rings and brushes or with a brushless exciter with a rotating rectifier. Unlike the induction generator, the synchronous generator does not need any further reactive power compensation system. The rotor winding, through which direct current flows, generates the exciter field, which rotates with synchronous speed. The speed of the synchronous generator is determined by the frequency of the rotating field and by the number of pole pairs of the rotor.
The wind turbine manufacturers Enercon and Lagerwey use the wind turbine concept Type D with a multipole (low-speed) WRSG and no gearbox. It has the advantage that it does not need a gearbox.

Since waterwheel generators are custom designed to match the hydraulic turbine prime mover, many of the generator characteristics (e.g., short-circuit ratio, reactances) can be varied over a fairly wide range, depending on design limitations, to suit specific plant requirements and power distribution system stability needs. Deviations from the nominal generator design parameters can have a significant effect on cost, so a careful evaluation of special features should be made and only used in the design if their need justifies the increased cost.
The electrical and mechanical design of each generator must conform to the electrical requirements of the power distribution system to which it will be connected, and also to the hydraulic requirements of its specific plant.
The voltage of large, slow speed generators should be as high as the economy of machine design and the availability of switching equipment permits. Generators with voltage ratings in excess of 16.5 kV have been furnished, but except in special cases, manufacturing practices generally dictate an upper voltage limit of 13.8 kV for machines up through 250 MVA rating. Based on required generator reactance, size, and Wk2, a lower generator voltage, such as 6.9 kV, may be necessary or prove to be more economical than higher voltages. If the generators are to serve an established distribution system at generator voltage, then the system voltage will influence the selection of generator voltage, and may dictate the selection and arrangement of generator leads also.
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; 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; IEEE, 492).
Synchronous generators require direct current field excitation to the rotor, provided by the excitation system described in the 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).
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 that depend on the amount of phase-to-ground fault current that is permitted to flow (IEEE, C62.92.2, C37.101). 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 frame 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.

3- In modern pumped hydro power plant the power generator type opposite in dam hydro power plant is induction generator.Generally Variable-speed motor-generators allow operation of the pump-turbine unit over a wider range of head and flow, making them economically advantageous for a pumped-storage facility.
The 1,060-mw Goldisthal pumped-storage plant on the Schwarza River is the biggest hydroelectric project in Germany and the most modern in Europe. It is an important component of Vattenfall Europe Generation AG & Co. KG’s generation capacity. Construction on the project began in September 1997, and the plant started commercial operation in October 2004.
The Goldisthal project is unique in that two of the four vertical Francis pump-turbine units feature variable-speed (asynchronous) motor-generators. This arrangement provides several benefits for Vattenfall Europe, including: power regulation during pumping operation, improved efficiency at partial load conditions, and high dynamic control of the power delivered, for stabilization of the grid.
The most important innovation at the Goldisthal project is the first-ever application of variable-speed motor-generators of this size in a hydro plant in Europe. In essence, turbines have one optimum operating point in terms of head, flow, unit size, and speed. But when these units are coupled with a variable-speed motor-generator, operating speed can be varied over a certain range of the nominal synchronous speed of the turbine-generating unit. As head and flow vary, the unit is able to increase or decrease its speed to operate closer to peak efficiency for this unique set of conditions.
The difference between synchronous and asynchronous machines is the rotor. While classical synchronous generators have salient poles, variable-speed generators have a three-phase winding on the rotor. And while the synchronous rotor is energized by a direct current (DC) to create a rotating magnetic field, the asynchronous rotor is energized by a low-frequency alternating current (AC). A direct frequency converter in the rotor circuit is used to control the frequency. If the frequency is changed, so too is the speed of the unit.
The rotor can be retarded or accelerated opposite the stator field, from 90 to 104 percent of the synchronous speed. The variable frequency of the asynchronous generators at Goldisthal ranges from 5 Hertz (Hz) opposite the stator field of 333 revolutions per minute (rpm) (which provides 300 rpm) to 0.01 Hz (which is nearly the rated speed of the unit) to 2 Hz additional to the stator field (which provides 340 rpm).
Asynchronous motor-generators provide several advantages, including:
• More flexibility in their operation;
• Higher efficiency over a wide range of operations at partial load conditions;
• A wide range of controllable and optimized power consumption in pump operation;
• Additional and faster features for grid control, such as fast power outlet regulation;
• Better use of the reservoir because higher water level variations can be allowed; and
• Better contribution to grid stability because of the high moment of inertia of the rotating masses.