Types of Electrical System Interfaces: 3 Types | Electrical Engineering

The main types of electrical system interfaces are: 1. Synchronous Machines 2. Asynchronous (Induction) Machines 3. Electronic Power Inverters.

Type # 1. Synchronous Machines:

Even though synchronous machines use old technology, are common on power systems, and are well understood, there are some concerns when they are applied in grid parallel Distributed Generation applications. They are the primary type of electric machine used in backup generation applications. With proper field and governor control, the machine can follow any load within its design capability.

The inherent inertia allows it to be tolerant of step-load changes. While this is good for backup power, it is the source of much concern to utility distribution engineers because this technology can easily sustain inadvertent islands that could occur when the utility feeder breaker opens. It also can feed faults and possibly interfere with utility overcurrent protection.

Unless the machines are large relative to system capacity, interconnected synchronous generators on distribution systems are usually operated with a constant power factor or constant var exciter control.

a. For one thing, small Distributed Generation does not have sufficient capacity to regulate the voltage while interconnected. Attempting to do so would generally result in the exciter going to either of the two extremes.

b. Secondly, this avoids having the voltage controls of several small machines competing with each other and the utility voltage regulation scheme.

c. A third reason this is done is to reduce the chances that an inadvertent island will be sustained. A nearly exact match of the load at the time of separation would have to exist for the island to escape detection.

It is possible for a synchronous machine that is large relative to the capacity of the system at the PCC to regulate the utility system voltage. This can be a power quality advantage in certain weak systems. However, this type of system should be carefully studied and coordinated with the utility system protection and voltage regulation equipment. It would be possible to permit only one generator on each substation bus to operate in this fashion without adding elaborate controls.

The generation will likely take over voltage regulation and can drive voltage regulators to undesirable tap positions. Conversely, utility voltage regulators can drive the generator exciter to undesirable set points. To ensure detection of utility-side faults when the interconnected generator is being operated under automatic voltage control, many utilities will require a direct transfer trip between the utility breaker and the generation interconnection breaker.

One aspect of synchronous generators that is often overlooked is their impedance. Compared to the utility electrical power system, generators sized for typical backup power purposes have high impedances. The sub-transient reactance X_d“, which is seen by harmonics, is often about 15 percent of the machine’s rating. The transient reactance, X_d‘, which governs much of the fault contribution, might be around 25 percent.

The synchronous reactance X_d is generally over 100 percent. In contrast, the impedance of the power system seen from the main load bus is generally only 5 to 6 percent of the service transformer rating, which is normally larger than the machine rating. Thus, end users expecting a relatively seamless transfer from interconnected operation to isolated backup operation are often disappointed.

Some examples of unexpected consequences are:

a. The voltage sag when elevator motors are being started causes fluorescent lamps to extinguish.

b. The harmonic voltage distortion increases to intolerable levels when the generator is attempting to supply adjustable-speed-drive loads.

c. There is not enough fault current to trip breakers or blow fuses that were sized based on the power system contribution.

Generators must be sized considerably larger than the load to achieve satisfactory power quality in isolated operation.

Another aspect that is often overlooked is that the voltage waveform produced by a synchronous machine is not perfect. In certain designs, there are considerable third-harmonic currents in the voltage. Utility central station generation may also have this imperfection, but the delta winding of the unit step-up transformer blocks the flow of this harmonic. The service transformer connection for many potential end-user.

Distributed Generation locations is not configured to do this and will result in high third-harmonic currents flowing in the generator and, possibly, onto the utility system. The net-result is that synchronous generators for grid parallel Distributed Generation applications should generally be designed with a 2/3 winding pitch to minimize the third-harmonic component. Otherwise, special attention must be given to the interface transformer connection, or additional equipment such as a neutral reactor and shorting switch must be installed.

Type # 2. Asynchronous (Induction) Machines:

Induction generators are induction motors that are driven slightly faster than synchronous speed. They require another source to provide excitation, which greatly reduces the chances of inadvertent islanding. No special synchronizing equipment is necessary. In fact, if the capacity of the electrical power system permits, induction generators can be started across the line.

For weaker systems, the prime mover is started and brought to near-synchronous speed before the machine is interconnected. There will be an inrush transient upon closure, but this would be relatively minor in comparison to starting from a standstill across the line.

The requirements for operating an induction generator are essentially the same as for operating an induction motor of the same size. The chief issue is that a simple induction generator requires reactive power (vars) to excite the machine from the power system to which it is connected.

Occasionally, this is an advantage when there are high-voltage problems, but more commonly there will be low-voltage problems in induction generator applications. The usual fix is to add power factor correction capacitors to supply the reactive power locally.

While this works well most of the time, it can bring about another set of power quality problems:

i. One of the problems is that the capacitor bank will yield resonances that coincide with harmonics produced in the same facility.

ii. Another issue is self-excitation.

An induction generator that is suddenly isolated on a capacitor bank can continue to generate for some period of time. This is an unregulated voltage and will likely deviate outside the normal range quickly and be detected. However, this situation can often result in a ferroresonant condition with damaging voltages.

Induction generators that can become isolated on capacitor banks and load that is less than 3 times rated power are usually required to have instantaneous overvoltage relaying. One myth surrounding induction generators is that they do not feed into utility-side faults. Most are SLG faults, and the voltage on the faulted phase does not collapse to zero. In fact, generators served by delta-wye transformers may detect very little disturbance in the voltage.

There are many complex dynamics occurring within the machine during unbalanced faults, and a detailed electromagnetic transient’s analysis is needed to compute them precisely. A common rule of thumb is that if the voltage supplying the induction machine remains higher than 60 percent, assume that it will continue to feed into the fault as if it were a synchronous machine. This voltage level is sufficient to maintain excitation levels within the machine.

Type # 3. Electronic Power Inverters:

All Distributed Generation technologies that generate either dc or non-power frequency ac must use an electronic power inverter to interface with the electrical power system.

The early thyristor-based, line-commutated inverters quickly developed a reputation for being undesirable on the power system. In fact, the development of much of the harmonics analysis technology was triggered by proposals to install hundreds of rooftop photovoltaic solar arrays with line-commutated inverters. These inverters produced harmonic currents in similar proportion to loads with traditional thyristor-based converters. Besides contributing to the distortion on the feeders, one fear was that this type of Distributed Generation would produce a significant amount of power at the harmonic frequencies. Such power does little more than heat up wires.

To achieve better control and to avoid harmonics problems, the inverter technology has changed to switched, pulse-width modulated technologies. This has resulted in a friendlier interface to the electrical power system.

Figure 6.5 shows the basic components of a utility interactive inverter that meets the requirements of IEEE Standard 929-2000.5 Direct current is supplied on the left side of the diagram either from a conversion technology that produces direct current directly or from the rectification of ac generator output. Variations of this type of inverter are commonly employed on fuel cells, micro-turbines, photovoltaic solar systems, and some wind turbines.

The dc voltage is switched at a very high rate with an insulated gate bipolar transistor (IGBT) switch to create a sinusoid voltage or current of power frequency. The switching frequency is typically on the order of 50 to 100 times the power frequency. The filter on the output attenuates these high-frequency components to a degree that they are usually negligible.

However, resonant conditions on the power system can sometimes make these high frequencies noticeable. The largest low-order harmonic (usually, the fifth) is generally less than 3 percent, and the others are often negligible. The total harmonic distortion limit is 5 percent, based on the requirements of IEEE Standard 519-1992.

While interconnected to the utility, commonly applied inverters basically attempt to generate a sine-wave current that follows the voltage waveform. Thus, they would produce power at unity power factor. It is possible to program other strategies into the switching control, but the unity power factor strategy is the simplest and most common. Also, it allows the full current-carrying capability of the switch to be used for delivering active power (watts). If the inverter has stand-alone capability, the control objective would change to producing a sinusoidal voltage waveform at power frequency and the current would follow the load.

One of the advantages of such an inverter for Distributed Generation applications is that:

i. It can be switched off very quickly when trouble is detected.

There may be some lag in determining that something has gone wrong, particularly if there are synchronous machines with substantial inertia maintaining the voltage on the system. When a disturbance requiring disconnection is detected, the switching simply ceases. Inverters typically exhibit very little inertia and changes can take place in milliseconds.

Rotating machines may require several cycles to respond. It may be possible to reclose out of phase on inverters without damage provided current surge limits in the semiconductor switches are not exceeded. Thus, reconnection and resynchronization are less of an issue than with synchronous machines.

The ability of inverters to feed utility-side faults is usually limited by the maximum current capability of the IGBT switches. Analysis commonly assume that the current will be limited to 2 times the rated output of the inverter. Of course, once the current reaches these values, the inverter will likely assume a fault and cease operation for a predetermined time. This can be an advantage for utility interactive operation but can also be a disadvantage for applications requiring a certain amount of fault current to trip relays.

If the inverter system is suddenly isolated on load, the frequency will quickly deviate, allowing it to be detected both within the control and by external relays.