Correcting Power Factor in Cogen

Pre-packaged cogeneration systems are increasingly popular for commercial and institutional facilities. For systems that are under 100 kilowatts (kW) and powered by reciprocating engines—and for some microturbines—the normal electrical design approach is to utilize an induction-type generator, wired in parallel to a building's three-phase circuits.

By Syed M. Peeran, Ph.D., P.E., WB Engineering & Consulting, PLLC Woburn, Mass., Robert A. Panora, President, Tecogen, Inc. and Joseph B. Gehret, Jr. Principal Engineer, Tecogen, Inc. Waltham, Mass. June 1, 2002

Pre-packaged cogeneration systems are increasingly popular for commercial and institutional facilities. For systems that are under 100 kilowatts (kW) and powered by reciprocating engines—and for some microturbines—the normal electrical design approach is to utilize an induction-type generator, wired in parallel to a building’s three-phase circuits.

Moreover, there are strong incentives for cogeneration suppliers to include capacitors for power-factor correction with the induction generators. But the introduction of capacitors into the circuits creates the possibility of self-excitation of the generator during a power outage. Even so, as long as certain basic engineering principles are followed, power-factor correction capacitors are routinely and safely applied to induction-generator systems. But one must implement the correct design strategy to apply capacitors in a safe and reliable manner.

Induction Preferred

The induction generator is often preferred over the synchronous generator because it is simpler to install—complex synchronizing and reactive power controllers are unnecessary—and its characteristics are less onerous to the utility interconnect engineers. In particular, an isolated induction generator is incapable of operating in an outage, an important feature for power-line worker safety. The advantages are especially apparent when multiple-unit installations are considered, where synchronous-generator control systems become highly complex and too costly for many small-scale projects.

In a typical cogeneration installation (see Figure 1), an induction-type generator is simply an induction motor driven by an engine or turbine at a speed greater than its synchronous speed. For example, a 4-pole 60-Hz induction motor with a full load speed of 1,760 revolutions per minute (rpm) will start working as an induction generator—exporting power—when driven at a speed above 1,800 rpm.

Unlike a synchronous generator, the induction generator has no source of excitation, except the alternating-current mains to which it is connected. Consequently, one characteristic of the induction generator is that it absorbs reactive or “imaginary” power in kVAR, while supplying “real” power in kW. Despite its “imaginary” label, utilities will include a surcharge to the monthly customer invoice for reactive power. The kVAR charge is generally an order of magnitude less than the kW charge. (For a review of the fundamentals, see “Real and Reactive Power Flow,” p. 24.)

Induction Generator

As previously mentioned, an induction motor starts working as a generator when driven at a speed above the synchronous speed. The difference between the actual speed and the synchronous speed is referred to as the slip. Generator action begins when the slip becomes negative. Because there is no source of excitation—a field winding with direct-current excitation or a permanent magnet, as in the case of synchronous generators—the induction generator cannot operate in a stand-alone fashion.

The induction generator is less expensive than a synchronous generator in sizes less than approximately 500 kW. Most industrial induction motors are National Electrical Manufacturers Association (NEMA) Design B motors. If Design B motors were used as induction generators, they would be less efficient than their synchronous counterparts because of rotor copper losses. However, when an induction machine is intended for generator operation, a NEMA Design A or even a premium efficiency type can be used, which improves the efficiency to about 94%—which is on par with high-quality synchronous generators. These high-efficiency induction motor/generators will operate at a lower value of slip than the Design B units.

A look at the power and reactive power characteristics of a typical induction generator (see Figure 2, p. 25) shows that when the speed increases above synchronous, the real power changes from negative to positive, indicating a change from motor operation to generator operation. However, the reactive power does not change sign. This means that in the generating region, even though the machine supplies positive kW to the bus, it absorbs kVAR just like an induction motor. For this reason, the induction generator would reduce the power factor of the total facility load.

The Typical 75-kW Cogenerator

This problem can be illustrated by considering a typical 75-kW induction cogenerator installation in a facility where the load changes from 100 to 1,000 kW. A 1,800-rpm, natural-gas-fired engine drives a 75-kW, three-phase, 480-volt, 60-Hz induction generator. The engine controller is set up to adjust the speed so that the generator power output is the rated output of the unit. The unit supplies 25 gallons of hot water per hour at a temperature of 210°F.

A microprocessor controller monitors the voltage and frequency at the terminals of the generator (see Figure 3, p. 25).

If either is found to be outside a preset band, the generator contactor (M) is tripped. The capacitor contactor (S) is also tripped by means of an auxiliary contact of M. The unit is equipped with anti-islanding software, which trips out the unit in the event of a sustained self-excitation operation.

The induction generator has a rated power factor of 0.84. When tested as an induction motor, it has a no-load current of 31 amps. This means that the reactive power demand is 26 kVAR at no-load and 48 kVAR at full load. A capacitor of rating Qc is supplied by the cogenerator vendor for power factor improvement. The capacitor rating depends upon the desired power factor. The maximum rating should be less than the reactive power demand of the generator at full load—in this case, 48 kVAR. This would prevent self-excitation of the generator when the utility power is lost, provided there aren’t any other capacitors in the facility.

The real and reactive power flow balance is indicated by the following equations:

P U = P L – P G

Q U = Q L + Q G – Q C

The power factor of the input from the utility is given by

PF U = COS (ATAN(Q U /P U ))

If there are any capacitors for power-factor correction in the facility, then there can be excessive capacitive kVAR at times of light load. This situation can lead to self-excitation of the cogenerator. The generator control system is equipped with a means to take the generator out of a sustained self-excited operation and trip out the unit.


Self-excitation is a phenomenon that causes the induction generator, in conjunction with capacitance in the circuit and while isolated from the utility, to develop a voltage and function as a stand-alone generator. While this is normal operation for synchronous generators, it is undesirable for induction generators, because the latter are unequipped to control the voltage level. Without any controlling device or safety relaying, the voltage could become excessive, beyond the rating of the equipment.

The simultaneous criteria for an induction generator to self-excite are: the unit has become isolated from the utility; there is a capacitive load on the generator; and the capacitive kVAR of the load is in excess of the magnetizing kVAR.

As the machine is driven at some speed, the residual magnetism in the rotor iron induces a small voltage in the stator windings. This voltage causes a leading power-factor current to flow because of the capacitive load. This leading current flowing in the machine reactance causes an increase in the voltage at the terminals of the capacitor, known as the Ferranti effect. The increased voltage causes increased current, which further increases the voltage. There is, therefore, a positive feedback situation that causes escalation of the voltage and is limited only by magnetic saturation. The steady-state voltage due to self-excitation is determined by, and is highly sensitive to, the capacitive kVAR.

The classic scenario for self-excitation occurs when a facility in which a cogeneration unit is operating suffers a power failure, isolating the unit to a group of loads. If the loads include a set of power-factor correction capacitors, subsequent events may play out in one of these five scenarios:

If the isolated loads on the generator exceed the power capability of the prime mover, the generator’s speed—and therefore frequency—will decrease. The cogeneration unit’s under-frequency alarms will detect the situation and take the unit off-line, although the engine will likely stall in any case. This is by far the most likely scenario.

If the loads are less than the kW set-point of the unit, the engine will increase in rpm as it attempts to meet set-point. The onboard safeties for over-frequency or over-speed will trip the unit off-line.

If the loads exactly match the cogeneration unit’s set-point—that is, in the 75-kW example, they are exactly 75 kW—but the kVAR required by the loads and generator overtax the capacitors, then the voltage will decay, causing the low-voltage safety to take the unit off-line.

If the loads exactly match the cogeneration unit’s set-point, but the kVAR required by the loads and generator is less than the capacitor’s rating, then the voltage will increase, causing the over-voltage safety to take the unit off-line.

If the loads exactly match the cogeneration unit’s set-point, and the capacitance exactly matches that required for the loads and generator, then operation in a self-excitation mode would theoretically occur. While it is extremely unlikely that both of these parameters would exactly balance, it is virtually impossible that they would do so for any length of time, because any load change in the building would upset the very delicate equilibrium. To guard against even this minuscule probability, the anti-islanding software causes a small perturbation in the engine speed. Because the unit is isolated and operating as a stand-alone generator, an increase in the speed would produce an increase in the frequency, as well as in the voltage. Over-frequency and over-voltage protection would be actuated to trip out the unit.

As these examples illustrate, safe operation of an induction generator with power-factor correction capacitors first requires that the unit be equipped with fast-acting over/under safeties for both frequency and voltage. Moreover, these safeties should be designed to electrically isolate the capacitors and generator from the bus and from each other, as well as stopping the prime mover.

Secondly, and to avoid the fourth scenario above, the capacitor’s kVAR rating should be selected to be somewhat less than the generator requires, correcting to about 95% power factor, in which case scenario five becomes scenario three.

Most cogeneration units supplied by reputable manufacturers have built-in microprocessors that sense frequency and voltage and will safely disconnect the generator and capacitors in the event of an outage. This on-board approach to relaying has the very important advantage of being integral to the unit, making operation without oversight impossible.

Moreover, the power-factor capacitors can be brought on line in a pre-programmed sequence that follows the power output of the unit. When the power is low and less kVAR is needed, they can be taken off-line to avoid a near unity power factor. Additionally, this integrated approach allows anti-islanding algorithms to be added to the control strategy.

Because of the important duty of the utility safety relaying system, these devices should be backed by an independent test laboratory relative to a national relaying standard. For distributed generation systems, this standard is the IEEE’s proposed P1547, which encompasses a number of technologies including induction generators. Equipment properly certified to this standard will have certified trip settings and assurances of reliability even under adverse conditions.

From Pure Power, Summer 2002.

Real and Reactive Power Flow

Real power flow (measured in kW) is real in the sense that there is actually a flow of energy from the source to the load. The source is a device that converts an available source of energy—gas, oil, water, nuclear, heat or light—to electrical energy. The load is a device that absorbs electrical energy and converts it to some other form of energy, such as rotational kinetic energy, as in the case of electric motors, or to heat, as in heaters. The flow of real power in a conductor results in some power loss, but not necessarily a voltage drop. The power loss manifests itself as heat in the conductor.

But in the case of reactive power, there is really no flow of any kind. In fact, reactive power (measured in kvar) is an artifice used to link the kVA, kW and power factor. It is defined as:

kvar = (kVA

Although the “flow” of reactive power is imaginary, it is a useful concept in the analysis of electrical systems. Flow of reactive power from point A to point B results in a voltage drop from A to B.

The sign of reactive power flow is arbitrary. An accepted convention about positive and negative reactive power flow is shown in the figure at left.

It is useful to remember that there is always a balance between reactive power generation and absorption, just as in the case of real power.