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induction generation

An induction generator operates on principles identical to an ac induction motor, except that in normal operation it has a speed of rotation slightly greater than the synchronous speed of the 60 Hz power system. The induction generator, because it has “slip” in relation to the 60 Hz utility system voltage, is often referred to as an “Asynchronous” generator” because it is never quite synchronized with the utility (Company’s) distribution system. Induction generators do not have an exciter and they can not normally sustain a stable island on their own so they are not used for generator plants that must provide power on a stand alone basis. They are, however, commonly used in power plants that only need to operate in parallel with another source (such as the utility system).

In general, induction generators have unique characteristics as follows: Induction generators operate in an asynchronous fashion with respect to the utility system voltage so when first connecting to the Company’s distribution system it does not require precise alignment of frequency and phase angle. However, speed matching to near synchronous speed may still be required for some cases.

The design of the induction generator (its lack of an exciter) makes it less likely to pose an islanding risk to the Company’s system than a synchronous generator. On the other hand, self-excitation still can occur in some special cases (causing ferroresonance) so the threat of islanding is not entirely removed and must be addressed as part of any induction generator interface design package.

Induction generators gather the excitation current they need from the utility system (Company’s system) thereby consuming considerable reactive power from the system. This causes voltage drop and increased losses on the distribution system. In situations where system losses and voltage drop are significant, the induction generator may need provisions to correct its power factor to near unity.

Induction generators can not sustain an appreciable fault current for a fault at their terminals for a long time due to the collapse of excitation source voltage during the fault. However, they will inject a large amount of current for a short transient period of time and this can impact the power system. Because of the characteristics of the induction generator described above, its protection and interface is somewhat different than that of the synchronous generator.

Induction generators may be connected to the distribution system and brought from a standstill up to synchronous speed (just as an induction motor is) if it can be demonstrated that the initial voltage drop measured at the point of common coupling is acceptable based on current inrush limits. The same requirements also apply to induction generators connected at or near synchronous speed using a speed matching relay approach because a voltage dip is present due to an inrush of magnetizing current even when the unit is connected at or near synchronous speed (albeit of shorter duration than starting from a standstill condition).

In order to assess voltage flicker, the expected number of starts per hour and maximum starting kVA draw data will need to be delivered to the utility company to verify that the voltage dip due to starting is within the acceptable flicker limits according to IEEE 519-1992 and, where applicable the Con Edison flicker curve requirements (see Graph 1).

Starting or rapid load fluctuations on induction generators can adversely impact the Company’s distribution system voltage and cause noticeable voltage quality problems for customers on the circuit. Corrective steps include usage of switched capacitors or other techniques may be needed to mitigate the voltage flicker and regulation issues that arise. These measures can, in turn, cause ferroresonance, which is a serious form of over-voltage condition that can damage equipment and loads on the system. If the customer’s design includes additional capacitors installed on the customer side of the PCC, the Company will review these measures and may require the customer to install additional equipment to reduce the risk of ferroresonance. Customers who provide capacitor banks to minimize the voltage drop on the bus during starting of the generator, shall provide a way to automatically disconnect them from the generator terminals after the start up. The customer shall perform and submit studies to demonstrate the impact of the capacitors on the system.

Induction generators, unless corrected with capacitors, operate at relatively poor power factor due to the reactive excitation current drawn from the Company’s power system. For induction generators falling within the 0 to 2 MW SIR guidelines, if the average power factor of the customer (including the effects of the generator current), as measured at the PCC is less than 0.9, then the method of power factor correction necessitated by the installation of the generator, if any, will be negotiated with the utility as a commercial item. For Reactive Power (VAR) requirements, the customers shall refer to the applicable Company’s rate “Service Classification” under the Special Provisions section to determine the kilovar charges. For induction generators larger than 2 MW, the Company will negotiate with the customer the reactive requirements of the machine and expected power factor performance. Regardless of generator size, use of power factor correction capacitors must be approved by the utility to insure that issues related to self-excitation and ferroresonance are addressed.

The customer is responsible for tripping their generator intertie breaker and /or contactor and isolating their generator from the Company’s distribution system in the event of an electric fault and/or abnormal voltage/frequency condition. The protective relaying requirements for a particular facility will depend on the type and size of the facility, voltage level of the interconnection, location on the distribution circuit, fault levels, and many other factors. IEEE Standard 1547-2003 has specific tables with recommended default values for the trip settings of distributed generators.

The absolute minimum protective relays that the Company will require for induction generators for any size generator will never be less than the relays mentioned below, and on a case by case basis it may be necessary for the utility to require additional protection.

  • Utility grade undervoltage relays (device 27) shall be connected phase to ground on each phase. These relays disconnect the customer from the Company’s distribution system during faults or when the Company feeder is out of service. The default trip settings should conform to IEEE Standard 1547-2003 Table 1. However, for generation greater than 30 kW the Company may require different settings on a case by case basis as needed.
  • Utility grade overvoltage relays (device 59) shall be connected phase to ground on each phase. The default trip settings should conform to IEEE Standard 1547-2003 Table 1. However, for generation greater than 30 kW the Company may require different settings on a case by case basis as needed.
  • Utility grade over- and under-frequency protection (devices 81/0 and 81/U) are used to trip the generator or intertie breaker upon detecting a frequency deviation outside of reasonable operating conditions. The default trip settings should conform to IEEE Standard 1547-2003 Table 2. However, for generation greater than 30 kW the Company may require different settings on a case by case basis as needed.
The above functions are the minimum Company required relaying functions per the SIR table of minimum requirements and per the context of IEEE 1547-2003. However, it should be recognized that the customer may be required, based on the outcome of a Coordinated Electric System Interconnection Review (CESIR) or general technical review, to use protection settings other than the default settings described above, and add additional protection to facilitate proper operation of the Company’s low voltage network system or radial distribution feeders depending on where the system is interconnected. Additional protection could take the form of phase and ground fault overcurrent relays, ground fault overvoltage relays, directional power and/or overcurrent relays, transfer trips, speed matching controls, lock-out functions, etc.

It is important to recognize that the protection functions mentioned above are specified by the Company with the objective to protect the Company’s electrical distribution system as well as its other customers from the effects of the customer’s generator. The customer’s generator may need voltage and current unbalance relays and various types of generator over-current relays to prevent overheating of the generator windings during unbalance and fault conditions. Certain forms of generator grounding may also be needed to reduce the level of ground fault current so that generator windings don’t see excessive damaging forces during faults. DC backup power may be required for relay tripping functions depending on the size and criticality of the function.

To insure that both the utility system and the generator are protected, the customer has the responsibility to install the Company designated relays and also work with the generator manufacturer or system integrator to use relays and grounding practices that are coordinated to protect the generator itself from damage during faults and other anomalies. Damage that occurs to a customer generator as a result of failure to use appropriate protection and design practices is not the responsibility of the Company.

As mentioned in the Section I of EO-2115, only relays that are type tested by a certified lab or the Company or utility grade will be accepted for protection of the interconnection and the generator. Relays may be single function or multifunction packages, and they can be mechanical, solid state or microprocessor based types as long as they satisfy the utility grade or type tested specifications. Modern microprocessor multifunction relays designed for generator protection that satisfy the required utility grade specifications have recently become much more cost effective (compared to earlier products of a decade ago) and are available from a variety of equipment vendors.

The appropriate grounding scheme to use for the induction generator is a function of the type of distribution system to which it is connected and other factors specific to each site. The four main concerns of the Company regarding the type of induction generator grounding to utilize are ground-fault overvoltages, ferroresonance, harmonics, and ground-fault current contribution/detection issues. There is a widely held misconception in the industry that because the induction generator does not normally self excite, that the effects of ground fault overvoltages can be ignored since they would disappear quickly (transient decay). However, partial excitation can still exist on some phases during ground faults and because an induction generator might self excite due to capacitors and because even without self excitation, the transient decay period of its output can cause damage in just a few cycles, the grounding of induction generators and its potential impact must still be treated almost similar to a synchronous generator. This means the Company may need to specify effective or solid grounding for an induction generator whenever there is a concern about ground fault overvoltages on a four wire multi-grounded neutral distribution system. When interconnecting to ungrounded or uni-grounded distribution systems an ungrounded or impedance grounded interface to the Company distribution system at the PCC will usually be specified. The final determination as to which ground configuration is most appropriate will be done on a case by case basis. It is important to recognize that the type of grounding referred to in this section is the grounding with respect to the utility distribution system which is a function of not just the generator grounding itself, but also the configuration of the interface transformer winding configuration and its ground connection.

Many design requirements that the customer must satisfy are common to all of the generator types (that is SPC, induction, and synchronous generator types). The common requirements include the disconnect switch, certification standards, power quality standards, IEEE 1547 voltage response tables, etc. See section-I of EO-2115 for a discussion of the common requirements.

Drawings No. 1 and 2, at the end of EO-2115 represent typical interconnection design for induction generators and are presented as illustrative examples. Each project may have different requirements.

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