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synchronous generation

Synchronous generators are rotating energy conversion machines capable of operating as stand alone power sources (running independently of any other source). They also can operate in parallel with other sources (such as a utility distribution system) if they are properly synchronized to those sources and have appropriate protection/controls. In general, synchronous generators have the following characteristics from an interconnection standpoint:

The integral exciter and exciter controls of a synchronous generator allow it to operate as a stand alone source. This is particularly useful for customers that desire DG installations that can serve the dual function of stand alone (standby) power unit and also grid parallel operation. Extra care in the anti-island protection is required with these units

Synchronous generators can adjust their excitation levels to vary the reactive output of the machine. A high level of excitation can make the unit produce reactive power for the utility system (appear capacitive). A low level can make the unit consume reactive power from the system (appear inductive). The power factor can be adjusted anywhere from substantially leading (capacitive) through unity to substantially lagging (inductive) making this technology very versatile for voltage regulation and VAR support applications for both the customer and the utility system.

Synchronous generators, unlike induction generators, must be precisely synchronized with the utility system at the instant of connection and during operation. This means matching the frequency, phase angle and voltage magnitude within certain tight tolerances at the instant of interconnection of the customer’s tie breaker in order to avoid damage to or problems with the generator or utility system equipment. The unit’s speed must be controlled in appropriate fashion once it is connected so that it does not slip out of synchronism. If the unit slips out of synchronism and is not immediately separated from the system equipment damage or power quality problems could occur.

Synchronous generators, due to their exciters can sustain fault currents for much longer than an induction generator (assuming the exciter energy source is separately derived). This makes fault protection more critical on a synchronous unit than on an induction unit.

The frequency, phase angle and voltage magnitude difference between the generator and the Company’s distribution system at the moment of connection must be no more than allowed in IEEE 1547-2003 (see Table 5 in that document). This is a requirement of the Company because failure to connect within the indicated tolerances could cause a significant voltage and current perturbation on the Company’s distribution system that could impact the power quality of other customers. In extreme cases, where the tolerances are widely violated, distribution system outages could be triggered, damage to Company equipment could occur and/or the customer generator could be severely damaged.

The prime mover (turbine or internal combustion engine) for the synchronous machine needs to be started and the generator needs to be brought up to synchronous speed prior to completing the synchronizing process described in the paragraph above. To do this, the prime mover may use the generator (acting temporarily as a motor) or other motorized auxiliary equipment to start the prime mover and get the unit up to synchronous speed. However, the Company requires that any starting equipment deriving its starting power from the utility system, must not cause voltage flicker or voltage regulation problems on the Company distribution system. As part of the design review, the starting process is assessed to make sure that it does not cause unacceptable voltage flicker on the Company system. In order to assess voltage flicker from starting a synchronous generator, if the starting method draws power from the utility system, then the customer shall submit the expected number of starts per hour and the maximum starting kVA draw data to the utility to verify that the voltage dip due to starting is below the visible flicker limit as defined by IEEE 519-1992 and, where applicable, the Con Edison flicker specification (See Graph 1).

No synchronizing across Company distribution system equipment is allowed. This includes network protectors, switches and other devices. Interlocks with upstream disconnect switching devices may be required.

While the machine is running and connected to the power distribution system, the output power must not be allowed to fluctuate in a manner that causes objectionable voltage flicker or voltage regulation problems on the Company’s distribution system. The customer shall maintain and operate the generation facility such that any intentional and/or unintentional power output fluctuations do not cause flicker that exceeds the visible flicker limit as defined by IEEE 519-1992 and, where applicable, the Con Edison flicker requirements (see Graph 1).

The synchronous generator output, due to its exciter controls, can be adjusted to near unity power factor and can even provide reactive support if needed. For synchronous 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 generators larger than 2 MW, the Company will negotiate with the customer the reactive requirements of the machine and expected power factor performance.

Unless otherwise required by the Company, the synchronous generator will operate in a “voltage following” mode where it operates at near unity power factor and it will not directly attempt to regulate the voltage by adjusting the VAR output (either leading or lagging)

If the customer does not wish to use a voltage following approach and instead wants to use reactive-current based regulation either to help reduce the customer reactive demand or improve voltage regulation, then the control scheme, generator reactive current capability ratings and settings will be reviewed by the Company to insure that they are compatible with the Company distribution system at the point of connection. The Company will grant permission for this approach if it is feasible at the site where it is applied. Use of this method will be approved only if it can be shown that the settings will not cause voltage regulator hunting effects, degradation of voltage conditions on the feeder, and nuisance trips of the generator due to reactive current overloads. Voltage regulation schemes using the reactive current regulating capabilities of synchronous generators can be helpful to both the customer and the Company.

The customer is responsible for tripping the generator intertie breaker and /or contactor and isolating the 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, faults 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 Synchronous generators will never be less than the relays mentioned below, and on a case by case basis it may be necessary for the Company to require additional protection. Synchronous generators need more protection than induction generators and this is reflected in the minimum requirements below:

  • 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 time 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 time 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 time 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.
  • Utility grade synchronism-check relay (device 25C) operates when the customer generator and the Company’s distribution system is within the desired limits of frequency, phase angle and voltage. IEEE 1547-2003 Table 5 has specific settings that the Company may require. The Company also may require other settings on a case by case basis as needed.
  • Ground fault detection. Use either a utility grade nondirectional ground overcurrent relay (device 51N) for wyeconnected systems or a utility grade zero sequence overvoltage relay (device 59N) for delta-connected systems. This detects Company system ground faults and trips the generator offline.
  • Utility grade phase overcurrent relays. Three phaseovercurrent relays (device 50/ 51) or Three-phase, voltagecontrolled/ restraint overcurrent relays (device 50V/51V) trips on a desired value of overcurrent flowing out of the customer’s generator that is coordinated with thermal damage characteristics of the machine windings.

The above functions are the minimum Company required relaying functions for a synchronous generator per the SIR 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 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 directional power and/or overcurrent relays (device 32 or 67), transfer trips, lock-out functions (device 86), backup relays, etc. The protection scheme could also require a dc battery relay tripping source with appropriate alarm and/or protection should it fail.

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. However, the customer should be aware that their generator may itself also be damaged by voltage or current anomalies and the customer may need additional protection beyond what is specified by the Company to protect their own generator plant. For example, unbalanced voltage (device 47) and current relays (device 46) would have little impact on the protection of the Company distribution system, but could be crucial to the generator to protect it from overheating in an unbalanced voltage or current condition.

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.

Customers that want to transition their generation system from grid parallel to standalone operation for power quality and reliability purposes when the company supplied power is unavailable at the PCC can do this with a synchronous generator if the appropriate protection and isolation is provided. This type of operation is allowed as long as the customer generator does not energize any portion of the Company’s system beyond the PCC during the system outage or abnormal voltage conditions. This type of arrangement requires the customer to have anti-islanding protection by monitoring the intertie point (PCC) with appropriate relaying functions that will operate an isolation device (tie circuit breaker) at the PCC. The islanding protection would consist of voltage and frequency window relays per IEEE 1547-2003 Tables 1 and 2 trip settings or other modified settings if required by the Company.

Only relays that are certified (type tested) 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 (certification) 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 vendors.

The Company may require a transfer trip to provide more reliable islanding protection than is afforded by local voltage and frequency windowing relays alone. Islanding cannot be allowed under any circumstances on the Company’s system and the Company must use extra caution in the design of the interconnection for these generators.

The appropriate grounding scheme to use for the synchronous 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 synchronous generator grounding are ground-fault overvoltages, ferroresonance, harmonics, and ground-fault current contribution/detection issues. The Company may need to specify effective or solid grounding whenever there is a concern about ground fault overvoltages on a four wire multi-grounded neutral distribution system. Ungrounded or impedance grounded installations might be specified in other circumstances (such as when interconnecting to ungrounded or uni-grounded distribution systems). The final determination as to which ground configuration is most appropriate must be done on a case by case basis.

The company requires that the customer maintain harmonic distortion levels at the PCC in accordance to IEEE 519-1992 and IEEE 1547-2003 (see Table 3 in that document). While synchronous generators are relatively distortion free from a positive sequence voltage perspective, the characteristics of these machines can create zero sequence harmonic voltages that appear in the zero sequence path (neutral). They can also exacerbate certain harmonics that are created by load currents. These harmonics can occasionally be problematic depending on the machine design and loads at the customer facility. With certain transformer Arrangement, some harmonic distortion can find its way from the customer to the utility system and vice versa. As part of any CESIR design package review, practices will be recommended by the Company that have shown the best results in mitigating harmonics in a particularly situation. These include specifying a generator winding arrangement with 2/3 pitch (as opposed to a full pitch where the magnetic field poles span a rotational distance equal to that of the stator winding area), providing special grounding to limit the flow of zero sequence harmonics, the use of interface transformers with windings that block the flow of harmonics, and harmonic filters. Some of the solutions that are appropriate also must be balanced against the grounding needs of the generator and so must be addressed on a case by case basis.

In order to assure continued operation of the dispersed generation source and minimize impacts to existing customers during system disturbances, the stability of the customer’s generator may need to be investigated for larger units in this class or aggregations of many smaller units. Instability occurs when systems are subject to disturbances. While all generator types can have stability issues, rotating synchronous generators, in particular, owing to their electromechanical nature and the characteristics of synchronizing torques/inertia effects are the most likely of the three types of units to experience stability related issues. Stability problems can cause loss of synchronism (forcing the generator to trip offline) or build up of rotor oscillations that lead to power quality and/or reliability problems. Examples of contributing factors to the problem are:

  • Load swings
  • Switching operations
  • Short circuits
  • Loss of utility supply
  • Motor starting
  • Hunting of synchronous machines
  • Periodic pulsation applied to synchronous systems

Power system stability studies are essential for planning and designing a dispersed generation installation. The method of determining the stability limits of a system is elaborate and must take into account all the factors affecting the problem including the characteristics of all machines, exciting systems, governors, inherent regulation, grounding and circuit breaker response time. The Company may require a stability study part of a CESIR.

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 requirement include the disconnect switch, certification standards, power quality standards, voltage response tables, etc. See section 1 of EO-2115 for a complete discussion of the common requirements.

Drawings No. 5, 6, 7, 8 and 9, at the end of EO-2115, represent typical interconnection design for various types synchronous generators. Each project may have different requirements. These drawings are presented as illustrative examples and each project may have different or additional requirements.

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