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inverted generation

The static power converter (SPC), also commonly referred to as an inverter, provides the interface between direct current (dc) energy sources or variable high frequency sources and the 60 Hz power distribution system. Examples of generation systems employing SPC units include photovoltaic arrays, fuel cells, battery storage systems, some microturbines, and some wind turbines. Unlike an induction or synchronous generator that uses rotating coils and magnetic fields to convert mechanical into electrical energy, the SPC converts one form of electricity into another (i.e. dc to ac) and is typically controlled and protected by its internal microprocessor-based controller. The internal controller detects abnormal voltage, current and frequency conditions and quickly disables the injection of power into the system if limits are exceeded. It also controls synchronization and start-up procedures. While most small certified SPC units designed for grid parallel operation can rely totally upon their internal protection functions, larger and special feature SPC units may also require external protection/control functions.

When applying SPC units to the Company’s distribution system there are some big differences compared to rotating machines. These include:

SPC have no moving or rotating parts and utilize the on/off switching of solid state transistors to “synthesize” a 60 Hz ac waveform from the energy source.

Due to the fast switching response of transistors, an SPC is usually able to stop producing energy much faster than a typical rotating machine (once the controller protection scheme identifies the need to interrupt flow of energy)

The fault level contribution of SPC units are not usually as large as those from the same size (rating) induction or synchronous rotating type generator reducing the impact on Company equipment SPC units use embedded microprocessor controllers that control the switching and waveform synthesis, and also have embedded protection functions such as under/over voltage and under/over frequency. SPC also often employ an “active” antiislanding capability (if they are listed per UL 1741 as a non-islanding inverter). This is a level of protection beyond that found in ordinary voltage and frequency based passive islanding protection. A “certified” SPC per UL1741 can eliminate the need for external utility grade relays for smaller systems Because the use of SPC for DG is an emerging commercial technology, and is still going through a maturation process, the local, state and national regulations related to this are still evolving. Currently the IEEE 929-2000 for PV inverters, IEEE-1547-2003, and UL-1741 standards serve as the national foundation for the most pertinent interconnection requirements for SPC units. The Company approach for interconnecting SPC (inverters) is consistent with these standards where they are applicable and consistent with the requirements of the SIR.

SPC Startup and Synchronization
Modern SPC units which are designed for grid-parallel operation operate as grid interactive synchronous sources and will synchronize their output with the utility system voltage to achieve proper and safe parallel operation. For most small SPC, such as UL 1741 certified PV inverters and fuel cell inverters, all of the start-up, control and synchronization logic and functions are built into the device. At the instant the SPC is physically connected to the grid, its voltage sensing and controller circuitry starts tracking the utility distribution voltage, phase angle and frequency. The transistors of the SPC are then triggered to begin switching to create a source current injection into the system that is synchronized with the utility system.

As part of the start up process, many photovoltaic and other types of SPC units include a soft start-up feature that gradually ramps up to full output over several seconds following the moment of initial connection. This helps reduce voltage flicker compared to the approach of suddenly stepping to full output. The Company desires this type of soft start feature for SPC units and may not require it if the CESIR shows the resulting flicker of a full step start is not an issue. Some sophisticated SPC units operate in parallel with the utility system during normal conditions and as a secondary function can serve as standalone power for customer load when the utility distribution system is disabled. If the customer generator is to employ this type of “Advanced” SPC configuration, it must be configured with the appropriate protection and synchronization equipment to transition to/from grid parallel operation in a safe and proper fashion. It must not energize any part of the utility system beyond the PCC when the voltage or frequency conditions are out of range. When the utility service is restored to within normal range it must use a Company approved method to resynchronize with the system prior to re-connecting.

Essentially all modern SPC are self commutating and pulse width modulated (PWM) devices which makes it possible for them to easily operate at a very high power factor when at full load (almost always in the vicinity of 1). Modern self commutating and pulse width modulated SPC should have no problem meeting the SIR requirement of an average 0.9 power factor at the PCC as long as the loads at the customer’s facility do not cause poor power factor. The normal mode of operation that the customer is required to maintain is to operate the SPC as an essentially fixed power factor source close to unity. However, a benefit of some modern SPC designs is that some units can regulate the phase angle providing either leading or lagging VARs for voltage regulation purposes.

In most cases, the Company does not allow this type of regulation to occur on the system by customer generation but under some scenarios it can be of benefit to the system and may be allowed pending review by the Company. For SPC 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 SPC larger than 2 MW, the Company will negotiate with the customer the reactive requirements of the machine and expected power factor performance.

Modern units generally use Pulse Width Modulation (PWM) with high switching frequency and this has been shown to produce an extremely high quality waveform within IEEE 519-1992 requirements – especially good in the lower order harmonics. Despite meeting this standard, in rare cases, higher frequency harmonics and noise that arise from inverters (SPC), can on occasion cause interference with other devices or power line carrier systems. While generally this is extremely rare, the Company reserves the right to require that the customer should take corrective action or disable the system in the event of a noise problem after the system becomes operational. The Company requires that all inverters meet IEEE 519-1992 and IEEE 1547-2003 Harmonic limit requirements.

The customer is responsible for tripping the Static Power Converter intertie breaker and /or contactor and isolating his generator from the Company’s distribution system in the event of an electric fault or abnormal voltage/frequency condition. The protective relaying requirements for a particular SPC 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. New York State also has specific requirements under the net metering law that applies to net metered PV inverter systems.

The absolute minimum protective functions that the Company will require for Static Power Converters up to 20 MVA connected at the secondary voltage level will never be less than the functions below. These functions could be by means of a utility grade relay controlling an interrupting device or, by an imbedded relay function within the SPC controller if the SPC is certified under the most current approved version of UL1741 and/or that is type tested and approved by the NYS PSC for parallel interconnection with the utility system. Minimum requirements are defined as follows:

  • Undervoltage function (device 27) shall monitor 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.
  • Overvoltage function (device 59) shall monitor phase to ground on each phase. The default trip settings should conform to IEEE Standard 1547- 2003 Table 1.
  • 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.
The above functions are the minimum relaying functions per the SIR. 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 and external protection could take the form of phase and ground fault overcurrent relays, ground fault over-voltage relays, directional power and/or overcurrent relays, transfer trips, speed matching controls, lock-out functions, etc.

As mentioned earlier, some SPC units designed for grid parallel operation also have stand-alone capabilities, meaning that they can operate independently of the Company’s distribution system. This type of arrangement is useful when the customer desires to serve just the customer load for power quality and reliability purposes if there should be a utility system power outage or abnormal voltage condition. Since under no circumstances is the customer allowed to energize the Company distribution system beyond the PCC when voltage and frequency conditions are out of range, the SPC schemes with this type of stand-alone capability must have a suitable arrangement of switchgear and protective relays to isolate their island from the Company’s distribution system when the voltage and frequency goes outside the IEEE 1547-2003 limits (see Tables 1-2 in that standard). The intertie breakers and/or switchgear for this island shall be controlled by an appropriate scheme of relay functions that provide the necessary reliability, and control functions to detect abnormal utility conditions at the PCC, separate from the system and maintain a proper island for the customer, and resynchronize and connect to the system after utility service is restored to the normal range. Depending on the type of equipment that is employed (size rating, voltage level etc.) the Company may require utility grade relays, dc backup power for the tripping functions, and various alarms. Re-connecting back into the system may not be allowed until the Company’s district operator has approved for a manual reconnection.

The Company does not require utility grade backup relays for less than 30 kW SPC systems that use the appropriate certified and/or type tested equipment. As SPC units become larger however, the need for utility grade backup relays becomes more critical. For larger SPC the Company may require a set of backup utility grade relays and switchgear to isolate the customer’s generation system even though the SPC has its own internal functions. The exact threshold where this becomes critical depends on the application and will be determined on a case-by-case basis.

In some cases the Company may require some sort of transfer trip to provide more reliable islanding protection than is afforded by local voltage and frequency windowing relay functions alone (For example, DG connected directly to high tension feeders.) While an SPC unit with active-anti-islanding is unlikely to island with the utility system given its local protection functions, one that has the capability to serve the local customer as a stand-alone unit during a utility system interruption would need the active islanding protection disabled and thus must rely only upon passive voltage and frequency protection functions. In certain cases larger units in this class might need a transfer trip function.

The appropriate grounding scheme to use for the SPC interfaced generator is a function of the type of distribution system to which it is connected and other factors specific to each site. The main concerns of the Company regarding the type of SPC grounding to utilize are ground fault overvoltages, ferroresonance, harmonics, dc- current injection, and ground-fault current contributions/detection issues. The Company may need to specify effective or solid grounding for an SPC 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, voltage response tables, etc. See section-I of EO-2115 for a complete discussion of the common requirements.

Drawings 3 and 4 are interconnection drawings of typical SPC arrangements for electrical capacity of 500 kW or less. For larger units, additional requirements may be specified by the company. The relay devices, except for the reverse power relays, are functional representations of the package protection of the unit. These drawings are presented as illustrative examples and each project may have different or additional requirements.

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