March-April 2005

DG Islanding Rescue

While the problem of distributed generation islanding has been addressed in literature and by the industry, certain circumstances may circumvent safeguards put in place to prevent unwanted islanding.

The Los Angeles Department of Water and Power (LADWP) has developed one of the most recognized distributed generation (DG) programs in the US. In the last 15 years, over 125 MW of DG have been installed, representing nearly one quarter of new generating capacity for Los Angeles. The purpose of the LADWP's DG program is to identify and encourage the beneficial use of localized electrical generation to reduce electricity load growth, defer or avoid electric utility infrastructure expenditures, provide premium energy services to Los Angeles energy consumers, encourage energy efficiency, and improve the environment. To meet these goals the LADWP has created four DG demonstration testing facilities to test various DG technologies and the electric grid effects under various operating scenarios. At one of these facilities, the LADWP has identified a potential islanding problem, where two neighboring generation sources can interact to create an unplanned generation island.

What Is Islanding?
Most DG provides power to an onsite load while remaining connected to a utility electric grid to take advantage of the flexibility and reliability such an interconnection affords. Interconnecting to the grid means that all the generators connected to the grid must operate at the same frequency and at the same phase as every other generator connected to the grid. Most DG units that are tied to the grid are configured to shut down when the grid does not generate power.

Configured to operate in islanding mode, DG units can continue to provide power to onsite customers if the utility's grid goes down, in which case the DG unit would disconnect itself from the utility and continue generating power to the customer load. This extra reliability that DG units can provide to onsite load is one of the primary benefits of DG. The problems of controlling islands and interconnecting them to utilities are still limiting this option for many customers. So, although DG devices can be configured to island, for the remainder of this article we will assume that the customer/utility has installed the DG devices in a manner designed to prevent islanding.

Potential Problems With Islanding
Unintentional islanding of DG has the potential to jeopardize safety, disrupt reliability, damage equipment, and reduce power quality.

Traditional generation and distribution companies' primary concern of islanding involves safety—the risk that field personnel may be injured due to the presence of unknown and operational DG, and the risk that islanding may damage utility equipment. This is of particular concern since the protection equipment of DG is not generally maintained by the utility, but by the utility customer itself. This may lead to a compromise of the utility's protection scheme if the customer's fault response is not adequately coordinated with that of the utility. For example, if the DG does not clear a fault, the utility may be forced to trip a wider area, thereby creating a larger outage.

In a typical fault seen by a utility, a relay will detect the fault and cause a breaker to open at the source distribution station to de-energize the affected line and halt the flow of current. Normally, the utility protection scheme is designed to close the breaker after a few seconds to allow power to resume if the fault has cleared. However, if the DG is not separated from the grid, the DG-supplied current may resemble the fault current and will prevent the breaker from closing automatically. The DG must be able to isolate itself from the grid during a fault before the utility fault response closes the breaker. If the DG has isolated itself from the grid and allowed the breaker to successfully close, the DG unit may now be out of synchronism with respect to the grid, and closing under such circumstances may cause severe equipment damage.

Unplanned DG islanding could also damage customer equipment by providing operating voltages or frequency outside state regulatory standards. This problem can be avoided by incorporating the appropriate generation-to-load ratio to establish the voltage and frequency thresholds.

The islanding problems posed by DG have, for the most part, been adequately resolved by DG manufacturers and islanding has generally been limited to those times when the practice is allowed by the utility—ideally when the DG is disconnected from the utility grid. To minimize potential DG problems, all DG protection schemes should be effectively coordinated with the utility protection scheme. Some relay settings for a typical DG installation are given in the table.

The LADWP's Islanding Dilemma
As shown in the figure, the LADWP's Main Street Test Facility has microturbines connected in parallel to a fuel cell. These DG devices are connected directly to the utility grid through an industrial station containing a circuit breaker. In between the DG devices and the industrial station are various loads.

To demonstrate that the DG unit can be safely disconnected from the grid, before any DG device is commissioned, the LADWP's line patrol mechanics conduct various disconnect tests. During one such test, while a DG unit is delivering energy to the utility grid, the mechanics switch the DG disconnect to isolate the DG from the grid. The DG output is then measured to ensure that the DG relays disconnect from the grid and that no energy is delivered. This test demonstrates that the DG unit can shut down safely when the grid is not providing power to the fuel cell at the fuel cell disconnect point, as indicated in point A of the figure.

If a fault occurs at point B, the breaker at the industrial station (point C) will open, isolating grid power from the fault. The relay settings in the table ensure that during a fault at point A, the fuel cell relays will detect the fault and cause the DG unit to stop generating power.

A potential problem occurs if there is a fault at point D. Initially, the breaker at point C would open. Typically, the opening of that breaker would introduce sufficient transients so that both the microturbines and the fuel cell relays would trip. However, even if the breaker at point C did not sufficiently disrupt the circuit stability to trip the microturbine and fuel cell relays, most likely the load connected to point A would not have the matching power requirements by the grid as seen by the DG devices—and this mismatch would cause the fuel cell and microturbine devices to trip.

The problem occurs if the load (as measured by the fuel cell and microturbines) mirrors the characteristics of the grid. In this case, both the fuel cell and the microturbines may continue to generate power to the load on the DG side of the industrial station (point B). This is due to the fact that the microturbine sees the power generated by the fuel cell, interprets this as the grid being energized, and continues to operate—not recognizing that it is islanding. Similarly, the fuel cell interprets the power generated by the microturbines as the grid being energized and continues to operate—without recognizing that it is islanding.

This problem is typically avoided when traditional generation is employed because there is usually an industrial station located at point A that uses relays to isolate the load from the generation. Requiring customer stations to have similar relay schemes would make most smaller DG installations prohibitively expensive.

The LADWP's Proposed Solution
The LADWP addresses the unintended islanding problem by installing a load-interruption device, located at point A, designed to open when the breaker at point C is opened. This would prevent the DG from continuing to feed the connected load, once the DG is isolated from the grid. As previously discussed, a fault at point A is already handled by the DG relays so the proposed load-interruption device need only handle load current and can be relatively small (as compared to devices that would need to handle fault current). The load-interruption device would most likely be a motorized disconnect switch.

The breaker (point C) and the motorized disconnect switch (point A) could be linked by radio or microwave transmitters (depending on how far away the two are) so that when the breaker opens the motorized disconnect would open. Note that the converse should not be implemented because the motorized disconnect should be manually closed after the breaker is closed and the DG is synchronized back to the system.

Protection coordination would need to be modified with the installation of the motor-controlled disconnects. Some utilities set closing at 2 seconds, which is too fast for these motor-operated isolation devices. The LADWP sets its closers at 5 to 10 seconds for 34.5-kV feeders and 30 to 45 seconds for 4.8-kV feeders.

Afterward
In the example above, we proposed solving the potential islanding problem by installing a motorized disconnect at the DG facility's connection to the grid. This motorized disconnect would be activated by a transfer trip from the industrial station breaker feeding the circuit in which the DG facility resides. Installing this fix at this site is feasible since the DG testing facility was designed to be flexible enough to allow for this type of modification. However, many customer sites are not fed from an industrial station, but rather from a customer station. Molded-case circuit breakers used in these customer stations typically lack a relay and may lack the external capability to incorporate transfer tripping. In these cases, the solution outlined in this article would need to be modified around onsite peculiarities.