Since the society becomes increasingly concerned to save energy and preserve the environment, the interest toward the distributed generation systems, such as photovoltaic arrays and wind turbines, increases year after year. Other sources, such as micro-turbines and fuel cells, are also in development. But wind turbines and generally DGs will have affects in the network that one of these influences is an islanding phenomenon. Islanding state occurs when one or many sources continue to feed power to a part of the grid that is disconnected from the main utility. Islanding situations can damage the grid itself or equipments connected to the grid and can even compromise the security of the maintenance personnel that service the grid. Therefore, according to IEEE1547 standard, islanding state should be identified and disconnected in 2 seconds. There are quite a few different methods used to detect islanding. All methods have benefits and drawbacks. The methods have traditionally been divided into two subgroups; passive and active methods. In active methods, small disturbances are injected into the power system and its responses due to the injected disturbances are monitored. These methods change the balancing power between loads and generations, reduce the power quality of the power systems and are not suitable for wind farms with numerous wind turbines. Reactive power export error detection method, impedance measurement method, slip mode frequency shift algorithm (SMS), active frequency drift (AFD), active frequency drift with positive feedback (AFDPF), automatic phase shift (APS) and adaptive logic phase shift (ALPS) are a few examples of active islanding detection methods. Passive methods continuously monitor the system parameters such as voltage, frequency, harmonic distortion, etc. Based on the system characteristics, one or more of these parameters may vary greatly when the system is islanded. The passive methods do not affect the waveform of the high voltage. This is beneficial since it does not give rise to power quality issues such as voltage dips. Setting a proper threshold can help to differentiate between an islanding and a grid connected condition. Rate of change of output power of DG, rate of change of frequency, voltage unbalance and harmonic distortion are a few examples of passive islanding detection methods. However passive methods are based on the measuring parameters of the power system and setting thresholds for the measured parameters. The main argue in passive methods is selecting suitable thresholds such that the islanding detection algorithm will not operate under noisy conditions
Islanding refers to a condition where DG continues to energize an electric power system (“EPS”) area through the point of common coupling (“PCC”) after a loss of service to the area from the electric utility as a result of an unplanned outage or routine maintenance. Unintentional islanding is of concern due to the following reasons:
v The impacts of unintentional islanding on power quality could result in damage to customer equipment. Because utilities lack control of the islanded system, maintaining power quality may become an issue during islanded conditions. The DG may be unable to maintain the local voltage within the ANSI C84.1 range or the frequency within parameters established by the Northeast Power Coordinating Council (PR6, PRC 12 and NPCC directory 12). Customers connected to the island could experience equipment damage as a result of these excursions.
v Islanding can impact utility asset integrity. For example, these conditions can interfere with manual or automatic reclosing, or loop feed automatic switching on the radial distribution system. Utility assets incorporated into or reconnecting to an island with abnormal voltage or frequency conditions may result in extensive equipment damage, for example, a line reclose damaged by reclosing out of phase or lightning arrestor damaged due to abnormally high voltages.
v Public safety risk may increase on delta connected systems. For example, a downed wire can remain energized after a device opens to isolate a fault. Depending on the location of the DG installation and the impedance of the downed wire, there may not be sufficient fault current or voltage deviation to trip a generator offline resulting in power being provided to the downed wire. Anti-islanding protection detects the island and causes the DG to cease power production and must operate quickly to mitigate the negative impacts of an islanding condition.
Some Fundamental of islanding
Given the activity in the field, and the large variety of methods that have been developed to detect islanding, it is important to consider whether or not the problem actually demands the amount of effort being expended. Generally speaking, the reasons for anti-islanding are given as (in no particular order):
1. Safety concerns: if an island forms, repair crews may be faced with unexpected live wires
2. End-user equipment damage: customer equipment could theoretically be damaged if operating parameters differ greatly from the norm. In this case, the utility is liable for the damage.
3. Ending the failure: Reclosing the circuit onto an active island may cause problems with the utility’s equipment, or cause automatic reclosing systems to fail to notice the problem.
4. Inverter confusion: Reclosing onto an active island may cause confusion among the inverters.
The first issue has been widely dismissed by many in the power industry. Line workers are already constantly exposed to unexpectedly live wires in the course of normal events (i.e. is a house blacked out because it has no power, or because they pulled the main breaker inside?). Normal operating procedures under hot-line rules or dead-line rules require line workers to test for power as a matter of course, and it has been calculated that active islands would add a negligible risk. However, other emergency workers may not have time to do a line check, and these issues have been extensively explored using risk-analysis tools. A UK-based study concluded that “The risk of electric shock associated with islanding of PV systems under worst-case PV penetration scenarios to both network operators and customers is typically <10?9 per year." The second possibility is also considered extremely remote. In addition to thresholds that are designed to operate quickly, islanding detection systems also have absolute thresholds that will trip long before conditions are reached that could cause end-user equipment damage. It is, generally, the last two issues that cause the most concern among utilities. Recluses are commonly used to divide up the grid into smaller sections that will automatically, and quickly, re-energize the branch as soon as the fault condition (a tree branch on lines for instance) clears. There is some concern that the recloses may not re-energize in the case of an island, or that the rapid cycling they cause might interfere with the ability of the DG system to match the grid again after the fault clears. If an islanding issue does exist, it appears to be limited to certain types of generators. A 2004 Canadian report concluded that synchronous generators, installations like micro hydro, were the main concern. These systems may have considerable mechanical inertia that will provide a useful signal. For inverter based systems, the report largely dismissed the problem; "Anti-islanding technology for inverter based DG systems is much better developed and published risk assessments suggest that the current technology and standards provide adequate protection while penetration of DG into the distribution system remains relatively low." The report also noted that "views on the importance of this issue tend to be very polarized," with utilities generally considering the possibility of occurrence and its impacts, while those supporting DG systems generally use a risk based approach and the very low probabilities of an island forming. An example of such an approach, one that strengthens the case that islanding is largely a non-issue, is a major real-world islanding experiment that was carried out in the Netherlands in 1999. Although based on then-current anti-islanding system, typically the most basic voltage jump detection methods, the testing clearly demonstrated that islands could not last longer than 60 seconds. Moreover, the theoretical predictions were true; the chance of a balance condition existing were on the order of 10?6 a year, and that the chance that the grid would disconnect at that point in time was even less. As an island can only form when both conditions are true, they concluded that the "Probability of encountering an islanding is virtually zero" Nevertheless, utility companies have continued to use islanding as a reason to delay or refuse the implementation of distributed generation systems. In Ontario, Ontario Hydro recently introduced interconnection guidelines that refused connection if the total distributed generation capacity on a branch was 7% of the maximum yearly peak power. At the same time, California sets a limit of 15% only for review, allowing connections up to 30%, and is actively considering moving the review-only limit to 50%. The issue can be hotly political. In Ontario a number of potential customers taking advantage of a new Feed-in tariff program were refused connection only after building their systems. This was a problem particularly in rural areas where numerous farmers were able to set up small (10 kWp) systems under the "capacity exempt" microFIT program only to find that Hydro One had implemented a new capacity regulation after the fact, in many cases after the systems had been installed