DESIGNING INTENDED ISLAND OPERATION IN DISTRIBUTION NETWORKS Jussi Antikainen, Sami Repo, Pertti Järventausta Department of Electrical Energy Engineering Tampere University of Technology P.O.Box 692, FIN-33101 Tampere, Finland Phone (358) 3 3115 4292, Fax (358) 3 3115 3646 E-mail:
[email protected]
Keywords: distributed generation; intended island operation; network planning ABSTRACT At present, island operation is seen as a one of the solutions to rise to the challenge of tightening demands on reliable and effective power supply. Due to this fact, the development of designing island operation is needed. This paper discusses designing island operation in a distribution network. The focus of this paper is to justify the reasons for the use of island operation in a distribution network and especially why pre-planning has such an important role. The key factors creating the context of islanding are also considered. Intended island operation is executed by means of distributed generation units (DG) located in the medium voltage (MV) or the low voltage (LV) side of the network. Selection of the connection point of DG and outage cost modelling for islanding potentiality analysis are also examined. In addition, case studies about islanding potentiality and short-circuit protection issues in a test network are analyzed. The discussions validate the usability of islanding and, on the other hand, the need for designing to ensure proper network operation. In addition, further discussions about islanding are needed in various forums.
1
INTRODUCTION
This paper discusses the principles of the designing of intended island operation in distribution networks. The main idea of intended islanding is that the distributed generation (DG) unit supplies power to the loads during a grid failure in the upstream network. The idea has some similar features than the Microgrids concept (MC). The targets of MC are increase the reliability of power supply, reduce network losses and reach environment benefits [1]. Island operation is a temporary and desired arrangement in a distribution network. It can be based on local DG units or backup power units, such as mobile stand-by power units. In this case, intended island operation is executed by means of mobile stand-by power units located in the medium voltage (MV) or the low voltage (LV) side of the network. The main differences between intended island operation and MC are that islanding is a temporary arrangement in MV or LV network and it is mainly based on mobile power generation units. Thus, islanding method is movable and it can be circulated between places where it is needed. In addition, an environmental benefit like decrease of pollution of the power production is not sought by islanding. At present, sufficiently reliable power supply is crucial for the activities of a developed society [2]. In addition, a growing dependency on reliable power supply has increased interruption costs. Furthermore, the regulator of the electricity distribution business in several European countries has taken interruption costs into account in a network profit regulation. In consequence of these, new ways to improve the reliability of power supply are under consideration. Based on many earlier studies, intended island operation has been regarded as one of the possibilities to improve distribution system performance and to prevent damage caused by long-term interruptions in the power supply [3] [4]. Intended island operation may improve reliability by reducing the outage time in the islanded part of the network. Furthermore, this reduces the outage costs of customers in the island. Savings in the outage costs can be significant even in normal failures depending on network constructions and customers in the islanded part. In case of major disturbances, change of the outage time and costs can be very remarkable. [5] To reach the desired positive effects of island operation, new approaches to planning and operating distribution networks are needed. Especially, personal safety always has to be secured for customers and all others working with electricity distribution. In addition, the function of network protection can also be endangered because the flow and the level of fault currents can vary strongly from normal network situation to island operation. In island operation, the fault current level depends on the characteristics of the DG. The DG´s ability to produce a decent fault current level in every possible fault situation is vital for proper operations of the
network protection. In these considerations, faults in the low-voltage (LV) networks also have to be studied. The success of intended island operation depends on many complex factors. Thus, the best place to use intentional islanding in different scenarios is not always easy to determine. Also, forming an island, island electrification in proper order and returning to normal network operating situation has to be carefully pre-planned. In this paper, these new approaches to planning and operating distribution networks are combined under the term designing island operation (DIO). The discussion of what should be taken into DIO is the focus of this paper. In this paper we will not specify all technical issues involved with islanding. Because of the case-specific nature of intended island operation and different resources to manage utilization of island operation, unambiguous operating or planning instructions cannot be given. This paper is divided into eight parts. The first part is introduction. The second part of this paper contains the general discussion of DIO, and a draft of the context of DIO is also considered. In the third part, network reliability analysis and evaluation of outage costs are introduced concisely. The third part discusses the development of evaluating outage costs especially from the DIO´s point of view. The fourth and fifth part contain discussions about islanding potentiality estimation, connection of DG to network and transition to island operation. The sixth part contains the case studies which support the issues presented in earlier chapters. Open questions concerning islanding are proposed in the seventh part. In the last part of the paper, considerations are given.
2
DESIGNING ISLAND OPERATION
Intentional islanding and the possibilities of improving the reliability of distribution networks have gained much attention in recent years. Many of the studies made concerning intentional islanding concentrate on the reliability issues; how intentional islanding affects reliability. This is totally expedient, but if intentional islanding is utilized in distribution networks, the study has to be taken further to develop the utilization details. These details will vary depending on the viewpoint from which they are examined. The examples of these different viewpoints are the network owner, the customer, the regulator of electricity distribution and the owner of DG. However, by observing standpoint of different parties, some common details to utilize islanding can be found. The main target of intended island operation, reliability improvement, also benefits other interest groups apart from the customers involved with electricity generation and distribution. For example, the use of intended island operation can produce income for DG or network owners [6]. Thus, the utilization of intended island operation must be planned as exactly as possible and also anticipated adequately to
attain the wanted outcome. The pre-planning and anticipating possible scenarios prevent errors and incorrect actions which could lead to unsafe network operation. Furthermore, the benefits of islanding strongly depend on how long it takes to form an island. The duration has to be short enough in comparison to the repair time of the fault to obtain gains. Because of this, designing island operation has an important role in the usage of intended islanding. At present, there are also plans for large-scale cabling in rural areas where the network configuration is almost purely radial. In that case, the power supply restoration time equals to the fault repairing time. The fault repairing time in cable network can be very long, thus, with this kind of network development trend islanding may come more beneficial. The need for intentional island operation is a consequence of long interruptions in the power supply. These interruptions consist of unexpected outages and planned outages. Unexpected outages are caused by faults in one or several network components. Furthermore, faults of network components relate to environmental factors (e.g. storms, snow, over voltages) and normal wearing and ageing, and thus, unexpected outage events cannot be accurately predicted. Based on the predictability problems with outages, the circumstances where intentional islanding is needed are not exactly known beforehand. Thus, perfect preplanning of islanding actions is difficult or even impossible. Anyway, if intentional islanding is used, a usage strategy should be clear. Also, the resources allocated to the utilizing of island operation have to be taken into account when defining the strategy. Therefore, DIO is needed. When island operation is used to improve the reliability of the distribution network, it is very important to take DIO into consideration systematically when designing a new network or development actions consisting of network renovation plans and other regional development plans like town planning. DIO consists of several topics; how to find and define potential places for islanding and what should be taken into account when considering the best places to connect DG, for example. The economical impact of islanding as voltage quality and other technical constraints are also parts of DIO. DIO includes considerations about possible connection points of DG in the potential areas to use intentional island operation. In addition, the network disconnectors, both manual and remote-controlled, affect the utilization possibilities along with the power transfer capacities of the network. On the other hand, DIO can be divided into sections concentrating on pre-planning and real-time planning - planning the actions before and during islanding. With these, the optimal way to introduce the proper usage of intentional islanding to improve reliability and efficiency of electricity distribution are created. These also ensure the possibility to utilize island operation in a functional way.
These strategy and resource considerations with DIO generate the context of intentional islanding. The draft of the context is shown in Figure 2.1. The topics of the context are discussed in the following sections.
Figure 2.1: 3 3.1
The context of islanding.
SAVINGS IN OUTAGE COSTS Reliability
The reliability of a distribution network can be defined by its ability to perform required operations in an ideal way without outages. Thus, distribution network reliability is strongly related to interruptions in the power supply. These interruptions consist of unexpected outages and planned outages as well as high speed or delayed auto-reclosings (AR). The interruption frequencies affect reliability as well. A failure in one individual network component, like a part of an overhead line or a cable, is able to prevent power supply to a large area of the radial distribution network. Customers in this area will suffer an outage whose duration depends on the possibilities to arrange backup power to the downstream network from the faulted part. If there is no possibility to restore power supply, the outage time is the same as the repair time. The repair time can vary from a few hours to several days depending on the failure. If there is a possibility to isolate the faulted component and restore power supply, the outage time will be shorter. Thus, the outage time is the principal factor in the reliability of a distribution network.
Reliability can be defined numerically by reliability indices [7]. These indices give trends for trouble spots on the network and make it possible to compare different ways of evolving the supply system. Another way to consider the reliability level and to compare possible network development actions is to calculate the outage costs. An evaluation of the outage costs is presented in the next chapter. Simplifying the task, there are three main ways of improving the reliability of the supply system: reducing the average fault frequency, reducing outage time, and reducing the size of the fault-affected zone. However, this is a complex task because these three main ways include many possibilities for reaching the desired effect. The optimal solution has been found when the reliability of the network is maximised and the costs of outages and investments in a given consideration period are minimised. The average failure frequency can be reduced by using components with lower failure rates, e.g. replacing overhead lines with underground cables, improving the maintenance program, and using network reclosers. Using distribution automation in networks (e.g. remote controlled disconnectors), supply restoration equipments (e.g. temporary cables and mobile generation units) or personnel training, the average interruption duration will be reduced. These actions to improve reliability are partially overlapping. At the same time, these actions can also be divided into preventive and corrective actions. Preventive actions reduce the probability that a potential problem will occur. These actions may also reduce the severity of a problem if one should occur. Corrective actions eliminate the cause of an existing undesirable situation in order to prevent reoccurrence. Moreover, the fault type and scale itself further defines the upcoming outage time. A special case of the fault situation, where the outage time may be extremely long, is a major disturbance. Another example of a contrary situation is fault due to lightning. In this case, the outage time may be some of tenths of seconds if AR actions are able to remove the fault.
3.2
Evaluation of outage costs
The evaluation of outage costs is, along with reliability indices, the way to estimate the quality of power supply. Exact evaluation requires a lot of detailed information from the entire network, such as network topology, used components and their failure rates as well as information about the customers. The basis for the outage cost evaluation is created by clearing out the outage time in different parts of the network. Furthermore, the outage time calculation is based on the knowledge of the frequencies of different types of outages. The knowledge of the frequencies is related to the data collected during the past couple of years. The information of used components, such as conductor type, length, age and environment, weigh heavily on failure frequency. Thus, the frequencies are always estimations.
Along with the frequencies, network topology, the type and placement of disconnectors, overall existing backup connections and the capacity of them and DGs affect the outage time by creating or limiting the fault isolation and power supply restoration possibilities. Also, island operation is assumed to affect the outage time. Based on things mentioned in previous paragraphs, it is possible to calculate the probability of outages and expected value of the outage times in different parts of the network. This makes calculating the outage costs possible. The outage cost evaluation is based on the value of non-distributed energy during an outage. Non-distributed energy will incur direct and indirect damage to customers. This damage is highly dependent on several factors such as customer type, the actual load demand at the time of the outage and the time of day when the outage occurs. The outage types like long fault interruptions, planned maintenance outages or outages from auto-reclosing (high speed AR or delayed AR) affect the outage costs as well. The effect depends on the customer type. The outage costs can be modelled with the outage cost parameters (more details in References [8] [9] [10]). Table 3.1 shows the parameters for each customer group and for different outages. The data is based on a Finnish questionnaire study conducted in 2005 [8] where different customers are divided into five groups: residential, agricultural, industry, public and commercial. Table 3.1: Interruption cost parameters for different customer groups based on questionnaire studies in 2005. Unexpected
Planned
outage
outage
Au Bu Ap Bp [€/kW] [€/kWh] [€/kW] [€/kWh] Residential 0.36 4.29 0.19 2.21
High speed AR
Delayed
AhAR [€/kW] 0.11
AR BdAR [€/kWh] 0.48
Agriculture
0.45
9.38
0.23
4.80
0.20
0.62
Industry
3.52
24.45
1.38
11.47
2.19
2.87
Public
1.89
15.08
1.33
7.35
1.49
2.34
Commercial
2.65
29.89
0.22
22.82
1.31
2.44
The expected annual outage costs caused by interruptions in the zone under study are defined by using equation 1. A zone refers to a part of the distribution system like a distribution substation with a number of different customers or an individual load point. The equation summarizes outage costs from different types of interruptions for the zone studied.
ncg
COST cg 1
W (cg ) Au (cg ) nu 8760 B p (cg ) t p
where
COST ncg W(cg) Au(cg)
AhAR (cg ) n hAR
Ap (cg ) n p
Ap(cg) Bp(cg) AhAR(cg) BdAR(cg) tu tp nu np nhAR ndAR
(1)
BdAR (cg ) ndAR
annual outage cost [€/a] number of customer groups group’s cg total annual energy [kWh] customer group’s cg interruption cost for unexpected outages [€/kW,fault] customer group’s cg interruption cost for unexpected outages [€/kWh] customer group’s cg interruption cost for planned outages [€/kW,fault] customer group’s cg interruption cost for planned outages [€/kWh] customer group’s cg interruption cost for high speed AR [€/kW,fault] customer group’s cg interruption cost for delayed AR [€/kW, fault] duration of unexpected outages [h/a] duration of planned outages [h/a] number of unexpected outages [1/a] number of planned outages [1/a] number of high speed AR [1/a] number of delayed AR [1/a]
Bu(cg)
3.3
Bu (cg ) t u
parameter parameter parameter parameter parameter parameter
Development of outage cost evaluation when considering islanding
Intended island operation offers a way to affect the outage time especially in the case of a long interruption. As can be seen in equation 1, if the outage time is reduced by islanding, the outage cost is also reduced. Considering the effect of intended island operation on outages from auto-reclosing, in particular when it is based on mobile stand-by units, intended island operation does not influence them. Thus, these interruptions whose outage times and numbers can be reduced by islanding are mostly due to unexpected or planned outages. For simplicity reasons, the effect of intended island operation on the outage costs resulting from planned outages is desirable to separate into its own equation. Thus, equation 1 can be simplified to produce equations 2 and 3. Note that the outage costs from planned outages can be important factors that should be noticed when considering an accurate cost analysis of intended island operation. ncg
COSTu cg 1
W (cg ) Au (cg ) nu 8760
Bu (cg ) t u
(2)
ncg
COST p cg 1
W (cg ) A p (cg ) n p 8760
B p (cg ) t p
(3)
The appropriateness of intended island operation is based on profitability; savings in damages during interruptions. The profitability can be measured by the changes in outage costs. Equations 2 and 3 give tools for evaluating the outage costs or the changes in them when the outage times (tu and tp) and number (nu and np) are reduced by utilizing the intended island operation. In addition, the effect of islanding on the power based outage cost term Au in unexpected outages is questionable; an unexpected outage causes a blackout every time except for special cases - a customer with sufficient backup power generation and uninterruptible power supply (UPS) system with adequate capacity. Thus, it can be ignored in many cases. Based on this, the evaluation of the outage costs, when considering the profitability of islanding, narrows down to the dissections of the cost changes resulting from the terms Bu, Ap and Bp. Furthermore, when considering the rationality of islanding, it is also useful to model the interruption cost parameters, used in equations 2 and 3, in larger scale than a single customer. The reasonable scale is the zone of island to be formed - a single distribution substation or a part of a distribution network. This means modelling combined parameters out of individual customers’ parameters to form an island. The combined interruption cost parameters, for unexpected and planned outages, are modelled by calculating an annual energy weighted average of the interruption cost parameters for different customer types in the zone under study. Equation 4 and 5 describes this:
Azone B zone where
Azone Bzone Wzone,tot Wi Ai Bi
1 Wzone ,tot 1 Wzone ,tot
n
Wi Ai
(4)
Wi Bi
(5)
i 1 n
i 1
combined interruption cost parameter [€/kW] combined interruption cost parameter [€/kWh] total annual energy of the zone under study [kWh] customer group i’s annual energy [kWh] customer group i’s interruption cost parameter [€/kW] customer group i’s interruption cost parameter [€/kWh]
The combined parameters give additional information about the effectiveness of intended island operation in reducing the outage costs. Also, they reflect the harmfulness of an outage to the zone. Due to the fact that islanding has to be profitable
in order for its utilization to be reasonable, the gains have to be outweigh the costs of operation. Thus, one straight-forward way to estimate this relation of gains and costs, i.e. the islanding potentiality, is to calculate the price of an outage hour. Furthermore, the calculation of the price of an outage hour to the zone is simple to make with combined parameters. Equation 6 shows this: price of an outage hour
where
(6)
Bzone Pk , zone
Pk,zone average power of the zone [kW]
In addition, if the outage costs and times, due to unexpected or planned outages, can be defined for the zone by computer aided software, the prize of an outage hour can also be evaluated in a different way. However, it has to be noted that the outage times can be different in the single parts of the zone. These parts are settled on the possibilities to isolate them from the neighbouring network. Therefore, a weighted average of the outage times has to be calculated. The weighting is based on an annual energy consumption of the single parts. Thus, the price of an outage hour is the energy based outage cost divided by an annual energy weighted average of the outage times in different parts of the zone under study. ncg
COSTB
price of an outage hour
1 ncg
W (cg ) cg 1
where
COSTB B t
cg 1
W (cg ) B(cg ) t 8760
ncg
Wcg t cg 1
1 ncg
W (cg )
(7)
ncg
Wcg t cg 1
cg 1
annual outage cost resulting from term B [€/a] customer group cg’s interruption cost parameter in the selected outage type [€/kWh] duration of the outages from selected type [h/a]
The outage costs calculations presented are based on the annual energy consumption of the customers. In other words, the calculation is based on the average powers. The average powers are calculated from annual energies by dividing them by the hours of one year. This is not totally exact but it gives the best solution to solve the problem due to which power is used. On the level of annual outage costs, this may not be such an important factor but when considering the outage costs of one particular moment, the power needed by a customer or a zone can differ very remarkably from the calculated average power. Moreover, the outage cost evaluation is based on the value of non-distributed energy. Non-distributed energy will incur damage to customers. This damage is highly dependent on factors mentioned earlier. Further, the time of day or season when the outage occurs will have an influence to the outage costs as well. For ex-
ample in Nordic countries, an outage which duration is several hours happening in a summer or in a winter season has a remarkable different effect on the individual customer - the outage cost can be more (e.g. residential) or less (e.g. agriculture) depending on the customer group. On the other hand, the regulator of the electricity distribution business does not take this time-dependent feature of the outage costs into account in a network profit regulation. In the future, new methods can be used to approximating the needed power and the value of power during an outage in more detailed way. These methods can be based on customers’ automatic meter reading (AMR) solutions. With AMR, the load curves can be estimated to all single customers from their measured historic data.
4
IDENTIFYING POTENTIAL PLACES FOR ISLANDING
Finding potential places for intentional islanding is limited by technical requirements and, on the other hand, the operation has to be profitable. In addition, the profitability itself is not clear to define. One reason for this are problems in defining the costs of islanding. However, the first approach to the problem can be taken by passing the exact technical constrains and voltage quality issues. In the next paragraphs, a few approaches to identify potential places for islanding are proposed. Propositions are not all-inclusive and they are very strongly linked to the theory of evaluation of the outage costs.
4.1
Outage times and costs
At first, the network has to be thoroughly checked in order to evaluate the outage times and costs. The evaluation is reasonable to execute in different levels like a feeder and smaller parts. These are parts of the network which can be isolated from the surrounding network with disconnectors, an individual customer or a LV network. For these parts, annual outage costs and how the costs are comprised as functions of the interruption time have to be evaluated. This means calculating the price of an outage hour for the selected part of the network. The difference between the outage costs, in normal network operation and in the case where island operation is utilized, indicates the usability of intended island operation in the zone under study. The high annual outage times and costs as well as the high price of an outage hour each indicate the potential of intentional islanding in their own way. Thus, it is very case-specific which give the best assumption for the best place for an island. Further information on evaluation of the outage costs and the price of an outage hour are presented in chapter 3.
The definition of the high annual outage time or the high price of an outage hour is not unambiguous. The definition can be based on the comparison of the calculated values for other parts of the network under study or the average values of a larger extent. Also, when considering the potentiality of islanding, one way to consider the magnitude or significance of an outage time or price of an outage hour is to compare the outage time to the forming time of an island in particular area. The price of an outage hour can be compared to the variable and fixed costs of islanding. It is noteworthy that the high outage time does not mean high outage costs in every case and vice versa. One explanation for this is power demand during an interruption. If power demand is considerable, from half to one megawatt for example, even quite short interruptions can cause a very high interruption costs. Thus, the high outage time tells that there might often be situations where island operation can be profitably utilized compared to if the outage time is low. Herein a comparison has to be also based on the values of the network under study. Secondly, the high price of an outage hour means that interruptions in the area cause damages which have remarkable value. This depends on the power demand, number of customers and their types, for example. Furthermore, choices in valuating the significance of the different customer types affect the outcome. The high price of an outage hour does not automatically mean that the area has a strong potential to utilize island operation. But it shows the superiority order between possible islands, based on outage costs, in case the outage time is reduced by n hours. Also, if the time of day or season is noticed in the outage cost evaluation, the results due to potential places for islanding can be different.
4.2
Backup connections
Backup connections are needed to ensure the continuity of the power supply in particular interruption situations. Examples of these interruptions are problems in transmission and MV network and interruptions on substations (e.g. loss of the main transformer). In these situations, the repair times may be quite long. Thus, capacities of the backup connections have to be adequate to supply all loads. In some cases, the capacity is inadequate and, in consequence, the load shedding or periodic load supply is needed. If the capacity of backup connections is not sufficient or even if a backup connection does not exist, islanding can offer an effective way to correct the problem. Furthermore, intended island operation can be used to support the backup connections be taking load form them. This reduce loading of backup connections and may release capacity which can be used elsewhere. Also, it is possible to run DG unit parallel with existing network. This supports the voltage level of the network
for instance. Thus, identifying the major problems in restoring the power supply in different scenarios can expose some potential places for island operation.
4.3
Deferring the network investment needs
Components used in electricity distribution have a certain lifetime within which the reliability of the component is at the desired level. After time t the component has to be replaced or the desired level of reliability has to be modified to accept more interruptions. In addition, replacing the component before time t can be required for some reasons. With intended island operation, it can be possible to increase the time t. The increase can be based on lower loads in extreme situations, like arranging the backup power, thus the ageing is slower, for example. In addition, prolonging the lifetime of the component which is a part of a larger unity, may partially be based on the examination of the risk level of the complete system. If the decrease in the reliability of one component can be compensated in a suitable way, i.e. the risk level does not get worse, the t can be increased. Based on these facts, it could be possible to defer the network investment decisions. This might be a driver for intended island operation in some places.
4.4
Utilization of customer owned units
Along with network development actions, some customers are very interested in improving the reliability of their power supply by UPS and backup generators, for instance. This is because their activities are greatly sensitive to power supply outages. Some of these customers have purchased their own stand-by genset or UPS and the number of these units is assumed to be increasing. UPS and backup generators are widely used in nursing services and in most the critical operations of societies. Table 4.1 describes the situation related to existence of UPS and backup generation in Finland. The data is based on a Finnish questionnaire study conducted in 2005 [11]. Table 4.1: Situation of the reserve power in Finland, year 2005. Customer group
Have backup
Residential
-
Intended to purchase backup -
Agriculture
21 %
38 %
Industry
36 %
18 %
Public
49 %
38 %
Commercial
39 %
17 %
The customers which have backup generation also have private strategies for using and operating the genset when an outage occurs. The strategy used is not necessarily the most effective for their or the distribution company needs. Thorough co-operation between the network owner and the customer who has purchased DG, or who is going to invest in backup power, it is possible to expand the idea of reliability improvement by stand-by genset. This co-operation can make reliability improvement more appealing to a larger group of customers. It benefits more customers by decreasing the harm of the outages. In this situation, the investment and other costs such as maintenance and operating of the genset can be divided amongst more interest groups. This will mean lower costs to an individual party, and the outcome can be better. The operating strategy of the genset can also be more effective and safe. Based on previous paragraphs, it is valuable to go through the network to determine possible existing electricity generation equipment and network customers’ plans to obtain DGs. The type, location, capacity and usability for island operation are under interest. These can definitely expose potential places for islanding. The network owner must ensure the adequate quality of power supply. The adequateness is defined by standards for the voltage frequency and level, for instance. Also, outages affect the quality. Therefore, encouraging customers to obtain backup power equipment can be very advantageous from the network owner´s point of view, especially in places where island operation seems to have good potential due to reducing the outage costs or supporting the capacities of backup connections, for example. This can be a solution to secure reliable enough power supply to all customers of the network. Particularly if the outage frequencies or the reliability requirements of vital components of power supply are increased locally (e.g. feeder level) or on a larger scale (e.g. substation level).
5 5.1
ISLANDING AND ISLAND OPERATION Connection of distributed generator to network
The effect of island operation on the reliability of distribution network is strongly sensitive to the location of DG [3] [12]. Also, the number and quality of the effects are strongly dependent on the reliability of the production unit and on the reliability of power supply. In addition, the best connection point for DG depends on the network structure (e.g. existing backup connections and disconnectors) and the focus of the loads. Therefore, there is no exact definition for the best location of DG - it is always case specific. In the case of mobile stand-by generators, the problem of where DG should be located does not exist in that manner. Therefore, mobile units can be transferred to the places where they are needed. In other words, mobile units can be shifted into
the network from which the island is meant to be formed. However, the problem of the best location or connection point of DG is not clear every time. Besides the location, the connection point of DG can be situated on the level of LV or MV network. At present, many backup power gensets operate on the LV level. Based on this, it is natural to select LV for the level of connection point. Further, LV connection is useful if an island is formed from one customer or loads of one distribution transformer; one LV network. Despite the fact that LV connection is pronounced, it could limit the possibilities to form an island. Limitation is based on the power demand of an island, and thus, the load capacities of LV components used. In many cases, it is more effective to form an island from a larger part of the network than one LV network, for example. With one DG unit, with adequate capacity, several LV networks can be supplied in island operation. This means power supply from LV to MV network through the distribution transformer whose LV circuit includes connection point of DG. The idea is shown in Figure 4.1. In Figure 4.1, the island is formed from three LV networks which loads - L 1, L2, and L3 - are supplied by distribution transformers, equally numbered; Sn1, Sn2 and Sn3. The connection point of DG is under Sn2.
Figure 4.1:
An example of DG connection to LV network.
The maximum continuous power supplied to MV network from DG depends on the apparent power of the transformer including the connection point of DG, in Figure Sn2. This can be increased with an overloading marginal, if allowed. Now, the apparent power of the transformer Sn2 can be a limiting factor to the size of the island. This affects the selection of the DG connection point and the network development needs. In an optimal situation, the power of Sn2 is bigger than the sum of powers Sn1 and Sn3 increased by network losses. In addition, the LV loads of transformers have to be noticed. Referred to the situation in Figure 4.1, the load L2 is not stressing the transformer Sn2 in island operation. Therefore, it is supplied straight from DG. On the other hand, the total power
demand of the island is the sum of L1, L2 and L3. Thus, if the connection point of DG is selected under the transformer whose load is the biggest, the power transfer from LV to MV network and the network losses are minimized. Thus, the best connection point of DG can be found in the LV network which is supplied through the distribution transformer whose apparent power is the biggest or in the LV network with the biggest loads, compared to others in the area of the island. In other words, when DG is connected to the LV network, the rough approximation of maximum power of the island to be formed can be based on the apparent powers of the transformers and theirs LV loads. Thus, the approximation is equal to the biggest sum of the apparent power and LV load of an individual transformer situated in the possible island. As seen in the approximation showed earlier and also the distribution network development, there can be cases where the oversizing of MV transformer, compared to LV load, is a reasonable thing to do from the islanding viewpoint. This can be worthwhile to consider especially when the economical lifetime of a transformer is finished or close enough to the end and when other reasons such as potentiality support the use of islanding. The connection point of DG can also be in the MV network. If the operating voltage of DG is not at the same voltage level, a separate connection transformer is required. The connection transformer has to be rated strong enough compared to the power of DG. This increases the costs of islanding. At the same time, it facilitates the choice of connection point by removing the limitations due to the load capacities of LV components. Thus, the connection at the MV network level can increase the size of an island and, in consequence, improve the profitability of island operation. Furthermore, if a connection transformer is used, the voltage level of the generator can be adjusted with the economic relations in manufacturing and operating the system. Also, the type - liquid filled or dry-type - of transformer should be thought through with environmental aspects in mind, for example.
5.2
Transition to island mode
In many cases, the need for islanding comes after large-scale difficulties in a power system. Thus, the transition to island mode is reasonable to do after the situation causing the need is finished and the network condition is finally clear after a storm, for example. Also, the possibilities to restore power supply in traditional ways have to be studied first. In generally, the adoption of islanding is the last action in order to restore the power supply to the network suffering from an extended outage. An intended, temporary island in the distribution network can be formed in two different main situations; in a case of a de-energized network after a fault, or in scheduled maintenance. It is also possible to form an intended island in a case of
fault without interrupting the operation of DG. This case is not discussed in this article. In scheduled maintenance, the island can also be formed without an outage. These situations create different circumstances for forming an island. However, the forming and operating have to be controlled. This means that DG has to be controlled in such an exact manner that the voltage quality - the level and frequency - is on an adequate level and the network protection operates properly in all network levels. In island operation, it could be possible to reduce the voltage quality definitions but it is not possible to change the absolute demand of the proper operation of the protection. In this part of DIO, exact technical factors are going to be more important. 5.2.1 Forming an island In a de-energized network, the most critical state in forming an island is the startup phase. Firstly, the network of island has to be divided into isolated parts with disconnectors, for example. In start-up, DG must be started to the network without remarkable loading in order to achieve a stable operating state. After DG is running stably, the island is started-up by connecting the parts of the network sequentially to the network energized earlier. Thus, all loads of the island cannot be connected normally at the same time. Dividing the network of island into separate parts is based on the existing network disconnectors or contracts with customers. In addition, the amount and type of loads has to be noted. Especially the motor loads are interesting due to their large starting current. Also, it is reasonable to find out the biggest single loads in the island. The increase or decrease in power demand cause voltage and frequency fluctuation. Magnitudes of voltage and frequency fluctuations depend on the magnitude of changes in power demand, strength of the network and in the characteristics of DG. Also, the rate of power demand growth affects the changes. In a worst case scenario, the variations cause an undamped oscillation of the system frequency. This leads to unstable operating conditions and the island has to be de-energized to avoid further failures. As the strength of a network in islands is relatively weak, the effect of power variation needs further consideration. Knowledge about loads and their behaviour in different parts of the island affects the success of forming and operating the island. Generally, it could be the best solution to connect the biggest loads to DG supply at the beginning of the forming phase. After the biggest loads are connected and the voltage and frequency have been stabilized, other loads can be connected by an order of magnitude. Furthermore, it is valuable to notice these aspects - island dividing possibilities, load types, places and behaviour, load shedding and contracts with customers - when considering network development actions and the best connection point for DG. In scheduled maintenance, the uppermost moment in forming an island without an outage, is the load transfer from network to DG supply. The basic principle is re-
ducing the power flow to zero through the point of network which separates the island from the surrounding network. Reducing the power flow can be conducted by increasing electricity production and controlling the power demand - active and reactive power - in the island. 5.2.2 Control of DG in island The second state is operating the island properly in all expected circumstances. These consist of continuous load changes, remarkable periodic load changes and faults in the island, for example. Basically, all of these situations must be cleared without jeopardizing the proper operation of the island in any way. Proper operation depends strongly on the characteristics of DG. DG has to have enough capacity in power generation compared to the loads of the island. This means generation of real and reactive power. Also, the control system of power generation must be able to tolerate the load changes in order to maintain stable operation. Besides, the dynamic behaviour of loads, the dependency on voltage and frequency, affects the control system demands. In the case of diesel generator units, the control system means the equipment that regulate the output power and speed of the diesel engine; regulate the real power and frequency. The control system also regulates the excitation of a synchronous generator; it regulates the reactive power, and thus, voltage level. Furthermore, DG´s moment of inertia is one factor which affects the performance of DG during island operation. In addition, the load following ability of DG, compared to the island at issue, is important to take into DIO considerations. 5.2.3 Protection of island When utilizing island operation to improve the reliability of power supply, some technical constraints can be faced. In island operation, the presence of rotating machines in the distribution network alters the flow and the level of fault currents. Therefore, it is important to ensure the personal safety and the function of network protection during islanding. The action of protection devices are based on fault currents and voltages. In many cases, the level of fault currents collapses when compared to normal network situation. This depends on DG´s ability to produce continuous fault current, furthermore, this relates to the type - induction or synchronous generator - and the rated power of the generator used. In addition, the solution to connect DG to the network affects to fault current levels. The level of fault current in converters based solutions can be remarkable different compared to traditional solutions. This has to be noticed. Diminution of the fault current may incur inoperability of the network protection in MV and also in LV networks. The basic rule for the proper operation of network protection is the selectivity; the closest protection equipment to the fault acts. During temporary island operation, the idea of selective network protection can be ignored, especially, if it solves the problems due to the network protection in an effective way. Thus, the breakdown of fault currents is not a remarkable problem in
the protection of MV network when unselective protection strategy is adopted [13]. In island operation, sensitivity of the protection is more important that selectivity for safety reasons. One reason for this is that protection equipments are purposed to operate during the transient phase of a fault, and thus DG´s ability to produce continuous fault current is not necessarily the limiting factor for the proper protection scheme. This part of the task has been studied quite extensively excluding faults in LV network. The electrical installations and short-circuit protection of LV customer (e.g. summer house, detached house) are designed with information of the fault current level at the connection point of the conductor feeding the customer. The information is received from the network owner and it affects the choices made in the crossselection of wires and types of fuses used. Further, if the level of fault current decreases, it is possible that the required terms of the proper operation of the shortcircuit protection are not realized. This causes malfunctions of the protection of LV customer leading to serious situations where the risks of mortal danger and fire are increased. The operation of fuse to disconnect the faulted circuit is based on the flow of short circuit current. Furthermore, the operation time depends on the magnitude of the fault current. Thus, the fault current level has to be on a correct level to achieve the proper acting and operation time of protection. In addition, the required protection operation time in a case of short circuit depends on the part of the electric system to be protected. For example, the time can vary between 0.4 to 15 seconds. In addition to the requirements for DG and the functioning of protection, unintentional connection of the energized island and the surrounding network has to be reliably prevented. An unintentional connection may cause hardware failures, unnecessary operations of protection equipment and, thus, power supply interruptions for health networks. Furthermore, an unintentional connection may endanger the personnel repairing the network. Also, if intentional islanding is used, an awareness about some of the unusual parts of the network that may be energized during a grid failure in the upstream network has to be emphasized. 5.2.4 Returning to normal operation situation The island can be deactivated either with or without an outage. If an outage is allowed, the deactivation is done in reverse order from the forming. When all loads are disconnected, the shutdown of DG can be conducted and the power supply can be restored in a normal way. Another way to deactivate the island is simply opening the generator breaker and shutting down the DG. This is the same as the situation when the emergency stop of DG unit is needed. This way will cause more electrical and mechanical stress to DG than the method mentioned first. In the case where interconnection is done without an outage, the island has to be synchronized onto the surrounding grid. The target of the synchronization is to set all phase voltages to zero across the separation point which isolate the island from
the surroundings. Thus, the island and the surrounding network can be smoothly interconnected without remarkable transients or voltage and frequency fluctuations. The voltages are set to zero if the island and the surrounding grid frequencies are equal and the phase sequences match on the both sides of the separation point. Also, the voltage magnitudes and phases of the island and network to be connected have to be equal. The deactivation of the island without an outage needs metering equipment. This fact, according to others, affects the selection of potential islands, connection points of DG and network development needs.
6
CASE STUDIES AND RESULTS
6.1
Network under study
The study network is based on a real network consisting of one rural feeder including 80 separated LV networks fed by a primary 110/20 kV substation. The total line length of existing (overhead) line is about 120 km. The feeder has 2 remote controlled backup connections. The network also has 3 remote controlled and several manually operated disconnectors. The feeder is divided into areas marked I – III. In addition, area I is further divided into circuits A – F. The test network used and the zoning is presented in Figure 7.1. Basic data of the areas and circuits is presented in Tables 7.1 and 7.2.
Figure 7.1:
The preliminary drawing of the test network used for analysis. Cross-lines mean disconnectors; remote controlled disconnectors are boldfaced. Table 7.1: The basic data of the areas.
Area I II III
Number of LV networks 36 21 23
Number of customers 361 276 249
Smax [kVA] 636.0 640.8 492.1
Pmax Qmax Pave [kW] [kVAr] [kW] 626.9 107.4 253.5 622.3 153.0 297.0 479.5 110.8 206.5
Table 7.2: The basic data of the circuits. Circuit A B C D E F 6.2
Number of LV networks 5 5 7 8 4 7
Number of customers 79 54 108 45 19 56
Smax [kVA] 176.5 90.9 163.5 71.6 39.3 95.8
Pmax Qmax Pave [kW] [kVAr] [kW] 170.9 44.2 69.1 89.0 18.5 38.9 160.9 29.0 61.2 71.5 4.3 32.5 39.1 3.7 16.5 95.5 7.7 35.3
Investigation of intended island operation potential in the test network
Table 7.3 shows information about outages in the areas based on the reliability calculation and methods introduced earlier. Reliability calculations are made by using reliability-based network analysis software developed by Tampere University of Technology [14][15]. The network data of failure frequencies in this particular real network is based on the collected real history data. Fault frequency is the same in areas I – III, therefore they are on the same feeder and protection zone. Fault frequency and number depends on the size of the area and conductor types used. Also, line routes and other environmental aspects have an effect on faults. The minimum (min.) and maximum (max.) outage times for distribution substations of the area under study are presented in the column Outage time. The outage time generally depends on the fault frequency and number in zone, repairing time and possibilities to arrange backup power. In addition, the weighted average of the outage time (wav.) is presented in Table 7.3. The calculation of the weighted average outage times is based on the annual energy consumption of distribution substations in the area, as showed in chapter 3. The outage costs in normal network operation are also presented in Table 7.3. The column Bu, zone shows the combined interruption cost parameters for unexpected interruptions and the column Price of an outage hour shows the calculated price for an outage whose duration is one hour. Note that this only takes the outage costs into account in accordance to parameter Bu.
Table 7.3: Outage information of the areas under study. Area Fault Number Outage time Outage cost Param. Price freq. of faults of [h/a] [€/a] Bu, in in zone outage zone zone hour [1/a] [1/a] min max wav Au Bu Sum. [€/kWh] [€/h] I 6.03 3.82 2.2 7.3 5.6 903 10246 11149 7.25 1837 II 6.03 0.91 1.4 1.9 1.8 1636 5033 6669 9.69 2878 III 6.03 1.31 2.0 2.7 2.3 777 3233 4010 6.69 1382 According to the results and islanding considerations, the best area to utilize island operation is area II from one standpoint. The reason is that area II has the biggest outage hour price and Bu, zone parameter. Thus, if the outage time is reduced by islanding, savings per time unit are the biggest in area II. These results originate from the valuating of different customer types. On the other hand, the average outage time in area II is the shortest, being under two hours. Furthermore, the neighbouring networks, areas I and III, causes about 0,51 h/a of outage time for area II when the operating time used for remote controlled disconnector is 0,1 h. This means that the faults (0,91 1/a) in area II itself, causes 1,29 h of the outage time for the area under study. Thus, the average fault clearing times for area II are 0,1 h or 1,42 h depending on, where the fault occurs; 0,1 h if the fault happens in I or III, 1,42 h if the fault happens in II. The short outage and fault clearing time in area II is a result of good backup connections and network automation, for example. In consequence of short times, the potentiality for islanding in area II can be challenged. For example, the start-up time for the island operation based on mobile units can be more than 1-2 hours. Thus, it may be possible that intended island operation cannot be used in II to reduce the outage time when considering the network’s normal failure situations. Herein it must be observed that the consideration level is for areas, not parts of them, where the outage time caused by a single fault depends on the repairing time. Bu, zone in I is much smaller than in II even though it has the biggest number of customers and outage costs. The reason is the difference in the distribution of customer types, their annual energy consumptions and the definition of their interruption costs parameters. If the interruption cost parameters used are the same for all customer types, the results will be different. In that case, parameters Bu, zone for all areas are equal. Area I does not have any backup connections, and thus, has the biggest outage times. Note, the biggest outage time does not mean the biggest outage costs in every case, and vice versa. In addition, many faults occur in area I, and also minimum and maximum values of the outage times have a great range of variance. This
may indicate that there could often be situations long enough to utilize islanding effectively. When viewing the outage times in the areas, it can be easily accepted that the reliability of area I can be more easily improved by intended islanding than the reliability of area II. Thus, if the outage times can be reduced by 10 % in area I and area II, the outage costs are reduced by 1 025 €/a in area I and 503 €/a in area II when considering outage costs caused only by Bu. Based on these, area I may have the best potential to utilize intended island operation in the network’s normal failure situations. In the case of a fault where all possible islands suffer an equally timed outage, the calculated outage hour price for islands is determinant and therefore area II has to be chosen for an island. The corresponding considerations are reasonable to do for the smaller parts of the areas. Here they are named circuits. Table 7.4 shows the equivalent information for the circuits that Table 7.3 showed for the areas. Table 7.4: Outage information of the circuits under study. Cir- Fault Number cuit freq. of faults in in zone zone [1/a] [1/a] A 6.03 0.21 B 6.03 0.48 C 6.03 0.94 D 6.03 0.95 E 6.03 0.34 F 6.03 0.90
Outage time
Outage cost
[h/a]
[€/a]
min 5.8 5.8 6.9 5.0 3.0 2.2
max 5.8 6.4 7.3 5.8 5.4 3.0
wav 5.8 6.1 7.1 5.0 5.4 2.5
Au 249 177 141 198 41 97
Bu 2547 2442 2379 1599 659 619
Param.
Price of Bu, outage zone hour Sum. [€/kWh] [€/h] 2796 6.31 436 2620 10.29 400 2520 5.51 337 1797 9.84 320 701 7.37 122 716 6.93 245
The results for the circuits show that the major part of the outage costs in area I come from circuits A, B and C. This is partially based on the power demands and number of customers of the circuits. Furthermore, the outage times of circuits A, B and C, which are quite long, affect the results as well. Thus, the outage costs can be assumed to be reduced strongly by island operation in these circuits. When considering the superiority order between circuits A, B and C for utilizing the island operation, circuit B emerges because of its average power compared to A and C (see Table 7.2). The average power of B is about half of the average powers of A and C. However, the outage costs are quite the same. The reason for this is parameter Bu, zone which describes the circuits’ customers’ sensitiveness to failures. The parameter Bu, zone for circuit B is approximately double compared to A and C.
Thus, the distribution of customer types has a strong effect on the usability of the island operation. Circuit A has the biggest outage hour price compared to other circuits. The difference in the outage hour price between A and B is not significant. Based on these, circuit A or B may have the best potential to utilize intended island operation. The final decision about profitability of islanding, in this case study also, depends on the situation where islanding is needed; possibilities and the time to form an island and the estimated time for restore the power supply. In addition, the costs of islanding have also an intensive effect on profitability. Roughly said, island operation is worth of applying if the costs of islanding are less than the price of an outage hour.
6.3
Short circuit protection of a low-voltage customer
The minimum fault current levels, which are defined in standards for different protection equipment such as fuses and low-voltage circuit breakers to fulfill the needs of the short circuit protection, also have to be reached during islanding. In the case of islanding, the fault current is produced by the generator of DG unit, and thus, is strongly dependent on the characteristics of the generator. DG’s abilities to produce continuous three phase short circuit current can be estimated with a rough rule; the minimum continuous three phase short circuit current is about 2.5 to 3 times the unit’s nominal current measured straight from machine terminals. Table 7.5 shows this for a few 400V / 50Hz generators. In Table 7.5, the generators’ short circuit currents Ik are retrieved from reference [16]. Table 7.5: Calculated Ik/In ratios. Generator nominal Nominal current Short circuit current Ik/In power [kVA] 100 200 500 810 1030
In [A] 144 288 722 1169 1487
Ik [A] 430 1000 2050 2900 3600
2.98 3.46 2.84 2.48 2.42
In other short circuit fault types, where one or two phases unintentionally come in contact with the ground or each other, short circuit current will be different. Normally, the produced fault current is greater than that in case of a three-phase fault. This feature is desirable from the viewpoint of short circuit protection of a lowvoltage customer; the blowout probability of fuses in proper time increases when short circuit current grows. On the other hand, the production time of fault current can be less in asymmetrical faults; a remarkable unbalance between generator
phases leads to an unstable operating condition and generator protection equipment disconnects the DG. Generally, there is a risk that the fault current levels or duration in a low-voltage network can reduce exceedingly during islanding. This depends on the used DG unit, fault type and impedances between the fault place and generator. Fault impedance also affects the results. Based on this, the survey of short-circuit currents and operation of protection in different cases is needed. For assessing the effects of islanding on the LV customers short circuit protection, the survey of short-circuit currents is examined in the test network. The idea is that the DG unit is connected to the LV side of distribution transformer; every single LV network is studied separately. Short circuit currents are calculated in case of three phase short circuit at LV customer’s main fuses. The main fuses are located right after a conductor feeding the customer´s electrical system. If the calculated short circuit current is over 3.5 times the size of the main fuse, when the size is less than or equal to 63 A, or else over 4.5 times the size of the main fuse, the protection is assumed to act properly. Otherwise, the LV network protection is not operating in demanded time. The results of the survey made are shown in Table 7.6. The first line shows the results for different test network sections in a normal network operating situation, the next lines show the results of islanding with different generator sizes and short circuit currents. Note that, in this study, DG nominal power is not compared to the required power of the individual LV network. Table 7.6: Number of customers with problems with LV short circuit protection. DG nominal Short circuit I, II, III A B C D power current Normal operation 16 2 0 5 2 100 360 72 11 3 11 3 100 430 60 11 2 8 3 200 720 33 6 2 6 1 200 870 25 5 0 5 1 500 1800 20 3 0 4 1 500 2170 19 3 0 3 1
E
F
0 4 3 2 2 0 0
1 6 6 3 1 1 1
According to the results, there are 16 customers in the whole test network which have problems in short circuit protection in a normal operating situation. In the case of islanding with 200 kVA DG unit, there are 25 to 33 customers with problems with LV protection. Even islanding with 500 kVA unit, there are 3 to 4 customers more than in a normal situation that have problems. Based on the results, in
circuits C and D the number of customers that have problems with protection reduces when islanding is arranged by DG over about 200 kVA. Furthermore, the short circuit study should be conducted by taking into account the different fault types and considering further the LV customers’ electric systems. The protection must work when failure happens in the electric device connected to the point of the system which has the biggest impedance; usually the final circuit of buildings. The problem is that the network owner or other party considering network protection does not have exact information about electrical systems owned by a LV customer.
7
OPEN QUESTIONS OF ISLAND OPERATION
The aspects mentioned earlier make intentional islanding a very interesting but also a challenging solution to develop the reliability of distribution networks. Further, island operation may create new business activities in several sectors resulting in positive welfare changes. Despite the positive effects islanding has on the reliability of power supply, island operation has many complicated obstacles. Some of these can be solved with comprehensive DIO, and some need open discussion and legislative dictums. The most important aspect from the DIO point of view is to secure the adequate level of power quality and the safety of electricity distribution. However, before that, the costs and incomes caused by islanding as well as network profit regulations are issues which need further discussions in various forums. In addition, regulations of island operation may be needed. With reference to co-operation, it will require good communication between different interest groups before and after the decisions to operate the specified part of the network in island. This is a very important non-technical issue which creates the basis for effective intentional islanding. In this field, there are many open questions on how to develop collaboration, communication and information sharing methods. The power quality requirements in the normal operation of a supply system are defined with standards (e.g. EN 50160). In island operation, the defined quality of power supply needs further considerations and standardisation. A reasonable level of quality has to be maintained in an island, but the requirements of quality can also be different during islanding. The study of power quality during islanding is a major part of DIO. This can be carried out with real network data by using EMTDC programs, network information systems (NIS) and distribution management systems (DMS). The purpose of the studies is to test the functions of an island; how voltages, frequencies, fault currents and the other variables related to quality and safety of network operation behave during islanding in different scenarios.
The network data needed in simulations is quite easy to collect. Other fields in simulations are much harder. Modelling the DG unit - a generator, power source and control system - is one of the most problematic cases. The DG modelling consists of several dozens of variables to be exactly defined in order for the modelled DG’s dynamic behaviour to be sufficiently close to the real thing. In addition, defining upcoming situations - faults and power changes - where DG’s dynamic behaviour is under interests are not explicit. The main tool for DIO will or must be NIS and DMS, as these are the main tools for network planning and operation at present in network companies. These systems must be added with some functionality of EMTDC programs to allow the study concerning islanding possibilities. These systems also have to have features which make real-time load estimation possible to ensure proper operation of an island. This means the estimation of needed total power and behaviour in accordance the time of day and year based on information from automation meter reading (AMR). In addition, it would be fruitfully if these systems used also have features to evaluate the outage costs as it is proposed in chapter 3.
8
CONCLUSION
Reliability improvement of distribution networks has gained much attention in recent years. Intended island operation is regarded as one of the possibilities that will rise to the challenge of providing reliable power supply. To ensure the positive effects of islanding, the islanding activities have to be pre-planned as exactly as possible. In addition, real-time planning is needed to ensure safe operation and good quality of the island. The most important aspect in islanding is that the initial function of power supply systems is not allowed to be endangered under any circumstances. Therefore, designing island operation is strongly needed. The success of effective and intentional island operation depends on many complex factors. As this study points out, these factors generate the context of intentional islanding. And, on the other hand, the context generates the possibilities to utilize islanding. Thus, the context discussed is also the basis for developing islanding actions. The reliability effect of islanding depends strongly on the connection point of DG. Besides the location, the connection point voltage level has an effect on the islanding possibilities, and thus has to be considered exactly in every single case. LV connection point has benefits compared to MV connection, but disadvantages can also be found. An example of these benefits is that existing backup power equipment operates on LV level. One disadvantage of LV connection is that it could limit the size of an island. The best place to utilize intentional islanding in different scenarios is not always easy to determine. According to this paper and the results of case studies, one way
to find potential places for islanding is to focuse on the outage times and costs in different parts of the network. In addition, an evaluation of the outage costs and times has to be conducted on different network levels (e.g. one feeder or an individual LV network). Based on the case study results, there are differences between separate islands and decisions can be made in order of superiority. The superiority order varies depending on the situation where islanding is needed and on the decisions to valuate factors like customer type. The calculated outage costs may not be the best indicator in the estimation of islanding potentiality. Calculating the price of an outage hour for the area of the possible island is fruitful when studying the local potentiality of islanding. The outage cost evaluation and evaluation development are examined in this paper. Furthermore, the case study results state that islanding based on relatively small generators may affect the LV network protection negatively. This depends on the generator’s ability to produce continuous short-circuit current and the length of the network in island.
9
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