Applications of IEC 61850 in Distribution Automation

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example, IEC 61850-8-1 is a SCSM for mapping of services to Manufacturing ..... feeder topology. SVPI and SCPI represent supervisory LNs for voltage and.
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Applications of IEC 61850 in Distribution Automation Salman Mohagheghi*, Member, IEEE, Jean-Charles Tournier, Member, IEEE, James Stoupis*, Member, IEEE Laurent Guise*, Thierry Coste*, Claus A. Andersen*, Jacob Dall*

Abstract—Distribution Automation (DA) is viewed as an integral component of the Smart Grid paradigm. It facilitates the employment of computer technology and communication infrastructure to advance management and operation of the distribution network from a semi-automated approach towards a fully automated one. SCADA systems, advanced sensors, and electronic controllers are integrated into the DA system in order to achieve the desired performance and reliability at the distribution network. Interoperability of all the components participating in the DA system requires communication standards covering not only the devices in the substation, but all the components from the substation to the point of interface with the end consumers. While the IEC 61850 standard was originally addressing applications and communications within the substation, recent work is undergone for extending it beyond the substation fence. With its object oriented structure, IEC 61850 can provide comprehensive and accurate information models for various components of distribution automation systems, while providing an efficient solution for this naturally multi-vendor environment. This paper provides some concrete examples on how IEC 61850 can be employed in the context of distribution automation applications, and what measures need to be taken to enable it to efficiently respond to some of the emerging technologies in DA systems. Index Terms—IEC 61850, communication protocols, information models, interoperability, distribution automation, feeder automation, Smart Grid

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I. INTRODUCTION

MART Grid refers to a power system that incorporates the state of the art in communication, electronic control and information technology in order to achieve enhanced operational monitoring, control, intelligence, and connectivity. To achieve a “smart” distribution system, various automatic technologies and approaches have been attempted in the areas of system metering, monitoring, protection, and control. Although some automation schemes may only utilize local measurement (e.g. loss of voltage to initiate switching operations), most advanced schemes of distribution automation systems require communication between the different devices located in the field and/or to initiate an

S. Mohagheghi, J.C. Tournier and J. Stoupis are with ABB Corporate Research, Raleigh, NC 27606 USA (email: [email protected], [email protected], [email protected]). L. Guise is with Schneider Electric, Grenoble, France (email: laurent.guise @schneider-electric.com). T. Coste is with EDF, Clamart, France (email: [email protected]). C.A. Andersen and J. Dall are with EURISCO ApS, Odense, Denmark (email: [email protected], [email protected]). * Member of the IEC Technical Committee 57, Working Group 17 on Communication Systems for Distributed Energy Resources.

action or report an action to the central control center [1]. Such a communication system should make large quantities of data available to different applications while preserving its quality. This in turn raises the issue of how and with what format the data should be modeled and transported. Additionally, in more advanced automation applications, data needs to be accompanied by additional attributes such as the address of the device the message is being sent to, the address of the device initiating the message, type and length of the data, time stamp of the event/message, its priority compared to the other messages received, as well as its quality. Traditionally, proprietary protocols have been used to model and transport the data and the applications. The technologies developed were exclusive to each vendor and were not compatible with the systems and technologies of others. The inherent multi-vendor nature of advanced distribution automation applications leads to the need for an interoperable environment in which all devices and vendors share a common modeling and communication protocol. While the IEC 61850 standard was originally intended for intra-substation applications, this paper promotes the idea of extending its applicability to distribution automation applications integrating field devices located outside the substation fence. Some typical DA applications have therefore been presented here based on integration with IEC 61850. These include volt/Var control, fault detection, fault isolation, and service restoration. For each application, the paper attempts to discuss the modeling aspects, as well as the gaps and improvements that could be brought upon the standard to better suit distribution applications. The remainder of the paper is organized as follows: Section II gives an overview of the IEC 61850 standard by focusing on its modeling and communications aspects, while section III presents the main characteristics of distribution automation systems. Section IV is the core of the paper and presents the use cases of some typical DA applications using IEC 61850. Section V discusses communication aspects of the standard, and some practical considerations related to the implementation issues. Finally, concluding remarks appear in section VI. II. COMMUNICATIONS WITHIN THE SUBSTATION- IEC 61850 A. Overview IEC 61850 is a standard recommended by the International Electrotechnical Commission (IEC) originally for the design of substation automation (SA) systems [3], which was recently

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extended to cover other utility automation functions as well. Traditionally for the SA systems, the standard divides intersubstation communications into three levels: process level including the I/O devices, intelligent sensors and actuators, bay/unit level including the protection and control IEDs, and the substation level, including the substation computer, operator’s desk and the interfaces with outside the substation. All the communications within and between these levels are covered in the standard (Fig. 1). Moreover, in its recent edition, the standard also covers protection data exchange between the bay and remote protection, as well as control data exchange between the substation and the remote control center.

and services used for access to the elements of the domain specific object model. ACSI is a network independent interface that defines the semantic of the service models with their attributes, and describes what these services provide. The abstract nature of ACSI is necessary to make the SA system compatible with the fast advances in the communication technology, keeping the SA specific data models separate from the underlying communication technology.

Fig. 2. Data structure in IEC 61850.

Fig. 1. Substation automation topology based on IEC 61850.

In the IEC 61850 environment, protection and control functions are broken down into smaller units called Logical Nodes (LN). These virtual units are in fact the objects defined in the object oriented context of the standard, and present one of the most important advantages of the standard over legacy protocols. These LNs correspond to various protection, protection related, control, metering, and monitoring functions as well as the physical components such as transformers and breakers. Each LN can have a few or up to 30 data objects, each of which belonging to a Common Data Class (CDC). Each data object in turn has a few or more than 20 data attributes. The LNs can be on any of the three levels defined for substation automation, and are normally grouped into logical devices (LD) – one or more of which reside in each physical device [3] (Fig. 2). IEC 61850 defines an abundance of services that act upon the data objects of the LNs. These services not only cover the traditional control/read/write commands, but they also cover new and expanded services for grouping the data objects, reporting an event and logging, as well as transmitting the fast messages, i.e. GOOSE and GSSE [3]. The communication services and data models are defined in section 61850-7-2 of the standard. The Abstract Communication Service Interface (ACSI) specifies the models

The syntax and encoding of the messages are defined in Specific Communication Service Mapping (SCSM). For example, IEC 61850-8-1 is a SCSM for mapping of services to Manufacturing Message Specification (MMS). Figure 3 illustrates how these communication stacks and interfaces are related.

Fig. 3. Communication services- mapping to the OSI layered model

In addition to the client/server services by mapping to the MMS stack, the standard provides peer-to-peer services for transmitting Sampled Values (SV) and GOOSE messages (Fig. 4). SV represents quantities digitized at the source to be transmitted to the substation. These quantities come from modern low energy voltage and current sensors which gather information from the primary power system. IEC 61850-9-1

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and 61850-9-2 define two mappings for SV over serial unidirectional multi-drop point-to-point link and SV over ISO/IEC 8802-3.

Fig. 4. Client/server and peer-to-peer communication modes in IEC 61850.

Multicast GOOSE messages on the other hand are used to model the transmission of high priority information such as trip commands or interlocking information. The model is based on cyclic and high-priority transmission of status information. Information like a trip command is transmitted spontaneously and then cyclically at increasing intervals. Although other standard protocols exist that cover communications beyond substations, it is generally believed that the capabilities of IEC 61850 can be potentially used to improve these applications. In this context, IEC 61850 can be used as the communication protocol for feeder automation applications or communication with the control centers [5]. III. DISTRIBUTION AUTOMATION Distribution Automation (DA) as a concept emerged in the 1970s to promote the application of computer and communications technologies for the improvement of distribution system operating performance. Since then, DA has evolved and turned into an established concept which is adopted by the utilities worldwide. Today, DA has gained renewed attention and accelerated momentum in view of the recent industry-wide push towards Smart Grids and the need for more reliable and efficient distribution systems. In fact, it is estimated that by 2030, 55% of all distribution feeders in the US will be integrated with advanced DA systems [6]. DA specifics vary from one utility system to another, but in general it refers to deployment of automation technologies for protection, control, monitoring, and operation of distribution systems. These technologies enable electric utilities to monitor, control, and operate distribution components in a real-time or non-real-time mode from remote locations. A key requirement for any DA system is an advanced two-way communication system for providing capability of remote measurements/operations of field devices from a substation or the control center.

DA promises to benefit the utility and customers alike by reducing operation and maintenance costs, improving reliability and power quality, enabling new customer services, deferring capacity expansion projects (CAPX), and providing better information for utility engineers and planners [7]. DA covers the complete range of functions from existing SCADA systems to ever-increasing deployment of AMI technologies at the customer level in which local automation, remote control, and central decision making are brought together to deliver a cost-effective, flexible, and cohesive operating architecture [8]. A DA implementation could be as simple as upgrading a manual switching scheme with remote control to deployment of sophisticated DMS systems with integrated IEDs. Some examples of DA/FA applications are listed below, each requiring automated operation and control of a specific set of components within the distribution system: • Fault Detection, Isolation and Restoration (FDIR) – algorithms used for detecting and isolating faults in the distribution system, and restoring power to the customers located in the outage area. This improves system reliability and availability of service. • Feeder Reconfiguration – preventive or restorative actions for dynamic reconfiguration of the network in order to achieve improved efficiency, reduced losses, load balancing, lower congestion, and smaller probability of outages. • Outage Management System (OMS) – utilizes the data available from fault location systems, IEDs and Advanced Metering Infrastructure (AMI) to achieve accurate outage scoping, thereby replacing the traditional trouble call approach and reducing the response time to system outages. • Distribution State Estimation (DSE) – perform near-realtime state estimation and topology processing to achieve an accurate state/topology of the distribution network to be used either by other applications or for situational awareness purposes. • Voltage/Var Optimization (VVO) – regulates shunt capacitors and transformer tap positions in order to achieve minimized power losses, reduced demand and/or improved voltage profile. • Distributed Generation (DG) Management – optimal dispatch of DG units to minimize the losses, improve the system voltage profile, manage reactive power production, improve the system congestion profile, or assist system restoration, while adhering to the market conditions. • Microgrid Management – supervisory control of low voltage and medium voltage microgrids during grid connected mode and/or performing microgrid islanding. • Demand Response (DR) – demand side management to make use of the demand reduction offered by proactive consumers, primarily for peak shaving purposes. Some similar mechanisms can also be used to manage ancillary services that contribute to quality of service and system security in the distribution system.

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Protection Coordination – to achieve dynamic optimal coordination between the protective devices in the distribution system after a change in the network setpoints or configuration. • Load Forecast and Modeling – accurate load forecast and modeling for real-time or near-real-time applications, at the substation, service transformer or meter level, considering the consumption patterns and/or econometric data of individual or groups of customers. • Electric Vehicle (EV) Integration to the Grid – to model, analyze, and manage the integration of EVs into the grid for battery charge and discharge processes, given the utility needs and the market information. The recently coined term Advanced Distribution Automation (ADA) describes the extension of intelligent control over electrical power grid functions to the distribution level and beyond [9]. While traditionally, electric utilities with SCADA systems have control over the transmission level and distribution level equipment, their area of responsibility falls short of the end users’ territory and they are unable to provide direct control of smaller energy units such as autonomous distributed energy resources (DER), homes and buildings. ADA concept is a platform that offers extension of utility’s control over these small scale systems in order to achieve higher efficiency, sustainability and reliability.

modeled using IEC 61850. 1) Shunt Capacitor Control A typical LN-representation of the capacitor bank and the related controls are depicted in Fig. 5. In this case, three separate sets of logical nodes are assigned to phases a, b and c, in order to represent the individual instrument transformers for the three phases. The logical node XSWI represents a switching device not capable of tripping short circuits [10]. Examples are load breakers, capacitor breakers, disconnecting switches and grounding switches. It should be noted that although the capacitor bank in Fig. 5 is considered to allow for individual phase switching, the individual XSWIs are shown as a stack of switches and not three switches for three phases. This is due to the fact that a capacitor bank normally consists of several parallel capacitors per phase and therefore each phase has more than one switch associated with it. The proposed logical node AVVC represents the application LN for VVC.

IV. CASE STUDIES This section provides some detailed examples on how to model various DA functions using the data models provided in the standard IEC 61850. A. Voltage/Var Control Generally, the objective of volt/Var control (VVC) problem is to minimize the power losses in the network, reduce the total demand, and/or flatten the voltage profile. This objective is achieved by regulating the size/status of the shunt capacitors, and tap positions of the voltage regulating transformers along the feeder(s) as well as that of the on-load tap changer (OLTC) at the substation. The optimization problem is subject to operational constraints of the control elements as well as the network constraints for the power system. Mathematically, the problem can be formulated as follows: Min { power losses, total demand } Subject to one or more of the following: - Load balance equations - Bus voltage constraints - Line/transformer current constraints - Power factor constraints at the main substation - Reactive power constraints at the main substation - Maximum allowable number of operations for each transformer tap for a given time duration - Maximum allowable number of switching operations for each capacitor for a given time duration The two main control elements of the VVC problem, i.e., the shunt capacitor and the voltage regulator, can be easily

Fig. 5. Decomposition of shunt capacitor bank control into LNs.

The size of the capacitor bank can be regulated by opening or closing one or more switches from the stack of parallel capacitors. This can be achieved by accessing the data attribute Pos belonging to each logical node XSWI. Furthermore, the logical node ZCAP represents a capacitor bank, and in addition to typical optional attributes such as the equipment health and operation time, provides mandatory attributes CapDS and DschBlk to indicate capacitor bank device status and blockage due to discharge respectively [11]. Finally, the data attribute OpCntRs belonging to the logical node SSWI determines the (resettable) number of switching actions on the XSWI. This information is critical in evaluating the operational constraints of the capacitor, namely, the number of switching operations in a day, or the last switching action –which are often limited.

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2) Voltage Regulator Tap Position Control Voltage regulators with automatic tap changing capabilities allow for controlling the voltage according to a predefined automatic logic or by remote access through the operator command. The most relevant LNs defined in IEC 61850 for this application are ATCC that represents the automatic tap changer controller, YLTC that represents the tap changer which is the device allocated to the power transformer allowing changing taps of the winding, and MMXU/MMXN that indicates the presence of three phase/non-phase metering and measurement for operative purposes [10]. Some of the main data attributes associated with the logical node ATCC are as follows [11]: • Loc: to indicate local operation • TapPos: tap position • OpCntRs: resettable operation counter (i.e., number of tap operations) • TapChg: change tap position (stop, higher, lower) • LTCBlk: block automatic control of LTC • Auto: automatic/manual operation • ParOp: parallel/independent operation (which is used for ganged or unganged operation of the tap changer) • HiTapPos/LoTapPos: to indicate that the high or low tap positions have been reached. Fig. 6 illustrates a tap changer with a three-phase control, which similar to the previous section can be easily expanded to incorporate individual phase control capability as well. In that case, the attribute ParOp of ATCC needs to be set to the correct setting to indicate independent (un-ganged) as opposed to parallel (ganged) operation.

Fig. 6. Decomposition of tap changer control into LNs.

3) VVC Use Case A typical voltage/Var control use case can be described as follows: 1. Load forecast, network model, loss calculations are imported from external modules and used for algorithm calculations.

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Single phase and three phase measurements from across the system are available through MMXU and MMXN. Examples include the total active demand, total reactive power, total power factor, etc. 3. Capacitor status and number of switching operations are retrieved for all capacitors. 4. Tap position and number of operations are retrieved for all voltage regulators. 5. Algorithm is executed (at the utility side or at the substation), control actions are determined (subject to operational constraints of individual capacitors and tap changers). 6. Finally, control signals are sent to local controllers (CSWI and ATCC). The communication scheme for the VVC application depends on the way the algorithm is being implemented. While for centralized solutions implemented at the control center level, the communication services would be in the form of client/server applications, for more decentralized solutions –for instance at the substation level or lower– the services could be either in the form of client/server or peer-to-peer applications. Both these schemes are supported by the standard. B. Fault Detection and Isolation The objective of fault detection and isolation is to sense and locate a fault in the network, and consequently, isolate it from the rest of the network in minimum amount of time. Fault detection and isolation therefore contribute to the overall system security by minimizing the impact of an electrical fault on the network. The fault isolation needs to ensure that the fault is isolated with minimum amount of unserved load as a result of the disturbance. This mechanism is largely dependent on the protection scheme employed at the feeders. In general, two main protection schemes can be considered that are currently being used worldwide: • A distributed protection scheme, mostly used in rural distribution networks or when large distances have to be covered – In such a scheme, multiple breakers and/or reclosers are located on the same feeder and contribute directly to clear the fault as close to where it occurs as possible. Since this mode is very frequent in North America, it has been referred to here as the NA influenced feeder topology. • A centralized protection scheme, where protection devices able to clear the fault are exclusively located in the primary substation. This means that in the event of a fault only one breaker can trip (or perform reclosing action). Any other switching equipment on the line does not have fault interruption capabilities. In the current state of the art, no more than 2.5 switches per feeder are remotely controllable. Since this mode is very frequently used in Europe, it has been referred to here as the European influenced feeder topology. Fault detection and isolation issues for these two schemes are described in the following sections.

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1) NA Influenced Topology In this first scheme, protective relays often detect the fault and trip their corresponding circuit breakers to isolate it from the healthy feeders. Fault detection, location and isolation applications can be easily modeled using IEC 61850 since it involves virtually the same set of devices and operations to detect and isolate the fault within the substation as it does down on the feeder. a) Fault Detection Various protection devices can be used for sensing a disturbance, the most common ones for the distribution network being time overcurrent, directional overcurrent, differential protection, and earth fault detection. Although in the presence of distributed energy resources other protection devices such as over/under-voltage protection, over/underfrequency protection, directional over/under-power and suchlike can also be employed. All these protection functions are modeled in details in the standard [11]. In this topology, it is also common to install reclosers along the feeder. These devices are equipped with typical protection elements such as PTOC and can help in detecting the fault. Once the protection device senses a disturbance, it sends the trip command to the circuit breakers and reclosers to lock out and interrupt the fault. Fault detection at the control center level can be achieved by monitoring the position of the switch, i.e., XCBR.Pos or the status of the auto-recloser, i.e., RREC.AutoRecSt. The standard also provides data attributes for counting the number of operations of these devices, which is specifically important in applications involving autoreclosers. Examples of these attributes are RREC.OpCntRs and XCBR.OpCnt. b) Fault Isolation Switches and reclosers used for isolating the fault are all modeled in IEC 61850: • RREC: an auto-recloser is modeled in the standard as a controllable device whose status AutoRecSt can be accessed by an external application, and can operate using the data attribute Op. The standard provides optional reclose time attributes that indicate the time of the first, second and third reclose operations. • XCBR: is a switch with short circuit breaking capability that is controlled by the protection logical nodes Pxyz. The switch position can be accessed by retrieving the attribute Pos, while its operation mode can be changed from local mode (without communication) to remote mode by accessing the data attribute Loc. • XSWI: the circuit switch is very similar to the XCBR, except that it cannot interrupt a short circuit. The switch position and mode of operation (local/remote) is often controlled by the logical node CSWI. c) Fault Location The standard also provides a logical node RFLO for fault location. Among its various data attributes, the LN provides measurements for fault impedance (FltZ) and distance (in km) to the fault (FltDiskm).

2) European Influenced Topology In this type of feeder operation, there is only one breaker in charge of protecting the line against electrical fault. Very often in order to minimize the impact of a fault, the real topology of the feeder is an open ring. Fault detectors are spread on the line (underground or overhead) and are used to identify the faulty section of the line. Isolation of this section will then isolate the electrical fault based on the information received from the fault detectors and hence, restoration will be possible by supplying the healthy section by closing the normally open point of the open-ringed feeder. a) Fault Detection The fault detection scheme in this specific case not only has to detect the fault, but also to ensure that this fault has been cleared by the upstream breaker. A confirmation is therefore needed that this fault was a “true” fault. Fault signature analysis (fault detection) can be performed and modeled using the P series LNs such as PTOC, PTOV, etc (see the Appendix). However, in such cases, the corresponding Start and Op attributes which are considered mandatory in the standard are generally not very useful unless they are used for providing setting information.

Fig. 7. Functional breakdown of a fault detector in the European influenced feeder topology.

Another function –not currently supported by the standard– is the function in charge of detecting the presence of voltage or current. It is therefore possible to create a new LN for supporting these functions, which can also be of interest in a “standalone” approach. Moreover, the decision-making function, which will take into account the signal coming from the fault signature LNs, as well as from the presence of power (voltage or current), is very specific, and cannot really be semantically modeled using the PTRC logical node, which is generally used for protection relays, because such function is not supposed to perform trip conditioning. Therefore, it is recommended here to add a new LN to cover this type of function, from the S series LN (S meaning supervision). The proposed LN is called SFPI, i.e., Supervision Fault Passage Indicator. This would lead to the LN breakdown of FPI as depicted in Fig. 8. By using peer to peer communications, current break down may evolve by computing the real status of the upper breaker, rather than an image of its position through voltage and current analysis.

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Fig. 8. Fault presence indicator LN breakdown for the European influenced feeder topology. SVPI and SCPI represent supervisory LNs for voltage and current presence indicators.

b) Fault isolation Fault isolation is performed by remotely managing the remotely controllable switches located on the corresponding feeder(s). Here also peer-to-peer communications between the fault detectors and the controllable switch can speed up the overall reaction time of the DA system. 3) Discussion The standard seems to cover almost all the devices that participate in the detection, isolation and location of the fault. Minor information missing can be added as described in the preceding sections. Moreover, geographical attributes can be added to the reclosers and switches that indicate their association with the connectivity model of the system. However, the important point is that no new common data class is needed to provide the required data. C. Service Restoration Use Case Following the occurrence of a fault in the distribution system and its consequent isolation from the rest of the network, the customers initially affected by this interruption are not limited to those connected to the faulty circuit; rather, a larger number of customers –for instance those connected to the downstream of the fault location– will be left without electricity as well. Service restoration algorithms are therefore applied in the distribution management system (DMS) in order to supply electricity to the customers located in the outage area, while the fault is isolated and the faulty circuit is being repaired; thereby improving the availability of the system. Traditionally, the selection of the restoration sources and the restoration paths is determined only by the capacity margin of the restoration source as well as the rating limits of the equipment along the restoration path. The consequence of service restoration is an additional load imposed on the generators located on the restoration path. When the additional load exceeds the capacity of these generators, several actions can be performed: • A demand response signal can be sent to the customers on the restoration path to lower their load. In this case, the demand response signal should be a direct load control (DLC) signal so that the load reduction happens as fast as possible.

Activation of distributed energy resources (DER) and bringing the reserve supplies online. • Adjustment of the generation setpoints of the dispatchable DER units. Due to space limitations, this paper only focuses on the case involving the activation of DER to support the additional load. To illustrate this case a small example is presented in Fig. 9. The proposed system consists of two main generation sources, four feeders and a DER unit. Under normal operating conditions, feeders 1, 2 and 3 are energized through Generator 1, while feeder 4 is energized by Generator 2 –with the normally open switch R3 being open. It is also assumed that Generator 2 has enough capacity to support feeder 4 with no need for bringing the DER unit online.

Fig. 9. Service restoration example – normal operating condition.

When a fault occurs along feeder 2, switches R1 and R2 open up in order to isolate the fault. The consequence of the fault isolation is that feeder 3 is now without power. It is assumed in this case that the load of feeder 3 can not be handled solely by Generator 2; however, it can be handled if the DER unit is connected to the network. The set of actions and operations to perform in order to restore the power on feeder 3 are (see Fig. 10): • Evaluate the load on feeder 3. • Determine the maximum capacity of Generator 2. • Determine the maximum capacity of the DER unit. This will provide an estimate of the total generation capacity available. • If the total power exceeds the loads on feeders 3 and 4 then proceed. • Perform synchronism check between the DER and the grid. • Connect the DER to the network (set to the load following mode). • Close the switch R3 to re-energize feeder 3.

Fig. 10. Service restoration example – after service is restored to outage area.

From an IEC 61850 modeling point of view, the above

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example can be modeled as in Fig. 11. The new application logical node ARES is proposed to indicate the service restoration engine. To perform its actions, ARES uses: • MMXU20 that provides the current load supported by Generator 2, • ZGEN2 which gives the capacity of Generator 2, • MMXU2 which provides the load of feeder 3 before the fault occurred, • DGEN30 which gives the capacity of the DER, • DRCC30 which allows to control the set point of the DER, • RSYN30 which checks the synchronism of the DER, • XCBR30 which connects the DER to the network, • RREC3 which closes switch R3 to re-energize feeder 3.

Fig. 11. IEC 61850 based model of the service restoration example.

V. COMMUNICATION ASPECTS Distribution automation applications are characterized by a large number of openly accessible devices, spread out over large geographical areas, which are connected to each other through heterogeneous means. Such characteristics make the requirements on the underlying communication infrastructure different from the ones applicable for substation automation applications. While communication infrastructure as defined by the OSI model [12] is too broad to be discussed in this paper, the discussion in this section is restricted to the most critical parts, namely the physical layer, the network and transport layers, the session layer and cyber security. A. Physical Layer At the physical layer, different media such as fiber optics, Power Line Carrier (PLC) or wireless technologies can be used. The selection of the proper medium depends on many aspects, e.g., installation cost, geographical span of the application, security, etc. Some options such as fiber optics provide high throughput and high dependability, but are considerably more expensive for long distance applications and may be only available in the urban areas. Similarly, wireless is a viable option for urban areas where the devices are not far from one another. Moreover, compared to optical fiber, wireless is a more economical option for many DA applications, although with lower dependability and higher security risks. From an economical point of view, PLC is even cheaper as it does not require heavy investments and is therefore more suitable for rural areas where the distribution

network can be spread over a very large area. Finally, it is worth noting that compared to substation automation applications, most DA applications are not very sensitive to network delays of a few seconds, as long as the data is received before the next computation period (usually considered in the order of minutes). This makes most transmission technologies viable options. B. Network and Transport Layers While a point-to-point communication is technically feasible to implement most DA applications, the ongoing effort for developing the Smart Grid infrastructure necessitates considering routable protocols. An obvious choice is therefore IP and especially IPv6 when considering the future developments. The downside of IP and IPv6 is the overhead it would cause for the data transmission channels with limited bandwidth such as PLC when used over long distances, where a simple point-to-point protocol would be sufficient. From a transport point of view, TCP is a protocol meeting the reliability requirement needed by DA applications. Indeed, while latencies are acceptable for such applications, the assurance of having packets correctly sent and received is crucial. It is worth noting that compared to substation automation, DA cannot rely on redundant physical networks (e.g. PRP or HSR) and therefore requires software redundancy mechanisms. C. Session Layer Communication services can be based on client-server, publish/subscribe or peer-to-peer patterns. For majority of applications that are executed at the control center level, a client-server approach would be sufficiently effective. However, peer-to-peer can be useful in applications where all or part of communication with the control center fails and the system (for instance the capacitor switches, tap positions, etc) need to go to a failsafe mode. D. Cyber Security Security is an important issue for automated DA applications. In the modern smart grid paradigm, the nature of attacks to the power system have shifted from easily observable physical damages to physical assets towards more subtle cyber-intrusions and cyber-attacks that can continue for a long time without showing an immediately observable impact on the performance of the system. When it comes to DA applications, some of the most important cyber security concerns for the utilities are: • Availability – denial of service, whether issued from the server side or resulting from inaccessibility of field devices, can disrupt the performance of the DA applications. • Integrity – integrity violation by an unauthorized entity can adversely affect the performance of the network and even its configuration, which can potentially impact thousands of customers. • Intrusion – intercepting the data packets through a man-

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in-the-middle scenario, eavesdropping or spoofing are all serious security threats for a DA system that if followed by unauthorized alteration of data packets can lead to malfunction of the distribution network and in some extreme cases to system instability leading to brown-outs and black-outs. While, many of these issues can be potentially prevented by message authentication and data encryption when confidentiality is required, the major issues remain twofold: (a) the key management for such a wide and distributed network; and (b) unlike substations where a security parameter or fence can be clearly identified, most the distribution automation assets are located in the field and are easily accessible. These characteristics pose serious challenges to properly secure DA applications. VI. CONCLUDING REMARKS IEC 61850 is an international standard for communication networks and systems proposed originally for applications within the substations, which was later extended to cover systems outside substations as well. The purpose of this paper was to demonstrate through use cases that the standard’s features can be utilized for control and automation functions in the context of distribution and feeder automation systems, and pave the way for interoperable operation required in the Smart Grid paradigm. Several of the most common examples of DA applications were studied in this paper and it was concluded that with occasional need to define new logical nodes and/or data attributes, the standard in its current format can effectively provide modeling capabilities for DA/FA. The communication services can also be effectively modeled; however, cyber-security issues for the geographically widespread nature of DA/FA applications need to be investigated.

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B. Protection Logical Nodes Some of the protections LNs that are more related to the DA applications are listed below: • PDIF: differential protection • PDIR: directional protection • PDOP/PDUP: directional overpower/under-power • PIOC: instantaneous overcurrent • PSDE: sensitive directional earth fault • PTEF: transient earth fault • PTOC: time overcurrent • PTOF/PTUF: over/under-frequency protection • PTOV/PTUV: over/under-voltage protection VIII. REFERENCES [1] [2] [3] [4] [5] [6] [7]

VII. APPENDIX- DESCRIPTION OF THE LOGICAL NODES The logical nodes referred to in the case studies in this paper are listed below [11], [13]: A. Non-Protection Logical Nodes • • • • • • • • • • • •

ATCC: automatic tap changer control CSWI: switch controller for controlling any switchgear DGEN: DER unit generator DRCC: DER supervisory control IHMI: operator interface MMXN: non-phase related measurement MMXU: measurement RFLO: fault locator RREC: recloser RSYN: synchronism-check SSWI: circuit switch supervision TCTR/TVTR: current/voltage transformer

XCBR: circuit breaker XSWI: circuit switch- all kinds of switching devices not able to switch short circuits YLTC: tap changer ZCAP: Capacitor ZGEN: Generator

[8] [9] [10] [11]

[12] [13]

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