B Remote Access for Substation Automation Systems: Needs, Technologies and Applications. Schneider Electric

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1 CIGRE , rue d Artois, F PARIS http : // B5-205 Remote Access for Substation Automation Systems: Needs, Technologies and Applications JM. BOISSET RTE France L. HOSSENLOPP Schneider Electric France SUMMARY Substation Automation has gradually been developed during the last 20+ years. The initial focus has been on real time behavior of the protection and control system, and on the telecontrol interface. This has now reached an industrial phase, with distributed system relying on IEC 61850, standard bays, etc. The non real time aspect of this business is still subject to improvement in order to optimize the overall cost of ownership. This is where the remote access to the substation plays an important role. This paper first presents the state of the art in French transmission substation and defines the new features needed. It then discusses the new technologies available to achieve it in an open way, taking on board the existing assets. KEYWORD: Substation Automation, IEC 61850, asset management, version management, setting management, cyber-security, remote access. 1

2 1. Introduction Substation Automation has gradually been developed during the last 20+ years. The initial focus has been on real time behavior of the protection and control system, and on the telecontrol interface. This has now reached an industrial phase, with distributed system relying on IEC 61850, standard bays, etc. The non real time aspect of this business is still subject to improvement in order to optimize the overall cost of ownership. This is where the remote access to the substation plays an important role. This paper will first present the state of the art in French transmission substation and define the new features needed. It will then discuss the new technologies available to achieve it in an open way, taking on board the existing assets. 2. State of the art Remote access to substations, with the exchange of non operational data (disturbance records, relay setting, etc.), is today often a side function from the core substation automation system. This is partly linked to the technology maturity at the time of the system design: remote communication was first available through a low speed PTSN link, cyber-security technology in power utilities was at its infancy and effort was first on industrializing a core substation automation system. The substations remote access architecture is typically composed (see figure 1) of a set of independant PC-type applications, communicating through PSTN networks. This leads to frequent troubleshooting during access, as difficulties of maintenance and inter-operability between all these applications. Figure 1: Remote Substation Access Architecture (Current) The remote access must be seen as a whole, a set of services for the utilities needs, which can be classified in 4 domains: 2

3 Exploitation, covering the supervision of the HV apparatus / network, Maintenance, covering the supervision of the protection and automation system, and allowing remote actions like system diagnosis and system database download Engineering, covering the asset management Management, to provide dashboards and key performance indicators related to the 3 above domains 3. New Substation Needs Hereafter a set of new needs, which allow improvements in the 4 domains defined above. a. Asset management Assets in a substation represent a large part of a utility ownership, and must so be tracked with precaution, for identification and maintenance purposes. Asset management is today mainly performed manually, for the HV apparatus as well as for the protection and automation system. This can lead to errors, generating a wrong view of the real utility assets and wrong schedule of maintenance works. Thanks to the CEI data modelling, the assets can be identified at the substation level, through the use of the DPL common data class (Device Name Plate). This model includes information like vendor name, serial number, model, location. Using standard IP communication technologies, this assets identification can be then easily transmitted to a central remote database from which all types of extraction can be defined. b. Version management The System Configuration management covers the release management of : The system software The configuration data The security data. (Nota: the hardware release management is covered by the asset management) The release management means the capability to clearly identify which releases are installed on a control system, and gives the tools to be able to exchange (i.e. upload and download) with the system the different types of information. The use of a substation automation system implies, for utilities, the follow-up of a (sometimes) large number of system versions and/or configuration database releases, due to anomalies fixes and/or evolution integration. All means allowing to speed-up, in a very secure environment, the deployment of any releases from a remote centre will have an immediate benefit in term of people security (no need to take your car to go inside the substation to install the release) and maintenance cost decrease. However, the test part remains a critical activity after any new release deployment : so the remote testing must also be defined to allow the remote system configuration management being really used. c. Setting management 3

4 During system commissioning, settings are well-defined and stored in all protection and automation equipments. During the substation life, the settings will evolve for a lot of different reasons. As for system and data configuration releases, an immediate benefit is the capability to transfer them from a remote point (without forgotten the testing part). Substation setting evolution can impact other substations, or other equipments in the same substation. As such the coherency check between all related settings will be a must. Real-time setting, linked to functions like Dynamic Line Rating, can now be used when protective relays provide a standard interface, based on IEC 61850, to modify tem. d. Grid failure management In case of a grid failure, the goal for a utility is to speed-up the operation recovery and limit the outages time. The future remote access technologies will allow to: accelerate the access to relevant data (COMTRADE files, event logs, fault distance, real-time substation images / video, ), using real-time transmission rather than upload on request insure fluidity of information between network actors enable precise and quick fault localization represent the dynamic schematic network. Fault localisation is a well-known function, frequently used today. This function can be improved, allowing: The identification of the most critical events The precise localisation of an event to reduce the intervention time The identification of the fault origin, optimizing the creation of corrective actions (for example, repetitive default due to vegetation will conduct to a pruning action) The continuous improvement of the protection system e. Other new needs Efficiency improvement for the testing of the devices and the system is expected, during commissioning, maintenance and extension phases, in order to reduce the project lead time and feeder unavailability. This is especially sensitive for new requirements in term of distributed functions and remote testing. IEC is providing some basic mechanisms to control the modes of the logical nodes and the communication flows, in order to build userfriendly high level applications. Condition monitoring in general is a way to improve the maintenance efficiency. This applies first to the primary and secondary devices through on-demand maintenance anticipation and correlation between primary and secondary data instead of periodic maintenance split between devices. Different levels of analysis corresponding to the use of existing devices (digital protection relays) or optional dedicated ones (for instance circuit breaker speed footprint check) shall be available depending on the substation importance and the installed devices. Further condition monitoring can be applied to the contribution to the grid congestion optimization and to the substation security check. Dynamic line rating and transformer overload management are some of the solutions mixing actions at substation and control 4

5 center levels. New sensors and communication links might be needed to achieve this. Usage of video camera is a way to enforce the substation security. 4. Technologies This section lists a series of technologies needed to achieve a modern remote engineering of the substation. They should be seen as add-ons to the existing substation systems, complementing the current architectures by new functions and possibly new devices and communication links. a. Standard & their evolutions IEC is the clear cornerstone of such future evolutions. The standard is progressively adding new features. The second edition of the documents has for instance refined the logical node mode management. Extension of the data modeling, for instance to cover the Ethernet switches and condition monitoring, is now available as a new logical node. On-going discussions include the integration of the system management functions; these are likely to directly contribute to the remote access to the substation requirements: dynamic detection of the devices connected on the network, software downloading, setting coordination, etc. Usage of web services to execute them is one of the design choice options being considered that would definitely facilitate the remote access to substations. Remote maintenance will however include other data not yet modeled, for instance PC resources, video-camera, etc. where again web services might be the right answer. Some gaps still exist. For instance defining the dependency of different parameters, in order to answer to one of the above needs is not yet defined. The rule engine, as discussed later in this paper, provides a solution based on proprietary add-on to the standard. IEC is companion standard defining the cyber-security measures, and that is especially important for remote access to substations. On-going discussions on the management of the cryptographic keys are needed for a full implementation of this technology. b. Cyber-security for substation The cyber-security is implemented through two functional groups that shall be implemented into some substation hardened products (i.e. no moving part and EMC compatibility) represented in the figure 2: - Secured gateway: this is the access point from the outside of the substation, containing firewall, antivirus and intrusion detection. This is widely available and already used in many substations. Note that if the telecontrol link is already secured, this will not use this path. - server: this is providing the authentication and authorization to the substation devices, collecting their security records, and liaising with some corporate security servers. This is not so widely available due to the need for IEC compatibility in term of protocols and objects, the need to manage the loss of communication inside the substation or between the substation and the remote security servers, and the need for machine-to-machine behavior without IT specialist. 5

6 Ideally the IEDs shall enable a Role Based Access Control, enabling to define which role can have access to which function. With regards to the remote access to the substation, this would for instance enable to read data, manage setting or reset alarms to specific roles. In the case of legacy devices that cannot be updated, this function will be emulated by the security server. Corporate Level ERP Gateway Corporate CS Control Center level tools SCADA/EMS/DMS Gateway Server Substation Server Gateway IEC IEC Engineering Tools IED HMI IED IED c. Remote access infrastructure Figure 2: Cybersecurity in the substation The remote access infrastructure provides an interaction with the substation through a web service computing hosted in the customer premises or in a third party supplier. This Software As A Service approach enables to centralize a flexible and scalable processing of basic information exchanged with the substation and redistribute it to multiple users in the customer and suppliers organization. This eliminates the need for synchronizing user software with substation software. The infrastructure is made of: - A gateway, exchanging in a secure way data with the cloud (thus also using the cybersecurity concepts explained above). The gateway is a function that might be a dedicated device (as per the figure 3 below) or hosted in an existing device of the substation, depending on the existing infrastructure (RTU or Substation Automation System). The gateway is added to an existing installation without necessarily changing it. - A remote service platform, hosted in the internet cloud. This platform host the processing of data existing in the substation in order to create higher level information exchanged with the remote users. For example it might provide a footprint of the existing devices and associated version in order to be integrated into an asset management system. 6

7 ERP (legacy & bridge) SFDC Customer Repository Customer /Partner/User Acquisition Service Catalog Management Customer Support Ticket Management Service Management Usage tracking & reporting for invoice Subscription Management SLA Management Device & Asset Repository M2M Services Service Management Network mgt. (GPRS, WAN, ) Data Provisioning, admin Consumption tracking & management & reporting Device & Asset Firmware & registration, conf, mgt Application mgt QoS & SLA Monitoring Service Delivery Ser vice 1 : RMS Service 2 : Service 3 : UI Framework UI Components Mobile UI Remote Monitoring Data Repository Data Archiving Service Data Abstraction Data transformation & mapping Delivery Data Polling Management Device remote Connection mgt Remote Services Platform Schneider Electric Remote Services Portal KPI, Status, Log & Audit Cloud Infrastructure Device Data Customer Care Center Expertise Center Supervision Data & events Customer Gateway IEDs d. Rules engine Figure 3: Remote Service Infrastructure Typical Example A rule aims at formalizing human reasoning resulting from the experience of multiple situations. A rule engine is a tool that automates the analysis in order to prepare a decision, possibly launching the associated actions. The usage of IEC enable to rely on data semantic provided by the IEDs, or by a proxy that will convert the legacy protocols to IEC The data semantic is essential to apply a same rule to a large series of data without investing into expensive engineering. The rules might be applied to different domains. For example a rule can check the plausibility of the voltage measurements of different feeders connected to the same busbar. It can verify the consistency of setting parameters between protection relays located in different substation thus insuring the protection system integrity. It might detect software and database version consistency, etc. The rules can be executed locally in a substation or globally for a set of substation, respectively in the Gateway or Remote Service platform introduced above. They can be dynamically configured to assist the maintenance and asset management people. e. Testing Remote testing of a substation automation system is one of the new frontiers to improve the efficiency of the lifecycle engineering. This testing is targeting update, no new installations, happening in case of bug or of substation extension. The confidence in this testing imposes to do it by steps, i.e. typically at IED level, before moving to the system level. IEC is defining the concept of logical node mode, where the outputs to the real process can be blocked in order to proceed to test. This is specific to one logical node and shall not interfere with the other ones. It also introduces the capability to switch the source of data feeding the algorithm to a simulation source. 7

8 Remote testing shall thus add to the existing substation automation system a simulation tool, containing the scenario to be played, and an analysis engine that will check that the result of the scenario fit with the expected theory. It shall then use IED that implement properly the mode management and the usage of simulation flow. For protection devices using conventional current and voltage transformers, this means the capability to accept process bus type of signal. This is still at prototyping stage. 5. Conclusions This paper has presented the current state of the art for remote access to substations, some examples of new needs and some new technologies to answer to the needs. The associated devices or pure software come in addition to the existing RTU or Distributed Substation Automation System. They leverage the existing standard in term of data modeling, communication services and cyber-security, and might complement some of the still standard gaps. They also maximize the usage of common communication, processing and storage infrastructure in order to reduce the cost of ownership and facilitate the usage of the remote access. Fundamentally this leads to an evolution of the utility information system, fully integrating the substation automation system needs into a global framework. 8