Abstracts 2016

By: Maty Ghezelayagh – TasNetworks

The setting and design philosophy of numerical relays of various passive primary plants namely distribution feeders, transmission lines, transformers and busbar are discussed. Attempt has been made to address the subjects from practical rather than the theoretical points of views. To develop appropriate criteria for setting and design philosophy, first different types of faults for each primary plant are identified. This include short circuit fault, insulation failure, core, tank, inter-turn winding fault in transformer, high impedance earth fault and open phase on transmission and distribution lines. Setting and design philosophy are described. In addition specific control devices such as voltage regulator relays and auto reclosing schemes are discussed. Different philosophies which have been applied by different utilities regarding to using transformer temperature devices for alarms or trips are mentioned along with the advantages and disadvantage of the application of different techniques for measuring the winding and oil temperature.

Required protection schemes, functionalities and logic block diagrams of different plants are discussed. In addition specification for latched and unlatched trip/alarm of protection signals and the conditions for blocking local/remote command for open/close command are given. This includes blocking under the operation of trip circuit supervision and CB SF6 gas alarm.

Different protection schemes and setting philosophy for different EHV and HV busbar arrangement namely High and Low Impedance, Arc Flash Detection, Sudden Pressure Detection, Over Current Blocking Schemes, Summated busbar protection and Frame earth leakage protection are discussed. Particularly the requirement of shunt resistor in high impedance protection to maintain stability under normal loading condition in addition to series stability resistor for through fault is described.

By: Terry Foxcroft – Snowy Hydro

Guthega Power Station was the first constructed station in the Snowy Mountains Hydro Electric Scheme. As such the generators are over 60 years old.The stator construction has two turns in each stator bar. Recently a bad smell was detected from within the generator. A full range of tests were performed but the source of the odour could not be found.

However, old multi turn bars are a high risk of failure causing permanent damage to the stator core. This paper describes the protection system installed to detect a single turn to turn fault and the calculations involved. 

It also examines the benefits of voltage detection compared to current detection, and the very sensitive settings required to detect a single turn fault.

By:  Chido Chandakabata – SEL

Percentage restrained differential protection is one of the oldest forms of adaptive protection algorithms. The percentage restraint characteristic operates on the ratio of operate-to-restraint current in the zone of protection. The restraint characteristics employed can be: Single-slope, Dual slope or Adaptive. These characteristics provide high sensitivity at low load levels and higher security for heavy loads and through-fault conditions.

The design and testing of single and dual slope percentage differential characteristics have been widely understood for some time. Some modern digital relays employ the adaptive slope characteristic with new and improved design features. Such relays use a low-security slope (Slope 1) or a high-security slope (Slope 2), dynamically switching between the two slopes based on fault-sensing logic. These design features however gives rise to challenges during testing and commissioning. This paper explores the design of the adaptive slope differential element and the testing techniques to verify relay operation. Key features of the adaptive slope characteristic namely, the External Fault Detector and the Filtered Differential logic will be explained. Testing methods for internal and external faults will be detailed, with particular emphasis on testing the high-security slope of the adaptive characteristic

By: Winodh Jayewardene, Samik Bhattacharya – AECOM  

There are differing requirements for anti-islanding protection depending on which network in Australia a generator is connecting to. This paper looks at the differing requirements of Network Service Providers as well as the challenges of identifying a suitable scheme given the lack of a ‘one size fits all’ solution. A review of equipment capabilities and international practice is also undertaken based on project experience.

By: Alexander Apostolov – PAC World

The transition of the electric power industry towards a smarter grid is characterized with significant efforts to improve the efficiency in performing all tasks and reducing the duration of outages in case of events related to the operation of multifunctional protection IEDs. The wide spread implementation of IEC 61850 based substation protection and the increased interest in digital substations based on the sampled values interface with the substation process is providing an opportunity to develop and implement protection, automation and control systems that can be tested remotely.

The testing of hardwired protection and control systems requires a crew to drive to (in many cases) a remote location to perform maintenance testing. Replacing the hard wired interfaces with IEC 61850 based communications interfaces allows remote access to the substation for remote testing. The replacement of part or all of the hardwired interfaces with communication links requires the development and implementation of methods and tools that maintain the same level of security during the testing process, while at the same time take advantage of all the benefits that IEC 61850 provides.

Improving the efficiency of maintenance testing means the reduction of time and resources required to perform the testing, as well as reducing the duration of outages that have an impact on the reliability and security of the electric power system. The paper first introduces the principle requirement for isolation of IEDs from the point of view of the maintenance testing in an energized substation – related to the testing of a specific function element, a local protection scheme or a distributed function are discussed. The specialists involved in the testing of protection, automation and control schemes are used to a physical isolation of the test object based on the use of test switches that allow on one hand to open the circuit that trips the breaker and at the same time to replace the analog signals from the secondary of the current and voltage transformers with signals coming from the test equipment. The second half of the paper describes the features in Edition 2 of IEC 61850 that can be used for virtual isolation of components of the protection scheme.

By: Alexander Apostolov – PAC World

The original GOOSE message was introduced in UCA 2 and later integrated in IEC 61850 to support the peer-to-peer communications between IEDs for substation protection, automation and control systems running over Layer 2. In order to meet the requirements for the communications of synchrophasors over wide area networks based on IEC 61850 object models and services, a technical report IEC 61850 90-5 introduced variants of the sampled values and GOOSE communications services that can be routed through wide area networks.

The paper describes the key concepts of the routable GOOSE messages introduced in IEC 61850 90-5 and then focuses on some implementation examples, such as System Integrity Protection Schemes or accelerated transmission line protection The last part of the paper discusses the methods and tools that can be used to perform the testing based on the IEC 61850 Ed. 2 definitions and how they meet the requirements for virtual isolation from a practical point of view. The benefits and challenges related to remote testing of IEC 61850 communications based protection, automation and control IEDs and schemes are summarized at the end of the paper.

By: Ian Young – Schneider Electric

The lack of tools is often given as a reason for users to delay the implementation of IEC61850. This has led to manufacturers and integrators producing tools that have a vast functionality. These tools allow knowledgeable users to quickly create substation automation systems based on the methodology given in part 6 of the standard. A side effect is that these tools also create specialists with new niche skill set. Users then see this new specialisation as further reason to delay implementation. Based on this logic IEC61850 should never have taken off, but it has and is used in thousands of substations around the world. Users have created and maintained substations without the supertool which then poses the question how have they done it and are there benefits in doing so. This paper looks at various methods used to create IEC61850 substations comparing the efficiency, processes and knowledge required to apply.

By:  Bruce Capstaff – Powerlink

Powerlink has recently developed a multi-vendor IEC 61850 Station bus secondary system. Now that this system is in place and performing well, we are progressing to developing an IEC 61850-9-2 Process bus solution.  The development process will be different from Station Bus and our Process bus road map has identified the tasks for development.  One of the main tasks is to implement a Process bus system in parallel with an operational system at one of our substations.  The intention of this trial is to investigate the ability to continue with our multi-vendor solution and to determine whether interoperability exists in the Process bus world and identify the challenges that need to be overcome to provide a multi-vendor Process bus system.  This paper will summarise the tasks and timing of the development and discuss the objectives and outcomes of the trial Process Bus system

By: Ranjan Vaidya, Diptiman Yadav – Jemena  

Jemena have embraced IEC61850 technology. Recently two green field zone substations have been commissioned using this technology. This paper shares Jemena’s journey so far in implementing IEC61850 standard. First, endorsement of this new technology is discussed, providing a sneak peek into the consultative approach adopted by Jemena. Upskilling is addressed in terms of people training and construction of a sandpit. Further, high level architecture of the two projects is described. Lastly, the methodology for much talked-about GOOSE isolation is also shared.

By: Asawin Rajakrom – Metropolitan Electricity Authority (MEA), Thailand      

IEC 61850 based substation automation is a powerful solution for substation control and protection system. It can maximize the benefit from the system interoperability thus avoiding vendor specific purchase; minimize the cabling works by replacing the traditional copper wires with optical fibers as well as allow the flexibility in system functional design. The Metropolitan Electricity Authority (MEA), the distribution utility supplying electricity to the customers in Bangkok Metropolis Thailand, is now standardizing their substation control and protection system based on IEC 61850 substation automation. IEC 61850 have gradually replaced the conventional control and protection for all existing substations whilst they are also specified for all new substations. Although utility has started implementing IEC 61850 a decade ago, but all the engineering, installation and testing works were entirely done by its contractors. There was a minimal involvement from utility engineers. This may pose a risk to MEA in losing an in-house capability to manage the critical control and protection system which in turns jeopardize its power system reliability. Management of IEC 61850 based substation automation system is a knowledge intensive task, particularly on testing and maintaining the system. Knowledge management can be employed to facilitate this task.

This paper aims to share MEA experiences in testing the IEC 61850 based control and protection on one hand, whilst to demonstrate how the knowledge engineering techniques can facilitate this testing on the other hand. In the paper, the author (i) discusses the testing processes of IEC 61850 substation automation and the challenges experienced by MEA engineers, (ii) presents the knowledge engineering methodology and its application to facilitate the IEC 61850 testing, (iii) demonstrates its practical application by implementing the techniques in MEA substation. The result shows that the knowledge engineering techniques can support MEA engineers to perform the IEC 61850 testing successfully. The knowledge gained from this demonstrated case can be systematically applied for the later projects.

By: Victor Dunand – Schneider Electric

IEC61850 engineering is often perceived as a complex and lengthy process requiring specialist resources, special tools, time and money. Today, time and budget constraints for project delivery are increasing in an ever more competitive market. Such an environment could hinder or limit the deployment of IEC 61850 systems. However, when IEC61850 is not viewed as the outcome of the design but rather as a tool for the design of the substation, significant efficiency gains can be realised; improved reliability, time to delivery and overall project execution.

Based on practical experience from recent protection, automation and control system projects this paper discusses the opportunities to improve delivery from concept design, through engineering and testing, to documentation. It highlights the challenges, limitations and lessons learnt related to the engineering process, use of configuration software and what led to the development of “in house” engineering tools and their methods.

By: Mitch Eadie, Greg Finlayson – Schneider Electric

Solar photovoltaic (PV) inverters differ from traditional embedded generators in that they utilise power electronics for the conversion of DC to AC voltage and current.  As no rotating inertia exists in these systems, it results in very low current contributions under fault conditions.  As the penetration rate of PV increases within distribution networks, the protection philosophies employed become of greater significance.  This paper presents a comparison and reasoning behind the various utility protection requirements as well as the AS4777 standard that the inverters and external protection devices shall incorporate as part of their operation.  Protection elements include but are not limited to overcurrent and earth fault, directional power, voltage vector shift, rate of change of frequency and passive anti-islanding protection via under/over voltage and frequency protection.  

By: Robert Bates,Robert Accendere, John Cass – Ergon Energy

Testing and commissioning plays a crucial role in the safe and reliable operation of a power system. The substation testing and commissioning process is designed to ensure plant and secondary systems operate in accordance with their design specifications. This process allows confirmation that plant and equipment have been constructed and installed correctly, configurations of electronic devices are as intended and systems operate as an integrated system. Initial protection relay testing strategies for electromechanical or static relays were aimed at detecting incorrect ratings and setting(s), inaccurate performance or failure in a protection element or physical component. This was a reflection of the relay’s use of analogue signals and its rudimentary self-supervision functions. The introduction of digital and numerical relays brought flexibility and expansion in the way the protection relay could be configured. The digital nature of these relays, combined with superior self-monitoring or supervision capabilities provided potential changes to the testing life cycle of digital protection relays.

This paper investigates a standardised approach for developing a frame work, philosophies and practices to ensure digital protection relays and their associated schemes operate in a reliable, effective and secure manner during the life cycle of the protection relay. To understand these challenges an Engineering Justification has been developed to define the intent, limitations and justification for testing and commissioning digital protection relays. This includes the protection relay failure modes, which includes potential hardware, software failures, procedural and administrative errors.

By: Usman Mahmood – Energy Australia, Sy Bui – Aurecon Group

Any fault in a power network is a serious and unwanted event and has to be accurately detected and isolated in the most efficient and fastest way. With the advance of digital protective relays, these critical criteria can be accomplished better than the conventional electro-mechanical protective relays. Consequently, digital protection systems are extensively used in greenfield projects and in most electrical upgraded projects.

Digital protective relays can also be programmed to capture events and waveform records at the instance of the faults in non-volatile flash memories. This feature provides invaluable benefits for protection engineers in the understanding of the origin of the faults and the performance of the protection systems in the process of detecting and isolating only the faulted sections from the rest of the system, verifying the design aspects of the protection system.

In a major fault event, there can have multiple protective elements operated and this can cause some degrees of difficulty to identify the initial source of faults. The event log can provide definitive evidence on the initial fault and sequence of events.

Combining with the event log, the waveform records can give complete and reliable information about the disturbances in the power network and the nature of the fault. For example, a protection trip caused by the transformer inrush would always have an identical current waveform regardless of the type and rating of the transformer. Similarly single phase to earth fault can be distinguished from a multi-phase fault by observing the voltage waveform and the binary signals. A library of these fault waveforms can be built to assist user in determining of the nature of the fault. The aim of this paper is to present a range of characteristic waveforms which can be expected for different types of faults and exploring the benefits of utilising this tool for fault analysis.

By: Leonardo Torelli – CSE Uniserve, Australia / Ilia Voloh – GE Energy

Single pole tripping operation is widely implemented to maintain system stability and continuity of supply on high and extra high voltage transmission line. Despite the capacity of modern circuit breakers and digital protection relays, field experiences show that the overall successful rate of single pole operation is lower to the typical three pole tripping scheme. This paper reviews three Australian field applications to highlight key difficulties of the scheme and some relay design solutions.

By: Stephan Geiger – OMICRON

In order to reduce customer outage minutes overhead distribution networks are equipped with reclosers. Such reclosers, when automated using voltage based logic or communication media, allow feeders to be interconnected to quickly restore power to areas not affected by a fault.

Communication based automation schemes allow for a very fast location and isolation of the fault, and restoration is possible in under 400ms. However, such schemes are custom made and require thorough testing prior to installation and ideally are also tested during commissioning. This paper will outline the importance of testing to ensure proper functioning of the installed equipment and will also suggests simple methods for testing of the scheme a whole.

By: Ervin Fekovic – S&C Electric Company

Automated loop restoration is not a new concept. Distribution utilities worldwide have used automated loop restoration schemes extensively and deployed them with and without device communication in order to improve reliability of supply. These schemes however, come with an inherent drawback. A conventional loop restoration scheme will detect and isolate a network fault. It will then attempt to reclose the circuit segment to determine if the fault is persistent. If the fault is persistent, reclosing acts as a fault multiplier, repeatedly stressing the primary substation power transformer, and all system components up to the fault point using all of the system’s available fault current.

After repeatedly reclosing and reaching lockout, a loop restoration scheme will isolate the persistent fault and close the normally open tie point. But if the persistent fault is located in a circuit segment adjacent to this normally open tie point, the persistent fault is transferred from the faulted feeder to the healthy support circuit.

While such systems improve supply reliability (in particular SAIDI), the mechanical damage attributed by continuously exposing primary equipment to high fault currents has only recently been seriously considered and analysed. There is a better way. Detecting whether a fault is persistent or not can be achieved without reclosing onto a circuit segment after the fault is initially isolated. PulseClosing® technology is an innovative solution where instead of immediately reclosing, the circuit is first “tested” for fault conditions before a reclose is initiated. When compared to conventional reclosing, pulse-closing will reduce the let-through energy of a fault by more than 95%. As such the stress on the system is drastically reduced and the side effects of conventional reclosing such as conductor slap, voltage sags, sympathetic tripping of un-faulted circuits due to voltage sags, and component damage are eliminated.

When pulse closing is coupled with multiple series fault-interrupters that cannot be conventionally time-current coordinated, automated, non-communicating recovery from intentional miss-coordination can be achieved. This application of pulse closing is called “pulse finding” and this paper will discuss it and other automated restoration applications achieved with pulse closing, offering APS attendees with real life examples of projects deployed in Australia and the US.

By: Martin Van Der Linde – Noja Power

Industrial automation has been around for many years, in the realm of fast local connections controlled within a small network. IEC63113 has been extensively used for logic implementation in PLC, but it is the advent of IEC61499 and event based logic processing that we have seen a proliferation in usage of IP based distributed control.

With the growing capabilities of IP based communications for pole top switchgear within utilities it seems a natural progression to allow for distributed logic to be executed across a distribution network as a whole, using the current communications medium and framework as the transporter and a VPN for security. This paper explores the new capability of using IEC61499’s logic design in pole mounted reclosers to create customised distribution automation and smart grid capabilities without the need for master station control. By sharing the hardware requirements across an entire network of recloser controllers, it is possible to create elegant and responsive algorithms to improve network reliability.

Access to IEC61499 application design and implementation allows for improved integration in IEC61850 schemes for recloser control. IEC61499 offers expanded portable configuration options with information links through definable Dynamic Data Type objects available for access by both protocols in a centralised database within a controller. This paper outlines the capabilities and future applications of IEC61499 in the world of pole mounted reclosers. As Australian utilities look for the best return in their capital equipment, this new implementation allows for the optimisation of switchgear for maximum return and value for distribution network operators.

By: Shantanu Kumar , Syed Islam – Curtin University / Narottam Das – University of Southern Queensland

Zero recovery time is an essential feature of a digital protection scheme in any fault scenario. For the protection to maintain its resilience, it is expected that a failure of a link or switch in digital protection should not compromise the overall protection scheme which in reality it is supposed to guarantee. The advancement in digital protection leveraging on IEC 62439-3 addresses the redundancy issues based on two complementary protocols such as, Parallel Redundancy Protocol (PRP) and High-availability Seamless Redundancy (HSR). These two topologies have redundancy features built within the protection scheme. They overcome a link or switch or a node failure during a zero switchover or delay time. Furthermore, the issues arising due to single port failure and interoperability problems related to multi-vendor equipment are addressed better in IEC 62439-3 initiated by the IEC working committee and published in 2010. The manufacturer of the Intelligent Electronic Devices (IED’s) took into account all the shortcomings of Ethernet network failures, such as Doubly Attached Node components that provided redundancy in protection having two active frames in the ring. The PRP and HSR topologies provide means of redundancies in the protection schemes and communication network to standardize the Ethernet protocols which were vendor specific having interoperability issues.

In this paper, the author attempts to compare the performances between the PRP and HSR topologies using an Optimized Network Engineering Tool (OPNET) simulating tool. It has validated the results in a lab set up using these two topologies and recommended its application in a utility run high voltage substation.

By: Pejman Peidaee, Akhtar Kalam – Victoria University

echnically protection settings are predetermined according to fault current levels in distribution networks. However, interconnections of Doubly-fed induction Generators with Ride through (RT) capabilities are introducing an altering effect on fault current levels leading to inaccurate protection settings for protection systems. Thus the main focus of this paper is concerned with the investigation and analysis of the fault current characteristics in DFIG systems and its challenges for protection settings in distribution networks. The proposed methodology is to develop and incorporate RT capabilities in time domain simulation for a typical distribution system interconnected with DFIG system. Furthermore, various operating points under different fault scenarios are investigated in order to highlight effective parameters for fault current analysis in interconnected DFIG system. Given the complexities for fault current calculations in DFIG systems interconnected into distribution network, the outcome of this paper is potential to provide protection engineers with an insight for reliable and effective protection settings in the aforementioned circumstances.