Abstracts 2018

Alexander Apostolov – PAC World, USA

Multi-terminal lines impose some significant challenges on the traditionally applied distance protection caused by the infeed from the multiple sources. Communications based protection schemes provide a better and faster solution. The first part of the paper describes the challenges of implementing distance protection based solutions. The second part of the paper describes the implementation of IEC 61850 based directional comparison protection scheme using superimposed components based directional detection. The use of RDIR and PDIR logical nodes to implement the protection scheme is discussed. The use of GOOSE messages is later described. The third part of the paper analyzes the different communications architectures available for substation-to-substation communications:

• Direct interface between substation edge bridges
• Tunneling of GOOSE messages using MPLS
• R-GOOSE

The last part of the paper discusses the functional and maintenance testing of the protection systems for multi-terminal lines.

Detlef Raddatz – SystemCORP Embedded Technology

The demand for intelligent electronic devices (IEDs) in SMART Grid applications is continuously growing. The communication method and media for these devices is clearly defined using internationally recognized standards such as IEC 61850. The functionality of these IEDs is typically fixed. However, the demand for distributed process control devices with a user programming interface is also growing. The international standard IEC 61131 defines a programmable logic controller (PLC) implementation suitable for SMART Grid automation.

IEC 61850 communication and IEC 61131 automation can be seen as independent software applications in a SMART Grid IED, which requires a well-defined interface for the information exchange between both applications. Different data exchange methods are available, which allow the reporting of real-time data events as a result of IEC 61131 PLC logic and the processing of command structures received by the IEC 61850 communication front-end of the IED.

Data type compatibility and data type conversion rules for data events between IEC 61850 and IEC 61131 need to be considered when developing such interface.

Control commands are normally processed differently in an IEC 61131 PLC compared to the handling of commands in a telemetry system. IEC 61850 adds even more complexity to command structures.

IED configuration requirements for IEC 61850 modelling impact directly on the data interface to the IEC 61131 PLC application and vice versa. Any configuration change needs to be managed taking into consideration the desired PLC functionality and also the presentation of data via IEC 61850 on the substation local area network.

Data and command interfaces can be integrated as direct relationship between both applications or alternatively through a real-time data base system. Both implementation methods are suitable for SMART Grid IEDs. The best implementation method depends on the actual functionality of the IED. The selection of a suitable processor platform needs also be considered.

For a successful integration of both applications target platform relevant firmware is required. These applications should be modular and portable between different hardware and software platforms with a common interface to user programming and configuration applications on host computer systems, which allow.

A successful integration of both standards in an IED depends on the implementation method. This presentation shows a real use case for a substation using a substation bay control unit (BCU) deployed in GIS switchgear designs.

Thomas Schossig – OMICRON electronics GmbH, Austria

Since IEC 61850 became the widely used standard for substation communication with a lot of implementations testing is an important issue. Edition 2 offers a wide range of possibilities and sophisticated details. To combine the different possibilities for smarter testing the client becomes more important in the workflow. On the one hand the client controls the setting of the modes of the logical nodes and the resulting behaviour of the logical nodes. Additionally the LPHD.Sim Value can be set by clients as well and has an impact on the interaction with GOOSE and Sampled Values in the IED. Accessing the device under test with a client offers additional opportunities. Every value stored in a data model can be read and used for assessment. Using the Reports in that case tests the entire chain of communication and tests the SCADA communication out of protection testing. This paper presents a practical implementation in an existing protection testing solution. To have the client embedded in protection testing scenarios opens wide perspectives for new methods in testing. They will be described. The method described is covered in testing procedures developed with utilities as well as an input for international standardization. The paper describes the challenges and the technical solution to be utilized for improving the reliability and quality of testing.

Musafare Chibowora, Hamilton Monzen De Figueiredo – Siemens Australia

IEC61850 is a global standard for protection, communication and control of substations. It brings the advantages of modern networking technologies to substation automation and offers a guarantee of inter-operability between systems from different vendors. An IED is a device that performs electrical protection functions, advanced local control intelligence, has the ability to monitor processes and can communicate directly to an external source. A substation automation system is an integration process that involves remote access of power system equipment, such as circuit breakers, transformers and capacitor banks. The system uses Intelligent Electronic Devices (IEDs) and RTUs to receive or send data for the purposes of protection, control, interlocking and monitoring of a substation. The exchanged data includes relay configuration information, equipment status, metering, waveforms, event data, diagnostic information and others and is gathered in real time for better asset and operational management. This digital revolution from the power industry is now being adapted and used in traction power distribution networks. This paper describes the testing employed on Australia’a first IEC 61850 digital automation system implementation in a rail environment. The system has more than 200 protection IEDs spread across in more than 20 DC traction substations across the network, this also includes the integration between more than four protection IED vendors.

Shantanu Kumar , Dr. Syed Islam – Curtin University

Dr. Narottam Das – University of Southern Queensland

Conventional methods of protection and communication based on secondary cables between substation primary plants within the High Voltage (HV) substation switchyard and control room equipment have few limitations, such as time consuming and laborious fault diagnosis. Some utilities have reported catastrophic failure of their instrument transformers disrupting normal power flow and causing unnecessary power outages. Advancement in digital technology and use of fibre optics in the switchyard equipment have given a new dimension to the application of Non–conventional Instrument Transformer (NCIT) which has reached a level of maturity and performance. NCIT is an alternative to the conventional instrument transformers that offer significant benefit in terms of operational performance, safety, environmental values, and many engineering advantages.

New technology in substation protection, automation and control have made it possible to protect costly primary plant assets, such as switchgears and power transformers by using Intelligent Electronic Devices (IEDs) in the protection schemes. Digital IEDs and Merging Units (MU) exchange Sampled Values (SV) and Generic Object Oriented Substation Events (GOOSE) via fibre optic cables in a process bus environment, replacing heavy copper wires. Use of Ethernet offer faster tripping in the event of a fault.

This paper evaluates the performance of a digital protection scheme featuring NCITs, MU and IED’s using an Optimized Network Engineering Tool (OPNET) as well as a laboratory based experimentation. Understanding the End to End (ETE) delay in receiving time critical GOOSE and SV messages in a process bus scheme of a smart grid substation provides confidence to use NCITs in future grids.

Christopher Pritchard – OMICRON electronics GmbH, Austria

In the early days of electromechanical (EM) protection, the cause for misoperations was very often found in the relay itself. Temperature, vibration and other influences caused the relay threshold to drift or caused complete mechanical failure. Thus testing procedures were installed to commission and periodically maintain the protection relays. That is why the goal for the majority of test cases today is still the verification of threshold values.

Since the introduction of the first digital relays the power and complexity of the relays continued to grow. Due to now affordable communication technology a relay is now part of a bigger protection scheme. As a result, the causes for misoperations have shifted towards logic, settings and design errors as the NERC misoperation study shows, but so far testing did not adapt. It is time to rethink our testing procedures! With limited testing time and resources, we have to invest our efforts, where we can actually find errors and prevent misoperations.

Our field experience showed, that although the protection was commissioned with conventional testing tools, we regularly found errors using a system-based test approach. System-based test approaches are well established in end to end testing, where the test case is derived from a power system simulation of a real world fault scenario. This principle was further improved to be applicable for every protection scheme with minimal effort. Experience of many different field tests performed with a system-based testing tool were collected and will be shared to proof the importance of system-based testing for the future of every commissioning.

Luke Napier , Robert Coggan – Energy Queensland

When Ergon Energy changed its network modelling package an opportunity was realised to update the way it undertook basic protection studies. The change in modelling package allowed for data to be harvested automatically and published reliably. Ultimately the change is envisaged to allow protection designers to focus on the more complicated aspects of a design and remove the routine analysis and data manipulation.   The change in modelling package was a ‘soft’ roll out. Where by the existing modelling software was available in parallel with PowerFactory™.  This allowed a staged approach for user adoption and development.   The initial goal was to have the Protection designers use the tool in its native format (no additional skill sets beyond operating the tool). This involved developing process and user guides to replace the existing techniques. It was soon realised that a Python scripting skill would assist in terms of speed and quality of some of the more laborious tasks.   With access to scripting skillsets the tool and process and depth of information has been organically improved by subject matter experts in the Protection Team. This allows a fully populated set of models that can be continuously improved. Due to a structured dataset model issues can be addressed across a large model base.

With a growing knowledge of the PowerFactory™ the previous method of performing a protection study where a predetermined outcome is now being questioned. With more intelligent software wouldn’t it be better to observe the modelled protection system and record the outcome?

The total lifecycle of a protection setting from its initial conception to decommissioning has always been a challenge to maintain particularly in the distribution network. When changes occur on the network having the ability to assess the impact on the protection system in near real time could have significant benefits.

Terry Foxcroft – Snowy Hydro

Shaft voltages are generated axially along a large motor shaft. If not correctly identified, these voltages can cause large currents that will destroy bearings in minutes.

This paper shows how the shaft voltages are generated, actual shaft currents and their harmonic content, designs to avoid shaft currents, and different shaft current detection methods. It also shows results when systems have failed and destroyed bearings.

It does not include anything about transmission protection.

M.Ghezelayagh , Robert Scott – TasNetworks Pty Ltd

Information on accurate fault location after a system fault is important to field crews in order to rectify it and restore the power to consumer in minimum possible time. There are several techniques which have been investigated for fault location on EHV transmission line as indicated below:

Although there are some new numerical relays in the market which use traveling wave technique for calculation of distance to fault but most of modern relays are still use impedance measurements. Some relays measure reactance instead of impedance. The advantage of reactance based technique is that the magnitude of fault resistance does not affect the measurement. Some relays use multi ended measurement using communication bearer of current differential relays to obtain remote end current and voltage signals in addition to local end measurements. However in all cases accurate distance to fault can not be obtained if transmission lines conductor is not homogeneous or there are multi circuit along the line.

In this paper a new approach utilizing existing fault location functionality of numerical relays and off-line system studies is proposed to give accurate distance to fault on a real EHV transmission line with multi-type conductors and multi-circuits. The procedure is based on implementation of following steps:

In order to illustrate the practicality of the above approach, the technique has been applied on a real EHV line with different conductor size and multi circuits and implemented in SCADA.

Finally, common errors which in the past have resulted to wrong indication of distance to fault by an IED and misguided the field crews to rectify the faults are given.

Leonardo Torelli- CSE Australia

Ilia Voloh- GE Energy

More stringent safety regulations related to high impedance fault detection are pushing utilities to utilise the full capability offered by modern protection relays. A good example is the use of the line ground differential element 87LG to further increase the sensitivity of the typical 87L line differential scheme.

This paper documents the results of extensive testing for a 275 kV transmission line application using a Real Time Power System Simulator, RTDS. The paper investigates the 87LG design which considers transient conditions, selectivity with the other line protection schemes, impact of CT inaccuracy, evolving faults and challenging applications such as a series compensated line. The study focuses on a transmission line with a solidly earthed system but considerations will be provided for resistive earthed networks as the implementation of the line differential scheme is now becoming more common on distribution lines.

Usman Mahmood – Energy Australia

Sy Bui- Aurecon Group

Protection systems are an essential and critical part of any power network. Modern Intelligent Electronic Devices (IEDs) are the brains of such protective system, equipped with overwhelming features such as relay watchdog, event logs, trip logs and waveform records. The information obtained from such devices greatly assists in the fault diagnostic process.

Many engineers in the industry are over reliant by the self-testing ability of numerical relays and consider them indestructible. Moreover, some of them believe routine testing on such relays is becoming unnecessary due to the fact that such relays are not prone to setting drift issues.

Determining the right testing frequency of such devices is still a great challenge faced by site engineers and management. On one hand, majority is led to believe in self-monitoring capability of these devices. On the other hand, premature failures, design flaws and complexity of modern IEDs dictate frequent testing.

Though numerical protection relays are often equipped with automatic self-testing functions to verify correct operation of the critical relay components, such monitoring function have certain limitations. For example, the analogue input section is typically monitored by an automatic self-testing feature, but it cannot detect errors which may be present due to partial failure of the components in the analogue to digital (A/D) converter. The self-monitoring feature provides minimal supervision of the digital input and output (I/O) contacts. Hence, relay watchdog cannot be relied upon about the overall functionality of the relay.

The aim of this paper is to present forensic investigation into the premature failures of two IEDs at Mt. Piper Power Station and argue the case for routine testing.

Terry Foxcroft – Snowy Hydro Limited

Normann Fischer, Dale Finney, Ritwik Chowdhury, Marcos Donolo, and Douglas Taylor – SEL

Currently in the United States, there is about 20 GW of pumped storage hydro generation installed. An additional 30 GW of new capacity has been proposed for support of renewable generation such as solar and wind. This paper describes the challenges associated with protecting these units and how digital relays can provide simpler and more effective protection. The following topics are covered:

Switching from generator to pump mode impacts protection elements that use sequence components. A second impact occurs if the differential zone includes the reversing switch. A third issue is a bad status signal from the reversing switch. The paper describes how a digital relay can address these issues.

Units that start as induction motors require protection for the damper winding, which has typically been provided by an overcurrent relay or even a simple timer. An alternate is to use a thermal element based on IEC 60255 with RTD biasing. The paper discusses the merits of this thermal-based solution.

In the past, units that started while connected to a variable frequency source used overcurrent and overvoltage relays with wide frequency responses to supplement the differential and neutral overvoltage elements. If a digital relay with frequency tracking is used, these supplemental elements are no longer required.

In early electromechanical schemes, out-of-step (OOS) protection took the form of an inverse-time overcurrent relay. This paper discusses the advantages of impedancebased elements present in digital relays that can provide a superior method for protecting against OOS conditions.

If the generator step-up (GSU) transformer is downstream from the reversing switch, the transformer effectively changes its vector group when the reversing switch is operated. A second issue can occur if the tap from the GSU transformer is used to implement low-voltage starting, which effectively changes the turns ratio of the GSU transformer. The paper discusses how both these issues can be addressed using a digital relay.

Sebastian Schneider – Siemens AG

Transformers are very important protective objects in the electrical energy system. Therefore different protection principles as well as devices are used in the different applications. From the engineering point of view the different design of transformers have a great influence on protection concepts. The changing in the electric energy system due to installation of large number renewable energy station leads to a lot of challenges for control and protection. For an efficient control of the power flow phase shift transformers are installed in the energy system. These types of transformers have specific requirements on the design of the differential protection. The paper addresses different aspects in the field of transformer protection. It starts with a general discussion regarding basic design of the protection schemes and presents a concept which is used in Germany. Further the basic concept of a modular hard- and software design will be discussed. With this design different types of transformers can be protected and allow technical as well as cost optimised solutions. With an autotransformer scheme the new possibilities are demonstrated. That means two different differential protection functions are active in parallel in the IED. A phase to earth fault can be detected phase selective in an autotransformer bank design.

A further focus of the paper is the differential protection. From the practical experiences over some decades two main points are discussed. The first point is the inrush detection. The 2nd harmonic criterion is the typical detection principle. Due to the different magnetic conditions as well as magnetic characteristics of a transformer an overfunction is possible due to less content of second harmonics. In the new design of the function a second principle operates in parallel. It bases on the analysis of the current wave form (CWA method). With a one out of two design of the inrush detection function an improvement can be achieved. The second point is the stability during external faults. In that situation the transient performance of the current transformers plays an important role. An additional requirement on CT design comes direct from the differential protection function. This is the required value of the transient performance factor (Ktd). This factor influences the construction of the CT (size) and shall be low as possible. The paper shows new solutions which have an impact on the algorithm design. The basic ideas are described.

A new application area in the differential protection is the phase shift as well as special transformer. In this field the classical design of differential protection cannot be used. That means the conventional correction of a phase shift in steps of 30 degrees. A flexible angle adaption is necessary. This allows the numerical technology due to a universal design of the “phase shift adaption” matrix. The basic changes in differential protection for this kind of application are presented and the differences between the typical applications are shown.

Ritesh Bharat – Jacobs

Detecting high impedance (Hi-Z) ground faults has been a challenge for utilities for many years. Depending on the conductivity of the surface where the fault occurs, conventional detection technologies based on measurement of current magnitude may fail to operate.

Concrete, grass, clay, or foliage surfaces can limit the fault current values on a distribution system to a very low magnitude. Under such conditions, the protection relays cannot distinguish between high-impedance faults and load unbalances. The undetected fault allows the system voltage to continue to exist on the broken conductor. The arcing that results under these conditions can have severe consequences. The high temperatures emanating from these arcs can even crystallize the silica in the surrounding ground. This creates a path to ground and a situation where in there is no visible sign that the conductor is energized. The inability to detect Hi-Z faults poses safety risks to humans, animals and to natural environments. In addition to the ethical reasons to reduce the safety risks, utilities may also face legal liability risks.

Waldemar Petersen invented that by introducing an inductance to the neutral point of the system, the capacitive earth-fault current of the network can be reduced close to zero and thus most arcing earth-faults would self-extinguish. Based on this principle, a group of researchers in Poland evaluated the possibility of feeder earth-fault protection based on admittance measurement. It was found that this was inherently immune to fault resistance and hence had universal applicability and high sensitivity.

Rapid Earth Fault Current Limiters (REFCL) technology is a step ahead in identifying low earth fault currents and causes the phase voltage of the faulted phase to be reduced to near earth potential, thereby eliminating the flow of fault current. This paper discusses various aspects and benefits of using REFCL technology.

Ervin Fekovic – S&C Electric Company

The uptake on automated FLISR (a fault location, isolation, and service restoration system) systems by distribution utilities globally has been on a rise.  This is mostly attributed to increased pressures of maintaining reliability as a result of climate change. Record highs in temperature, stronger winds  and more frequent droughts all lead to increased risks of prolonged outages, but also bushfires. 

Following the aftermath of the serious bushfires in Victoria in 2009, which resulted in Royal Commission, the Victorian Government mandated a series of mitigation strategies, including the suspension of reclosing and the deployment of resonant earthing systems, specifically the Rapid Earth Fault Current Limiter system (or REFCL), with a particular focus on high bushfire prone areas.

REFCL system however are complicated and difficult to integrate into existing infrastructure. The system uses an arc suppression coil normally installed at a substation, which then collapses the voltage of a faulted phase while the voltage on the other two phases is increased. This usually means that significant network upgrades need to be performed, for example; upgrading surge arresters to withstand the higher voltage.

An possible alternative to a REFCL system is a distributed FLISR system implemented in conjunction with advanced distribution control switching hardware and a high speed communications network. Such systems can provide enhanced functionalities that require very low latency such as low impedance fault detection and dynamic protection coordination in order to improve feeder segmentation. As the decisions are made in the end devices, this functionality is unique to the distributed intelligence architecture and is not easily achievable with either centralised or substation systems due to the inherent latency of those architectures.

Peter Mangan – Applied Power Technologies Pty Ltd

Traditional protection assessment techniques are limited in their ability to address the variability in today’s electricity supply networks. Time Current/Distance coordination and R-X diagrams are static (point in time) depictions of the performance of a limited set of like protection elements on a specific grading path for a contingency under a single network state. The time demands of this methodology make them inefficient for identifying weaknesses in the protection systems provided by modern numerical relays deployed on today’s complex interconnected and dynamic networks. A new paradigm is required to perform systematic protection security assessments, analysing the selectivity, sensitivity and speed of complete protection systems, across the multiple grading paths that present in large networks, throughout the staged clearance of different fault types under various operating conditions.

Technologies addressing this sophistication are emerging. Scripting capabilities provide study automation and advanced time-stepped simulators investigate performances throughout entire fault clearing cycles. Protection system models are maturing to capture the design complexity inherent to the utilisation of multifunctional numerical protection devices as relay supervisory elements and internal logic can no longer simply be assumed to operate. Post processing algorithms are also developing to provide concise and detailed visualisations of protection performance across multiple schemes for credible contingencies throughout wide area networks.

This paper explores these technologies. It considers case studies for each, investigating their strengths, weaknesses and application to provide a comprehensive insight into the role they play to ensure secure and reliable operation of today’s protection systems. Finally, it considers tomorrow’s landscape, as these technologies merge with sophisticated CIM compliant high integrity enterprise information systems to manage the network topology and protection model information.

Anisur Rahman – ABB Australia.Pty Ltd.

The occurrence of an arc fault, the most serious fault within a switchgear system, is mostly associated with extremely high thermal and mechanical stresses in the area concerned. Power system operation fault statistics reveal that a vast majority of the switchgear arc faults are caused by incorrect human actions or by aging network equipment. Both of these causes are unavoidable in some extent. It is well accepted that by investing in protective equipment such as arc fault protection, the safety and security of the switchgear system can be enhanced.

Time is a critical parameter in reducing the effects of arc faults, as the arc incident energy rapidly increases by time. An arc fault lasting more than 200 ms may cause severe damage to the installation. If the arc flashes for less than 100 ms the damage is often limited. If the arc is extinguished in less than 4 ms the damage will be insignificant. To minimise the operation time, different arc detection technologies are evolved such that high speed outputs are incorporated in the IEDs and the benefit of using IEC61850 GOOSE messaging is being used to transfer light signals between inter IEDs. Although the main circuit breaker speed is still under challenge.

Various arc protection schemes have been used to protect MV switchgear for long time. Although the principle is simple and easy to implement, the products available in the market are sometimes complex, expensive and do not provide complete solutions. In this session different arc protection systems are discussed highlighting the benefits and shortfalls of each system and finally discuss the world’s fastest Arc Protection System with Ultra-Fast Earthing Switch (UFES). It is a new, active arc fault protection system based on the know-how gained from decades of experience with the ABB vacuum interrupter and IS-limiter technology.

The system is a combination of devices consisting of an electronic device and the corresponding primary switching elements which initiate a 3-phase short-circuit to earth in the event of a fault. The extremely short switching time of the primary switching element, less than 1.5 ms, in conjunction with the rapid and reliable detection of the fault, ensures that an arc fault is extinguished almost immediately after it arises. With a total extinguishing time of less than 4 ms after detection, an active protection concept with the Ultra-Fast Earthing Switch enables switchgear installations to achieve a highest possible level of protection for persons and equipment.

Jose Malagon – Siemens

Some customer applications require two main protections to protect the busbars in medium voltage switchgears. This article suggests some of the possible alternatives to fulfill this requirement, and analyze the advantages and disadvantages of each solution. There are some technical options that the article describes such the mix between the arc flash protection with busbar protections schemes, like high impedance, and low impedance busbar protection, or blocking schemes to implement busbar protection.

With new technologies coming in the market, and the use of IEC 61850, the solutions now can be more cost effective, and could be implemented in medium voltage switch gear with a relative low cost, if they are compared with solutions available in the market some years ago. Centralized busbar protection can easily be implemented in medium voltage switchgears and some of the models in the market can include arc flash protection which permits have two different principles to protect the busbar.

The modern busbar protections can clearance the fault in very fast way, even with similar times that the arcflash protection.