Abstracts 2024

Daniel Mulholland – Transpower New Zealand

Transpower is now in the final stages of preparing a toolkit to enable digital substations to be deployed on its power system. Early in the project, evaluation of available system configuration tools (SCTs) and explorations of the vendor IED configuration tools (ICTs) led to the conclusion that no available market tool would met our needs and provide a sustainable process for developing and managing IEC 61850 configurations.

As a result, there has been considerable work done with a community-led open-source initiative called OpenSCD. Transpower has been involved in developing, testing and exploring opportunities using this software. Although relatively new to the market this tool has seen considerable development. It is browser-based with a light-weight architecture designed to allow stakeholders to compose their own “distribution” of modular plugins to provide specific functionality. Transpower has been involved in developing plugins for its own use as well as discussing, refining and testing functionality developed by others.

Over three years of community involvement, plugin development and engaging with IED manufacturers and their ICT tools, Transpower has created its own open-source distribution of OpenSCD and expects this will be effective in developing and maintaining IED configurations using only an SCD (System Configuration Description) file. Extensive lab testing using both IEC 61850 Ed 2 and Ed 2.1 devices has given confidence that in our multivendor system we will be able to develop and maintain configurations with close fidelity to the engineering process provided in the IEC 61850 standard.

This paper will describe the OpenSCD tool, the challenges of multivendor integration and testing and specific areas for future development.

Ozan Dayanc – OMICRON Energy

This paper presents a comprehensive analysis of the security issues found in over 100 global energy facilities, including substations, power plants, and control centers. The analysis was enabled by the deployment of Intrusion Detection Systems (IDS), through which a detailed network security assessment was possible. The paper highlights the five most common and significant network security risks we found in energy facilities, which were particularly prevalent in the facilities we visited. Along with the most frequent ones, we have also worked out some noteworthy examples of particularly unsafe implementations in substations which not only serve entertainment, but also as case studies to learn from. Additionally, our investigation revealed numerous operational issues on the station and process bus, such as configuration errors, network failures, and protocol interoperability issues, all of which are commonly overlooked and could impact operations later. The most frequent operational issues will be examined in detail, and we will explain how to spot them. Furthermore, the paper offers insights into secure grid automation system implementations, derived from our analysis, serving as a blueprint for cyber-resilient substation network architectures. This work not only outlines the most frequent security and operational issues but also contributes to the discourse on advancing cybersecurity practices for substation and power plant automation system design

Raymond Robinson – Endeavour Energy

This paper evaluates the suitability of the Parallel Redundancy Protocol (PRP) for Ethernet networking in IEC 61850-based process bus systems at Endeavour Energy. Beginning with an overview of PRP, its benefits, and industry practices, it addresses previous considerations and recommendations against PRP usage. Drawing from industry reviews and project experiences, it reassesses the need for PRP in process bus networks up to 132kV and proposes recommendations favoring non-redundant networks.

Technical considerations such as data integrity, reliability, and availability are examined alongside failure modes and maintenance requirements. Additionally, the paper compares PRP and non-redundant network architectures, assessing complexities, redundancies, benefits, and limitations. Cost comparisons and risk assessments are presented, concluding that the cost of implementing PRP outweighs the risk mitigation benefits, making non-redundant networks a more cost-effective choice for Endeavour Energy’s process bus systems.

Patrick Rossiter – BlackBox RTS

As the power system transitions to grid-following forms of asynchronous generation, such as wind, solar and batteries which are often located in already weak parts of the network, the strength of the power system is reducing and episodes of instability are becoming more frequent.

Since 2018 there have been requirements under S5.2.5.10 of the National Electricity Rules (NER) for generators to install systems to detect unstable operation. However, the wording of this clause is quite ambiguous and the lack of commercially available and fit-for-purpose systems has made this requirement difficult for generators to comply with.

The Blackbox RTS Stability Monitor is a real time instability detection system which has been specifically designed to address the requirements of S5.2.5.10 of the NER. The system runs in on the SEL Axion RTAC platform and is capable of monitoring up to nine feeders on a single system. Our system is believed to be the first commercially available system commissioned on a transmission connected system in the NEM and is currently in operation on seven individual generators in the NEM.

The system works by measuring voltage and current waveforms at the point of connection and stores these measurements in sliding window buffers. Every second, a proprietary instability detection algorithm is run on the contents of each buffer to determines whether there is a periodic oscillation in the measurement.

If voltage oscillations are detected the algorithm looks for corresponding oscillations in active and reactive power. If oscillations in either P or Q are also detected, the phase angle between these oscillations is determined and automatic action can be taken if the phase angle is below a certain threshold. Oscillations in voltage, current, active and reactive power are all analysed. Binary alarms with configurable thresholds and delays can be set for all four quantities and set for three frequency bands. These results are then provided over SCADA for operators to take corrective action. Thanks to the ubiquity and reliability of SEL hardware, substation and SCADA integration is trivial.

This presentation and associated paper outline the challenges of developing such a system, the benefits of using existing off the shelf hardware, bench testing with Omicron CMC products and experiences with on-site commissioning.

Kulbhushan Kul – CommTel Network Solutions

TSO (Transmission System Operator) in state of New South Wales, Australia is evolving its operational telecommunication (OT) network from TDM based backbone currently using SDH/PDH technology to Packet Switched transport technology to address EOL (End of life) TDM products and increasing operational efficiency in network. This OT network transports mission critical Teleprotection services and current differential protection services. Transporting these critical services over a packet network is especially challenging, due to the safety-critical nature of protection, the strict requirements for low end to end latency and asymmetrical delay.

There is an urgent need to replace aging SDH/PDH network with a modern equivalent technology which support modern protection schemes like IEC61850, GOOSE and R-GOOSE. The technology and product must have long life span with support up to 15 years. As the power generation profile is changing with more renewable (Solar/Wind) energy connected to the main grid (Distributed Energy Systems) there is requirement for efficient wide area protection and control (WAPC) schemes to support connected generation, future energy systems and power flow across the boundaries to the neighbouring power networks.

An extensive and detailed Field Trial (FT) testing was conducted to verify and validate MPLS-TP (Multi-Protocol Label Switching – Transport Profile) technology for transporting Digital Current Differential (DCD) a.k.a Current Differential Teleprotection services together with existing live TDM (SDH & PDH), IP Radio and DWDM network over total link length of 1,450 Km. This includes interoperability with existing PDH multiplexers at 64K level, Teleprotection Relays (IED), & Test Equipment. The testing was conducted with different network configurations for teleprotection relays to measure the network performance for end to end delay and asymmetrical delay The summary results from the detailed PoC testing are presented in this paper, which authenticate the performance and feasibility of MPLS-TP technology to transport teleprotection services and successfully interoperate with existing TDM based equipment.

Marco Nunes – ABB

In the landscape of modern power systems, the integration of advanced technologies such as Artificial Intelligence (AI) and digital substations has become imperative for ensuring efficient, reliable, and resilient network management. This abstract explores the pivotal role played by Centralized and Virtualization Protection and Control (CPC and VPAC) architectures within digital substations as foundational elements in the development of predictive and autonomous AI-powered network management systems.

Digital substations, characterized by their utilization of standardized communication protocols and advanced sensing devices, facilitate the seamless integration of data from various network elements. Centralized and Virtualization Protection and Control systems within these substations serve as the nerve center, consolidating data streams, recording network anomalies at high resolution, while enabling centralized monitoring and control functionalities. By centralizing protection and control functions, VPAC architectures enhance operational flexibility, streamline maintenance procedures, and mitigate cybersecurity risks inherent in distributed systems.

Moreover, the virtualization aspect of VPAC architectures allows for the decoupling of hardware and software components, paving the way for greater scalability, interoperability, and adaptability in network management systems. Virtualization not only optimizes resource utilization within digital substations but also facilitates the deployment of AI algorithms for predictive analytics and autonomous decision-making processes.

The integration of AI technologies within VPAC-enabled digital substations heralds a paradigm shift towards predictive and autonomous network management. Through the analysis of vast amounts of real-time and historical data, AI-powered systems can anticipate network anomalies, predict potential failures, and autonomously execute corrective actions in a proactive manner. This predictive and autonomous capability not only enhances system reliability and resilience but also optimizes resource allocation, minimizes operational costs, and accelerates response times to dynamic network conditions.

In conclusion, the synergy between Centralized and Virtualization Protection and Control architectures in digital substations and AI-powered network management systems represents a transformative approach towards the realization of smarter, more efficient, and self-adaptive power grids. Embracing this convergence will undoubtedly unlock new horizons in the quest for sustainable and resilient energy infrastructures of the future.

– VPAC architectures in Digital Substations: VPAC (Virtualized Protection Automation and Control) architectures form the foundation for modern digital substations, facilitating centralized control and leveraging virtualization for scalability.

– Predictive and Autonomous AI-Powered Management: Integration of AI technologies into VPAC-enabled substations enables predictive analytics and autonomous decision-making, enhancing operational efficiency and resilience.

– High resolution Anomaly Detection at the Edge level, enabling proactive anomaly detection and fault prediction, minimizing downtime and improving reliability.

– Toward Smarter Power Grids: The convergence of VPAC and AI technologies paves the way for smarter, self-adaptive power grids, offering sustainable and resilient energy infrastructures for the future.

Martin van der Linde – NOJA Power Switchgear Pty Ltd

Emerging cybersecurity standards for Intelligent Electrical Devices (IEDs) on the distribution grid provide both challenges and opportunities for operators of the distribution network.

In this presentation, we discuss the implementation requirements of IEEE 1686:2023 Cybersecurity for IEDs, and the practical application to distributed protection devices such as Reclosers. Organisational challenges in adopting hardened security stances are discussed, along with evolution pathways for self-provisioning IEDs and centralised settings management in a secure environment. While cybersecurity itself represents an additional layer of organisational management complexity, it also provides assurance for new methods of remote device management and operational cost savings.

Alex Apostolov – PAC World Magazine

We live in an environment characterized by the transformation of the electric power grid due to the widespread penetration of distributed inverter-based energy resources. This imposes new requirements for the protection systems to reduce the fault clearing time. High speed protection can typically be achieved by communications-based schemes; however the loss of the communications channel may have a negative impact on the fault clearing time. One of the benefits of IEC 61850 based digital substations is the availability of streaming sampled values that can be used by different protection applications. This paper presents the implementation of a cross differential protection function in a digital substation. It is suitable for double circuit high voltage transmission lines. The first part of the paper introduces the basic principle of cross differential protection and describes its behavior for internal or external faults in case of double circuit transmission lines. The second part of the paper describes the implementation of cross differential protection in digital substations and how it can be done in a centralized substation protection system as well. Combining different communication or non-communication-based protection functions in an integrated double circuit transmission line protection device is presented in the next section of the paper. Implementation based on superimpose components or synchro phasers are described later in the paper. The last part of the paper discusses the testing of the cross differential protection function and the benefits of its application. The better coverage of instantaneous protection without the need of a communication channel is identified as a significant advantage that it offers. This can help improve the stability of the electric power grid as well as support the ride-through of distributed energy resources in case of short circuit faults on double circuit transmission lines.

Maja Knezev – DEL Engineering

Implementation of Reactive Power Control Scheme

ABSTRACT: Power systems supply and consume real and reactive power. Reactive power affects power system voltage which must be secure, and stable within a specific range to prevent plant damage and provide reliable power supply. Depending on system loading and generation patterns reactive power requirements are continuously changing. One of ways utilities deal with reactive power changing nature is by installing synchronous condensers. Reactive power from a synchronous condenser can be continuously and quickly adjusted providing stable voltage as result. Frequently static reactive plants (reactors/capacitors) are used in combination with Synchronous condensers to reduce condenser’s output close to zero. This ensures maximal availability of Synchronous condensers for new system events when fast reactive power adjustment would be needed. This paper presents a novel autonomous scheme that has a goal to maximize available synchronous condenser output by automatically switching on or off the static reactive plant (reactor/capacitor). In addition to describing system architecture, the paper reviews various algorithm options and different criteria that are used for prioritizing optimal plant that should be operated. It also discusses various methods used during different stages of testing and hunting detection alarm logic.

Akhmad Sudaryono – State Electricity Company – PT. PLN (Persero)

The Timor System is the largest electrical system within the scope of PT. PLN (Persero) UIW NTT, with the highest peak load of 112.92 MW in 2022 and 123.74 MW in 2023. The challenge in delivering electricity in the Timor System is the occurrence of transmission network disturbances resulting in widespread outages and even blackouts. Transmission disturbances also result in the failure to achieve the TLOF (Transmission Line Outage Frequency) target due to internal and external disturbances. To improve the reliability and continuity of transmission, system protection in the form of tele-protection coordination is needed to prevent the system from experiencing widespread disruption. The existing tele-protection system in the Timor System only uses communication media through PLC (Power Line Carrier). Historical case occurred on November 10, 2022, where the Tele-Protection system of Transmission Line at Bolok – Tenau experienced damage and failed to minimize temporary disruptions, resulting in the distance protection system not working selectively. Therefore, a concept of strengthening protection coordination with FO (Fiber Optic) communication media using the GOOSE Protocol is proposed to minimize widespread disruption due to tele-protection failure via PLC Keywords — Transmission Disturbances, Teleprotection , Media communication, PLC, Goose

Jörg Blumschein – Siemens AG

Travelling Wave Fault Location becomes more and more popular. Users worldwide praise the great accuracy of travelling wave fault location. Due to the principle of travelling wave fault location the accuracy of the fault location is based on an accurate time measurement of the travelling wave wavefronts. For travelling wave fault location, the time accuracy should be in the range of nanoseconds. A time inaccuracy of one microsecond could cause an error of up to 300 m for the fault location. For double ended travelling wave fault location this time accuracy needs to be maintained for both devices which can be placed several hundreds of kilometers away from each other. Before putting such travelling wave fault location systems into operation different tests should be performed to guarantee the performance of the system. Users should start with a factory acceptance test to prove the accuracy of the system in a lab environment. In the factory acceptance test many test cases should be applied to test the accuracy of the system for different fault types and fault positions on the line. The factory acceptance test should be performed with the exact propagation velocity of the line. The inaccuracy of the fault location in factory acceptance test should be independent of the fault position otherwise there could be a problem with the propagation velocity. The accuracy of fault location during the factory acceptance test should be constant over time to demonstrate the reliability of time synchronization. If the factory acceptance test is passed it is confirmed that the fault location system itself can fulfil the accuracy requirements without the influence of the primary system like instrument transformer and the wiring between instrument transformers and travelling wave devices. During the site acceptance test a focus should be given to the accuracy of the time synchronization of the travelling wave device on site. Beside this, it needs to be checked that all channels are wired correctly, and the trigger levels are appropriate. For enhanced accuracy the compensation for the propagation time between instrument transformer and travelling wave device needs to be tested. At site acceptance test switching operations of primary equipment can be used to check the proper behavior of the travelling wave devices. This can be helpful to adjust trigger levels and check the propagation velocity of the line and the time synchronization of the travelling wave devices at both ends of a line. Finally, the communication of the travelling wave devices to the central computer needs to be tested at the site acceptance test. The paper starts with a short introduction of travelling wave fault location, followed by a discussion of possible source of inaccuracy for single ended and double ended travelling wave fault location. Factory acceptance test and site acceptance test are explained in detail using practical examples. The paper closes explaining how to verify the settings, especially the propagation velocity of the line. This can be done after putting the system into operation, using data from the first external faults.

Johnson Zhou – Mercury NZ Ltd

In one of Mercury-owned hydropower stations comprising three generators linked to an 11kV common busbar, connected to the grid via a 220kV / 11kV generator step-up-transformer (GSU), earth faults have persisted within its 11kV system for the past seven years. This 11kV system employs high-impedance grounding through a three-phase Star/Broken delta neutral earthing transformer (NET) and a neutral earthing resistor (NER). Duplicated transformer protection relays have enabled their 11kV busbar residual voltage element which is derived from that NET. Since 2018, at least 13 earth fault events have been picked up by the relay, among which 5 resulted in the whole station trip. However, investigations following each trip yielded no tangible findings. Annual oil sampling of the NET revealed no signs of failure until the latest trip, where gassing in the transformer was found and suggested the NET was the root cause of those earth faults. A decision was made to take the NET out of service, and an order was placed for a new one. However, the lead time for the replacement transformer exceeded six months, posing a significant challenge to the station’s operational continuity. To address this issue during the interim period, an alternative earth fault protection strategy was implemented. Given the station’s requirement for constant start and stop cycles of the generators, this interim solution was crucial to maintaining the reliability and safety of the system. This temporary measure allowed the station to mitigate the risk and provided earth fault detection while awaiting the arrival of the new NET. This paper gives an overview of the power station configuration and protection scheme setup, followed by a detailed description of those earth faults, including protection relay event reports, post-trip test results, and root cause analysis (RCA) outcomes. Then, the adoption of a temporary alternative earth fault protection is presented after the last station trip when the decision was made to replace the NET. Finally, several lessons learnt from this 7-year fault-finding process are shared.

Luke Napier – Schweitzer Engineering Laboratories

The traditional protection system consisted of a conventional current transformer (CT) and a protective relay. The CT had specific physical characteristics, which meant that each application required CTs to be designed specifically. The introduction of the nonconventional instrument transformer means that the CTs can be universal in design. The nonconventional instrument transformer discussed throughout this paper is the Rogowski coil.

The protective relay is a digital device, which means that the signal generated by the instrument transformer needs to be converted to a digital signal. The analog-to-digital (A/D) converter in the relay has a discrete range based on the number of bits. To ensure the resolution of this signal can be used, the A/D converter defines the upper limit at which clipping will occur. This is typically 30 times the nominal current.

The dynamic range of the Rogowski coil is much larger than the traditional CT. However, the protective relay is still limited by the A/D process. Interestingly, the protective relay still requires the user to define a CT ratio for a Rogowski coil configuration. This paper explores the opportunity this allows; by changing the CT ratio, the performance of the relay can also change.

The power system is evolving with a growing need for renewable energy. This has also included the growing trend for microgrids. Within these microgrids, inverter-based resources (IBRs) are the predominant source for fault current. This means that the fault level can be significantly reduced. One particular use case is an islanded network converting from diesel generation to a battery energy storage system (BESS) and solar system. The network needs to be able to operate on either IBR-only, a combination, or diesel-only source of supply.

This paper uses this case to demonstrate the new capability of the protection system to dynamically change based on the varying fault level in the protected network.

Lara Kruk – Jacobs

Worldwide electricity grids have experienced significant development and transformation. The key drivers include grid modernisation, increased electrification and the transition to renewables. These developments and changes require the new and existing Protection and Control (PAC) workforce to understand: • Traditional power systems and legacy PAC equipment, along with new power systems and new PAC equipment. • How digital solutions and data can be used to monitor, protect and control power systems. • The use of communication technologies in monitoring, protecting and controlling power systems and how to manage the cyber security threats introduced by their use. To provide the new and existing PAC workforce with the learning experiences and skills required to ensure that the next generation of the electricity grids are safe, secure, reliable, environmentally friendly, a deliberate and focused approach is required throughout the learning experience lifecycle. This paper details what new topics need to be incorporated within electrical engineering curriculum for undergraduate and graduate courses, and how to achieve industry-aligned teaching through strengthened university and industry partnerships. It is suggested that the following new topics be incorporated within university degrees: • Fault characteristics of inverter based renewables (IBR) and short circuit modelling of IBR • Protection scheme behaviour due to high IBR penetration • Protection scheme behaviour due to high inverter based distributed energy resources (DER) penetration • Digital and data science to support the use of real time data as part of Wide Area Monitoring, Protection and Control schemes and in the management of Distributed Energy Resources (DER) • Communications and networking fundamentals to support successful implementation of digital substations • Cyber-physical security detection, analysis and mitigation as part of protection and automation design • Environmental issues, sustainability and resilience and how to make design decisions and product selections that are sustainable and resilient. Recommendations are provided for how to develop graduate skills and competencies for next generation protection and control systems, this includes competency based graduate training programmes and coordinated and complimentary discipline area graduate rotation schemes. Appropriate means to train the existing workforce on the latest technologies while also ensuring appropriate knowledge transfer processes are implemented are discussed. And the use of large scale test beds is explored as both a training and research tool by both universities and industry.

I Gede Raka Joni & IKA Sudarmaja – PT PLN (Persero) Indonesia

PT PLN (Persero) Bali is one of the Operational units that manages the electric power transmission system in the island of Bali where PT PLN (Persero) UPT Bali manages transmission assets along 918.02 kms, 44 power transformer units with a total capacity of 2490 MVA, 13 conventional substations and 3 units of GIS. From the 16 substation units, there is the Gilimanuk Substation which is the backbone for the distribution of electric power from the island of Java.

The Gilimanuk substation as a load center is supplied through the 150 kV Banyuwangi

– Gilimanuk 1 and 2 transmission line using the hybrid configuration OHL TACSR 1×240 mm2 (973 A), submarine cable PIRELLI 1x300mm (500 A), and OHL ACSR Hawk 1×281.1mm (580 A). The total length of the Gilimanuk – Banyuwangi conductor is 14.18 km with a nominal voltage of 150 kV through the Bali Strait and operates to distribute electricity from the Paiton subsystem to the Bali subsystem. In normal operating conditions the conductor of 150 kV Banyuwangi – Gilimanuk 1 and 2 carries a load of 348 A while Banyuwangi – Gilimanuk 3 and 4 carries a load of 408 A. When there is an outage due to interference or maintenance on one of the SKLT, the burden will be borne by other senders. This causes OLS to work and extinguish the customer’s burden. PLN has a policy in network settings with a hybrid configuration set to the final trip when there is a temporary or permanent interruption.

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With the advancement of relay protection technology, especially the distance relay, namely the Zone Programmable facility, the implementation of autoreclose in OHL and submarine cable (Gilimanuk – Banyuwangi) can be implemented. This is so that during a temporary disruption in OHL, the tramsmission line will be recloses and saves the customer’s energy from outages.

n the autoreclose scheme on hybrid transmission lines (OHL and submarine cable) by utilizing ZP (Zone Programmable) parameters on the distance relay, there are three parts that play an important role, namely the sensor circuit (CT/VT-Distance Relay), the control circuit (Breaker-Distance Relay), and teleprotection. Rele distance can estimate the location of the interference based on its section (OHL or submarine cable) based on the fault impedance by utilizing the Zone Programmable (ZP) setting parameter. When fault occurs, rele distance will calculate the fault impedance based on the current and rated fault voltage. The fault impedance will then be compared with the ZP parameter set according to the OHL impedance so that when the rele distance detects ZP, the relay will initiate the breaker autoreclose and send a signal to the other substation with “Goose Communication”. Likewise, when relay gets a ZP signal from the other substations, relay will initiate the breaker autoreclose cycle. On the other hand, if the relay does not detect ZP or does not receive the ZP signal (fault occurs in the submarine cable) then the transmission lines will be the final trip.

With the implementation of the autoreclose algorithm on OHL and submarine cable (Gilimanuk – Banyuwangi), it is expected that the hybrid conductor (OHL and submarine cable) will autoreclose when there is a temporary fault at OHL, where the initial design for the hybrid transmission line is the final trip.

Leonardo Torelli – CSE Uniserve

Detecting high impedance faults and the fault directionality is one of the major challenges for protection engineers in distribution. The fault current could be very low in magnitude with arcing, harmonics and intermittent current pattern.

This paper focus on a modern technique to determine the direction of the fault on HV feeders in a compensated system. In this system, traditional directional techniques might not operate or operate incorrectly. To overcome this challenge, a patented algorithm is used, which does not require special hardware or high acquisition frequency, to precisely determine the fault direction. Real field events are tested to prove the element.

These protection techniques provide a sound engineering solution to mitigate the risk of bushfire, injuries and improve the overall safety in a compensated system.

Trevor Scott – Siemens Ltd.

Background With controlled switching the circuit breaker opening and/or closing is applied with consideration of the ”point-on-wave (PoW)” of the system voltage at the instant of galvanic circuit interruption/connection. This approach can mitigate switching transients and increase plant maintenance cycles by e.g. reduced transient voltages and fewer reignitions during CB opening inductive loads. The PoW energization of transformers is one example for controlled switching that has been widely used in the past and is achieving great interest for new applications due to the availability of the feature in standard bay IEDs such as protection relays or bay RTUs. This interest arises from the ability to effectively eliminate in-rush currents when energizing power transformers. Residual Flux (remanence) The controlled closing of a transformer will switch the initial pole(s) at such an instant that the flux in the energized transformer limb (residual flux) will match the “steady state” flux corresponding to the point on wave of the voltage that is energizing the limb. In this manner there is no offset of the flux, at the instant of connection, so that the sinusoidal flux induced by the energizing voltage will have no offset and consequently will not saturate. Without saturation, the in-rush current is eliminated. It is therefore a requirement, that the residual flux is measured so that a dynamic closing angle can be determined for the PoW energization of the transformer. The measurement of the residual flux is based on an integral of the voltage during switching off the transformer. Implementation A voltage measurement on the transformer winding is used. The voltage may be on the same side as the CB used for the controlled switching or on any other side of the transformer. For example, a grounded Y-connected transformer may be closed with the residual flux obtained with the corresponding Ph-Ph voltage on the delta-side of the transformer. Scope In the proposed paper the method used to measure residual flux based on the voltage transient during de-energization will be presented. The method used to establish the dynamic closing angles based on the residual flux is covered. Diagrams of simulated transformer switching are provided showing the requirement for a delayed 2nd close after decrease of transients. The simulated cases also show the effective elimination of in-rush currents. Terms such as “dynamic flux”, “prospective flux” and “dynamic closing angles” are described.

Ali Saravi – Endeavour Energy

The successful implementation of transformer differential protection requires balancing sensitivity and security. However, assessing sensitivity is challenging because standard software does not include calculations for internal faults. Therefore, differential bias curves are determined mainly based on factors such as CT error, tap changer ratio, and margin of safety to ensure security. However, this conventional approach may result in insufficient sensitivity, often relying solely on mechanical protection to detect low-level faults. Additionally, modern transformer protection relays offer more sensitive elements, such as tap changer position integration or the utilization of negative sequence differential elements. Yet, adopting these sensitive protections may compromise security, so it is essential to establish the minimum fault levels for various fault types to justify their necessity. This paper aims to model transformers for internal winding faults, which enables the assessment of sensitivity for bias differential curves. By modelling windings in 2D finite element software (FEMM), transformer parameters were calculated, and fault analysis and differential scheme implementation were conducted in PSCAD. As a case study, a 132/22kV Dyn1 transformer was modelled. The results showed that phase-to-phase and phase-to-ground faults on the HV winding (delta configuration) can approach the restraint area under full load, requiring correct bias curve settings. For the LV winding (grounded star configuration), differential protection against LV phase-to-ground faults is not sensitive, but restricted earth fault protection can be highly effective. For turn-to-turn faults on either HV or LV windings, differential protection alone is not effective, but implementing a negative sequence differential scheme enhances sensitivity, with mechanical protections remaining the primary safeguard.

Tarik Hussein – Endeavour Energy

This paper proposes the development of a fault record sharing platform run by the technical community of protection engineers. Fault records are data collected by protection relays when a fault occurs in an electrical system, and they contain valuable information for the power system protection industry. However, fault records are currently collected by individual utilities and industrial network operators, and are often under-analysed and lost in their archives. The proposed platform would enable the sharing of fault record data among different organizations, such as utilities, manufacturers, and universities, on a voluntary and secure basis. The platform would provide several benefits, such as improving the design and performance of protection relays, enhancing the knowledge base and expertise of the industry, and ultimately improving the reliability and resilience of the power grid. One of the most exciting potential uses of this shared fault record data is the development of new fault detection algorithms using AI neural networks and deep learning methods, which require large amounts of diverse and high-quality data to train their models. The paper calls on the power system protection community to come together to develop and support this important initiative.

Satendra Bhola, Peter Bovo & Leonardo Torelli – Tasmanian Networks Pty Ltd & CSE Uniserve

The transformer restricted earth fault protection (REF) is implemented to provide sensitive protection for faults with low current magnitude, typically near the star point of impedance grounded power transformers, where the biased differential protection might not detect the fault.

The restricted earth fault is a unit scheme. Security during an external fault is the focus of the algorithm, in particular during the switching off transient condition upon CB clearing the fault. In this paper, two recent REF operations from the field suggest that an effective solution to enhance the security is by implementing a minor small time delay to the REF protection algorithm element. One genuine transformer fault is also reviewed with the REF improvements.

The need for the REF, its importance, and the rationale of the scheme within the transformer protection is here revisited to support the proposed solutions with real use cases.