Abstracts 2026

Carolina Korez – Siemens Industry, Inc.

As the National Electricity Market transitions toward a low-emissions power system, from conventional synchronous generation to systems with high penetrations of inverter-based generation, protection behaviour becomes increasingly influenced by fast-changing system dynamics, reduced fault levels, and non-linear control responses. 
In this context, controlled modelling environments are needed to provide a trusted basis for evaluating new technologies, protection concepts, and wide-area control systems. Traditional asset-level or local studies are no longer sufficient and introduce significant challenges for traditional protection coordination approaches, as system strength, fault current characteristics, and transient voltage and frequency behaviour increasingly reflect broader network conditions and inverter-based resource interactions, where voltage and frequency responses during disturbances can deviate markedly from conventional expectations, necessitating protection schemes that can adapt to highly dynamic operating conditions. Across the Engineering Roadmap, the Transition Plan for System Security, and recent system security planning publications, AEMO has highlighted the growing risk of unexpected operation and interaction of protection and control schemes, including Remedial Action Schemes, as these schemes increase in number and complexity. This highlights the need for improved model representation to better assess these risks and support future system security capabilities.
In response, a new protection paradigm is emerging based on centralized architectures where protection functions are consolidated within virtualized computing platforms rather than distributed across discrete field devices. These architectures leverage high-speed communication networks to acquire time-synchronized measurements from across the grid, enabling coordinated, system-wide protection decisions while supporting the implementation of software-defined protection strategies.
By tightly coupling system dynamic responses with protection decision-making processes, the tool captures interactions between system stability and protective relaying. This modelling approach enables detailed assessment of protection operation across a broad range of contingencies, including faults, loss of generation, and system restoration scenarios.
A key strength of the platform lies in its ability to explicitly represent communication and implementation effects, including latency, critical to the dependability and security of wide-area protection schemes.
The platform provides insight into how centralized protection schemes respond to rapidly evolving system states driven by inverter control actions, such as current limiting and fault ride-through behaviour. This allows engineers to rigorously evaluate whether protection systems operate correctly under both normal and abnormal conditions.
Ultimately, the module assesses whether protection actions support overall system stability objectives, including maintaining synchronism, preserving voltage stability, and successful post-disturbance recovery. This is critical in low-inertia systems, where inappropriate protection operation can exacerbate instability or trigger cascading outages.

Michal Wiecha – OMICRON electronics GmbH

The increasing penetration of inverter-based resources in modern power systems is pushing protection devices toward their operational limits. Protection devices installed in the vicinity of inverters face significant challenges in fault detection and clearance, however, devices installed further within the power grid can also be affected by the influence of inverter-based resources. Protection elements based on voltage and current measurements need to cope with the voltages/currents injected from inverter-based infeeds during a power-system fault. Both directional elements and protection functions, which estimate the fault location based on impedance calculations, react differently than in conventional networks with much more short-circuit power. Within a simulation-based protection testing application, a generic grid-following inverter model is used, in which the detailed behavior of the inverter during fault ride-through can be parameterized. This allows the impact of inverter-based resources on power system protection to be systematically investigated. Depending on the fault type – single-phase, two-phase, or three-phase – and the fault characteristics, with high-impedance faults being particularly challenging, various scenarios can be simulated and tested using a protection device connected to the test system. Detailed results are presented and possible solutions and concepts for overcoming these challenges are discussed. Based on these findings, protection engineers can adapt their protection strategies.

Maja Knezev – DEL Engineering

With the increased contribution of Inverter-Based Resources (IBRs), power systems are experiencing vast transformation. Strength of power system changes during the day depending on IBR type, however protection must be reliable and dependable independent of these conditions. This paper presents protection challenges related to topology of newly connected IBRs. It proposes potential solutions to mitigate issues that can be caused with existing topology. It proposes solution that could avoid issues by better IBR reticulation planning.

Ying Yan, Gurindar Saluja – Transgrid

The decommissioning of the coal-fired generator units at Liddell Power Station is a key element of New South Wales’ energy transition strategy towards Australia’s 2050 net-zero commitment. In response, AGL has constructed a new 500 MW Battery Energy Storage System (BESS) to replace the retired generation capacity, supporting grid stability in a renewable-dominant network, leveraging the existing 500 kV and 330 kV transmission infrastructure, and enabling rapid-response grid services. To connect the Liddell BESS to Transgrid’s network, a new 330 kV BESS substation was engineered and delivered, together with an extension to the existing 330 kV busbar at the Liddell 330 kV Switching Station, which previously interfaced with the now-decommissioned power station. This paper presents the protection and control design advancements developed for this project, addressing the challenges of integrating a large-scale BESS into the 330 kV transmission network. Key topics include a non-conventional protection scheme that redefines zone boundaries and reconfigures conventional protection algorithms; novel distance protection applied to a short transmission line for secure and selective fault clearance under rare but high-consequence contingency conditions; and transformer overexcitation protection to mitigate over-fluxing risks that may potentially arise from the atypical dynamic behaviour of inverter-based resources (IBRs) connected to the 330 kV system via the transformer. Our study details Current Transformer (CT) selection improvements to guarantee unit protection performance, and an enhanced transformer automatic voltage regulation (AVR) scheme incorporating Load Drop Compensation in accordance with the customer’s Voltage Control Strategy. Improvements to the Quality of Supply interface for seamless integration with the customer’s power quality monitoring system are also discussed, alongside the adoption of multifunctional, combined protection and automation architectures that employ coordinated backup protections to provide adequate redundancy for the 33 kV BESS protection system. Our work emphasises the practical lessons drawn from real-world implementation, including the impact of IBRs on protection and voltage control systems, and constructive proposals for Low Voltage (LV) protection system design. Additionally, we detail insights into the design decisions, engineering challenges, and solutions encountered in delivering one of Australia’s largest grid-connected BESS projects

Dowon Kim, Hai Le – DIgSILENT Pacific

The Rate of Change of Frequency (RoCoF) function is a vital protection mechanism used to prevent unintentional islanding in grid-connected inverter-based resources, thereby enhancing system safety, regulatory compliance, and coordination with existing protection schemes.
This study introduces simulations conducted using both root-mean-square (RMS) and electromagnetic transient (EMT) models of a large-scale (tens-of-MW) battery energy storage system (BESS) to optimise appropriate RoCoF settings. These configurations are designed to meet regulatory compliance requirements and improve the effectiveness of islanding detection under varying active power loading conditions. Through comprehensive simulations and practical measurements, two primary limitations of RoCoF protection in a grid-connected BESS were identified.
First, a non-detection zone was observed during sudden increases in active power demand. RoCoF protection successfully initiated tripping of the incomer circuit breaker when a substantial amount of active power was drawn from the main grid while the BESS was idle (0 MW and 0 MVAr at nominal voltage). However, under certain loading conditions, the RoCoF remained insufficient to trigger the relay within the expected operating region.
Second, the actual RoCoF trip time of the protection relay was found to vary across different active power loading conditions. Secondary injection testing of the RoCoF protection relay confirmed that the configured delay time in the RoCoF logic did not consistently correspond to the actual operating time under different rates of frequency change. It was observed that the minimum operating time of the RoCoF function was achieved only when the measured df/dt significantly exceeded the pickup threshold, specifically, when it was at least twice the configured df/dt setting. Consequently, the existing RoCoF operating characteristics do not precisely represent the actual relay behaviour, potentially leading to uncertainty in predicting the true operating time under varying frequency disturbances.
This study explains frequency variation characteristics under diverse load-fluctuation scenarios and proposes considerations for configuring RoCoF protection settings for anti-islanding applications. Furthermore, by analysing and discussing practical operational limitations, this work provides a valuable case study for assessing the suitability of conventional RoCoF protection in real-world applications.

Tarik Hussein – Endeavour Energy

Distribution-connected microgrids are attracting increasing interest as utilities look for practical ways to improve resilience on weak and remote feeders while accommodating much higher levels of inverter-based distributed energy resources. This paper presents lessons from the commissioning and early operation of the Bawley Point microgrid, Endeavour Energy’s first distribution-connected microgrid of this type, and shows that once a utility-scale battery is introduced onto a long rural feeder already shaped by widespread rooftop solar and customer batteries, conventional protection assumptions can begin to break down in ways that are not always obvious at the design stage.

The paper focuses on two related themes. The first is the way reverse power flow changes the security of feeder protection settings that were originally selected for a system with a largely radial operating history. The second is the way an unintended island can persist for longer than expected when the feeder contains enough inverter-based resource to influence voltage and frequency behaviour after separation from the upstream network. In both cases, the commissioning program exposed behaviours already emerging on the existing network.

The paper also explains several other protection challenges that emerge from a feeder with a high level of distributed energy resources and proposes recommendations for future distribution-connected Battery Energy Storage System (BESS) deployments to improve protection performance.

The central conclusion is that reverse power flow, aggregate inverter response and anti-islanding performance are no longer edge cases for protection engineers. They must be treated as normal design conditions and verified in commissioning with the same scrutiny historically reserved for fault studies and coordination grading.

David Mueller, Derek Jayasuriya – AusNet Services

Maturity and useability of IEC61850 protection and control devices has improved vastly over the last several years, to a point where implementation of digital substations is easier than ever before. Coupled with the increasing rate of connection of renewable resources and data centres to the electricity grid requiring shorter timeframes, this prompted one Victorian transmission utility to begin on a journey to transition to IEC61850 digital substations where standardised designs and repeatable engineering could be leveraged.

This paper presents the path of testing and development undertaken to produce ready-to-use secondary protection and control templates for greenfield transmission sites, as well as how these were implemented on the first few substations. Also outlined are the major technical challenges and lessons learnt, as well as difficulties encountered that could be solved in future through additional device features or standard improvements.

Kevin Cabante, Francis Dave Cruz, Paul Callaman, Christian Pam-ot – Davao Light & Power Co, Philippines

There is a significant trend in IEC 61850 deployments in substation automation, and it has become a prominent standard of power industries. In the Philippines, Davao Light and Power Company Inc. (DLPC), has led its application, with 6 substations that fully utilized IEC 61850 and various hybrid applications. Although IEC 61850 offers significant advantages such as offering a common language for various IED devices and offers its users scalability and flexibility on its application, there were still challenges with its application.

This paper presents the practical experience of a distribution utility in implementing IEC 61850 substation and will cover the protection, control, and communication challenges faced by engineers from configuration stage to testing and commissioning stage. In the configuration stage, Generic Object-Oriented Substation Event (GOOSE) communication delays and some (Intelligent Electronic Devices) IEDs requiring additional steps such as (Configuration IED Description) CID raw data configuration are observed when integrating multivendor IEDs. During the testing stage, there is a difficulty in injecting (Sampled Measured Values) SMV due to time synchronization issues. Moreover, network related issues, multivendor (Substation Configuration Description) SCD reconfiguration, and troubleshooting difficulties faced by engineers in the testing stage. Compared to conventional technologies, IEC 61850 requires additional SCADA data points that must be considered. Additionally, there were challenges in CID integration between the (Remote Terminal Unit) RTU and the IEDs such as (Manufacturing Message Specification) MMS configuration and SCD frequent revisions.

These challenges are observed across the Davao Light substations. This study will highlight that while IEC 61850 provides advanced protection and automation, there is a need for strong configuration management. Detailed data collected by engineers from the first substation up to the latest substation with IEC 61850 will also be discussed. This paper further provides practical recommendations in addressing the issues and challenges identified in IEC 61850 implementation.

Amro Mohamed – OMICRON electronics

IEC 61850-based substations rely on Ethernet communication for protection, control, and engineering access, introducing cybersecurity risks that extend beyond traditional monitoring. While protocol-aware inspection provides visibility into MMS, GOOSE, and Sampled Values traffic, it does not prevent unauthorized operations or reconnaissance activity from reaching critical devices. At the same time, any response mechanism in a substation must preserve deterministic communication and align with established operational practices.

This paper presents a practical OT cybersecurity approach that connects IEC 61850 protocol monitoring with controlled, policy-driven network enforcement. The focus is on detection capabilities that are realistically achievable in operational environments, combined with deterministic containment actions that do not interfere with protection performance.

A primary use case is MMS session behaviour and high-frequency enumeration activity. Detection includes session establishment, data model discovery, repeated read operations, and file access patterns. When such activity occurs outside authorised maintenance windows, it may indicate reconnaissance or preparation for lateral movement. A structured evaluation workflow is applied, where maintenance state is used as the primary authorization boundary before severity and context are considered.

For GOOSE, the paper focuses on detectable anomalies such as unexpected messages and inconsistencies in configuration parameters, including VLAN settings, MAC addressing, dataset references, application identifiers, and configuration revision values. Encoding issues and malformed datasets are also considered. In addition, the absence of expected GOOSE communication is treated as a critical operational condition rather than purely a cybersecurity anomaly.

Sampled Values monitoring is addressed conservatively, focusing on the loss of expected streams rather than timing or sequence analysis, reflecting practical detection limitations in substation environments.

Unauthorized control actions using MMS, including switching and tap changer operations, are evaluated against maintenance state and asset context to distinguish legitimate engineering activity from policy violations.

Detected events are correlated with asset identity and communication paths. Enforcement is performed through deterministic network actions such as disabling predefined communication paths or isolating source devices. This approach avoids inline inspection and ensures that protection-class traffic remains unaffected.

The resulting workflow aligns with IEC 62443 principles while remaining consistent with SCADA and protection engineering practices, demonstrating a practical method for controlled and predictable cybersecurity enforcement in digital substations.

Johan Pensar, Harlem Tsai – ABB Finland Oy

As digitalisation accelerates across the energy and distribution grid landscape, operators are increasingly required to address cybersecurity risks in systems originally engineered for stability and long lifecycles rather than hostile, interconnected environments. While discussions often focus on high level geopolitical tensions or abstract threat trends, the most pressing need for practitioners is clear, technically grounded guidance on how to secure real operational environments without compromising availability, safety, or regulatory obligations. This paper therefore concentrates on actionable cybersecurity practices that can be directly applied within protection, SCADA, substation automation, and broader OT settings.

The session draws from recent real world cyber incidents in the energy sector to illustrate how adversaries exploit practical weaknesses—such as infrequent patching on protection relays, insufficient OT network segmentation, false assumptions about system isolation, inconsistent backup strategies, and limited personnel training. These examples highlight not only the technical attack paths but also the operational constraints that often prevent utilities from implementing traditional IT style security controls. The discussion will extract measurable lessons learned, including how intrusion dwell time, lateral movement, and inadequate device inventories contributed to the depth and duration of operational impact.

Building on these lessons, the paper presents a set of pragmatic engineering focused measures for improving cybersecurity posture in live grid environments. These include the design of patch management processes that accommodate maintenance windows; validation of backup and recovery routines for relays, RTUs, HMIs, and control servers; implementation of zoning and segmentation aligned with IEC 62443 principles; and targeted training programs that raise operator readiness for incident response. Each measure is accompanied by implementation considerations, architectural guidance, and examples of resilience improvements observed in utilities that have adopted these practices.

Finally, the paper discusses how equipment suppliers and system integrators can support these efforts through secure by design engineering practices, structured lifecycle support, verifiable software provenance, and reference architectures that reduce integration complexity. Rather than promoting specific products, the emphasis is on collaborative approaches that demonstrably improve the security and reliability of protection and automation systems.

The objective of the presentation is to provide practitioners with concrete, technically sound, field tested guidance that can be immediately applied to strengthen cybersecurity in operational environments, ultimately enhancing the resilience of modern energy systems.

Ciprian Hosu – Western Power

The rapid increase of Inverter-Based Resources (IBRs) in the South-West Interconnected System (SWIS) raises challenges in the operation of line protection relays due to their distinct fault characteristics when compared to traditional synchronous generators. The distinct fault signature of an IBR is due to the control scheme and physical limitation of the components used, specifically the power electronics thermal limits.

Proactively working towards a solution Western Power (WP) has investigated the behaviour of phasor based protection elements commonly used in today’s power system in a closed loop testing system using Omicron’s RelaySimTest software. During these tests issues with fault detection have on faults transmission lines where IRBs are connected were encountered. The issues discovered were related to: faulted phase loop identification, directional element, and mal-operation of distance. Whilst testing line differential protection encouraging results were obtained, main protection element, with it being the most reliable protection. However, one needs to consider its reliance on communication channel availability being the main drawback.

As the backup protection elements showed vulnerabilities, further investigation were carried into the use of innovative technologies which could cover the abovementioned blind spots. These investigations are looking into the use of time domain and enhanced phasor distance protection. 

The time domain and enhanced phasor distance protection were assessed in the same closed loop environment as the traditional phasor based protections. Furthermore, to fully validate the possible improvements brought by these technologies, the same power systems were used for the assessment.

The results obtained whilst testing all mentioned technologies are planned to be used to further enhance the current line protection philosophy and improve grid connection requirements for IBRs.
The authors of the paper intent is to present the finding of the studies carried and solution in mitigating the issues found.

Alex Pointon – Noble Power Solutions

The Amrun bauxite mine is a critical asset in Rio Tinto’s mining operation, which is powered by a microgrid consisting of 22 x 1.25MW diesel generators near the town of Weipa in Northern Queensland. To reduce fuel emissions and costs, a 15MW solar farm and 9MW battery energy storage system (BESS) has been constructed adjacent to the existing power station to provide additional power during daylight hours. 

The integration of renewable generation into the existing diesel microgrid presents a unique protection and operational challenge, affecting system inertia, strength and fault levels. This presentation describes the process and execution behind the upgrade to the 22kV protection system, which was a prerequisite to begin the commissioning of the solar and BESS. The commissioning team developed a comprehensive test procedure, outlining detailed steps including risk management, isolation registers, and emergency rollback plans.

Due to the continuous power requirements of the mine, the protection update had to be completed whilst maintaining 100% generation availability. The switchroom consists of two 22kV busses connected via a bus tie, allowing operation on a single bus while works were undertaken on the dead bus. This removed switchboard redundancy during the testing, placing critical importance on the accuracy of secondary isolations and risk management processes.

Every protection relay required new settings and subsequent testing, including secondary injections and functional checks. The use of IEC61850 GOOSE messaging for interlocking and tripping provided an isolation challenge, highlighting the benefits and drawbacks of this evolving technology. Full bus zone schemes were tested, showcasing the ability of the OMICRON CMC to thoroughly test all protection elements, including the bus tie protection and IEC61850 messaging.

With substations becoming increasingly digitised, the skills required for protection/ commissioning engineers are rapidly evolving – from checking voltage with a multimeter to performing network packet captures. This protection upgrade was a case study in how renewables and digital substations can be integrated into to legacy power systems without compromising operational continuity.

Ian Young, Schneider Electric

Line differential has many benefits compared to overcurrent or distance. It reduces operating times and works well with series compensation and inverter based resources. The main drawbacks of existing line differential are communications requirements and proprietary protocols. As communications improve the use of proprietary protocols is the main restriction forcing users to use outdated relays or updating multiple substations to cut into existing lines. This adds cost and makes an orphan of either the new or existing feeder protection panel design.
Line differential protection needs synchronised sampling for differential protection and usually incorporates binary signaling for intertripping and status. This presentation looks at using various standard protocols to provide this functionality. To ensure the solution is fully supplier independent the resultant function is single ended and can be replicated at both ends, when required, using the same or different vendors.
Implementation of the function is then shown on the P7 platform which can be physical or virtual. The configuration process is discussed particularly in IEC 61850 systems.

Philipp Stachel, Torsten Schumacher – Siemens AG

Traditional line differential protection schemes require a protection device per line end, which is connected via a protection interface (in a ring, star or chain topology) to the other line end(s). The protection communication uses a vendor specific protocol, optimised for low bandwidth and fast operation speed. Therefore, the line differential protection devices at all line ends must be of the same manufacturer. 

Further, the relay vendor may also require that the device hardware and firmware versions must be the same for all ends. Such constraints are a difficult for the end user, restricting flexibility and necessitating long-term planning and co-ordination for protection relay upgrades with line outages.

In this paper we present a novel centralised line differential protection concept using IEC 61850-9-2 sampled values (SV) as part of a process bus topology connecting the remote end(s) substations. 

The use of merging units to digitise current waveforms at prescribed sampling rates and transfer to a centralised protection device using standardised communication protocols based on IEC 61850 GOOSE and SV not only eliminates the aforementioned constraints, but decouples both the hardware and lifecycle planning interdependencies of each end. 

Any standard-compliant merging unit can serve as the remote device(s) in the differential protection scheme. This allows interoperability and easy replacement between different manufacturers. The required device time synchronisation can be achieved using IEEE 1588 / PTP, with security of time provided by the differential protection acting as relay grand master, or as part of a Best Master Clock Algorithm network when a global time reference is unavailable.

Low-latency inter-substation communication is required for the process bus devices (merging units) of the remote end(s) to send Layer 2 (Ethernet) SV frames to the centralised protection within the local substation. Typically, layer 2 communication tunnels (or VPNs) are used. The GOOSE interaction (e.g. exchange of status or trip commands) between ends typically also uses Layer 2 GOOSE via tunnelling but may be done by R-GOOSE via an IP multicast capable IP network.

To facilitate compatibility to existing protection interfaces in a multi-ended line scheme, the new method uses a virtual protection communication bridge. One bridge allows the virtual connection of two line ends in the protection device. The proposed method allows the mix of virtual and physical protection interfaces for multi-ended line protection.

In the paper we will also present laboratory tests and a short circuit field test using devices of two different vendors.

John Haywood – H Nu Pty Ltd

Fiber Optic Current Transformers (FOCTs) been deployed in high voltage transmission networks for many years and proven their robust characteristics. However new requirements, particularly for new HVDC installations, require a new generation of sensors with faster response times. This is particularly important for protection of high-voltage semiconductor-based equipment and for travelling wave analysis. In addition, improved longevity, plug-and-play operation, and sometimes multi-kilometre distances between sensors and merging units are required for many of these protection applications. This paper explores how this new generation of requirements can be met. We present corresponding test data and discuss the future needs in this rapidly evolving class of components.

Sam Keeling – Siemens Ltd.

With controlled switching, the circuit breaker (CB) opening and/or closing is applied with consideration of the point-on-wave (PoW) of the system voltage to specifically time the instant of galvanic circuit interruption or conduction. 

By exact control of the CB switching, switching transients and inrush can be mitigated, if not eliminated to extend plant maintenance cycles and increase asset life. Asset lifecycle benefits including reduced transient voltages, fewer reignitions during CB opening of inductive loads and elimination of mechanical stresses due to inrush also favourably enhance grid voltage stability. 
Traditional PoW switching is to time the CB closing according to the type of equipment being energised and its grounding. In the case of a transformer CB, the initial pole (or poles) is closed at peak voltage such that the 90-degree leading flux is at zero. However, this method does not allow for residual flux, and consequently some inrush will still occur.

By considering residual flux, the controlled closing of a transformer CB aims to switch the initial pole(s) at such an instant that the prospective flux introduced by the energising voltage is perfectly aligned with the static flux in transformer limb (i.e. the residual flux). By such alignment, the pursuing sinusoidal dynamic flux on energisation has no offset, thus preventing the possibility of core saturation and eliminating inrush.

This paper looks at the practical aspects of transformer PoW closing with residual flux compensation.

Specific connection cycles for transformer PoW closing which may be applied depending on the transformer type and construction are reviewed, followed by an analysis of real-world switching examples for waveform analysis, to better understand the switching dynamics and commissioning tests required.

Uma Amirthanesan – Schweitzer Engineering Laboratories

Modern numerical protection relays generate event files that capture high resolution voltage and current data during system disturbances. These event files are typically created whenever a relay operates and issues a circuit breaker trip command. The recorded data provides a valuable resource for post event analysis and for identifying opportunities to improve protection scheme performance.

This paper examines the incorrect operation of a transformer differential protection element and presents a structured methodology to: 
i. determine whether the relay operation was correct or incorrect through interrogation of event file data; 
ii. identify the root cause of the misoperation; and 
iii. develop and validate a corrective solution using the same event records.

To support this analysis, this paper demonstrates how a transformer differential element can be simulated offline using phasor quantities derived from recorded waveforms. A practical method for extracting phasors from event file data is presented, enabling the differential protection algorithm to be recreated and evaluated outside the relay. Once the cause of the misoperation is identified, a corrective solution is proposed and implemented within the simulated protection element. The efficacy of the proposed solution is then verified by reapplying the original event file data and demonstrating correct operation under identical conditions.

This approach illustrates how detailed event file analysis and phasor-based simulation can be effectively combined to diagnose, correct, and validate solutions for protection relay misoperations.

Satendra Bhola – Tasnetworks, Leonardo Torelli – CSE, Matthew Weedin – Hydro Tasmania

The presentation will share real life examples of inadvertent energisation of a large generator as it was being prepared for synchronisation to the 220 kV power system in Tasmania. Power plants are equipped with circuit breaker that is used to connect and disconnect the generator to and from the network. Out of phase synchronisation of a generator circuit breaker will lead to large out of phase current with DC component. In this presentation we will go into the mechanism of circuit breaker pole conduction and subsequent sequence protection operation which caused one of two busbar protection schemes to operate and other scheme to restrain. Presentation will highlight the philosophy of circuit breaker fail protection and subtle differences in the logic of CB fail scheme implement in two busbar protection relays from different manufacturers.


Michael Stanbury – Ausgrid

Over the last 12 months, artificial intelligence (AI) has made remarkable leaps in capability, making this an appropriate time to ask whether it can be used as a practical engineering tool. This presentation shares real-world examples of how large language models (LLMs) are being applied in day-to-day protection and control work, with a focus on where they add value, where they can mislead, and how engineers can use them responsibly.

Case studies will include using AI to explain concepts, convert CT specifications, compare relay options, interrogate relay manuals, generate spreadsheet formulas, review code, and analyse event data. In one case, AI was used to build a spreadsheet to simulate CT saturation, which was then validated against real CT test data. In another, a SCADA technician (with no protection experience) used AI to develop a distance relay test shot that produced the desired SCADA signal. In a further example, AI analysed a 30,000-line modem log file, discovered a firmware bug, and then drafted an email to the manufacturer, who acknowledged the defect.

These examples demonstrate AI’s strengths in language-heavy, research-heavy, and iteration-heavy tasks. It is particularly effective at explaining, summarising, comparing, drafting, and accelerating first-pass analysis. However, it is not inherently trustworthy. It can make technical mistakes, fill gaps with plausible-sounding assumptions, and become more dangerous as its answers become more fluent. This presentation will discuss practical validation methods, appropriate levels of trust, ways to verify outputs, and the types of tasks that still require strong domain expertise and engineering judgement.

The presentation concludes with a reflection on what AI may mean for protection engineering careers over the next decade. This will cover the skills engineers will need, the training that will be valuable, and the likely directions these careers may take.

Aditya Parhad – Schweitzer Engineering Laboratories

A polarity error on a neutral CT can compromise both security and dependability of protection elements, such as Restricted Earth Fault (REF) and directional neutral overcurrent (67N). These errors can easily go unnoticed—a simple CT wiring check during commissioning is insufficient to confirm CT polarity, and without specially designed tests or careful attention to detail, neutral CT polarity issues may go unnoticed for years until a fault occurs. This paper presents a structured diagnostic approach for identifying incorrect neutral CT connections in REF and 67N applications, progressing from indirect to direct methods.

Indirect methods are non-invasive, relying on information readily available from protective relays, such as event reports and metering captures, that can be obtained without any outage or power disruption. This information is used to examine pre-fault power flow, the relationship between zero-sequence current and transformer neutral current, and the expected versus the observed current directions. The paper details that in addition to metering data, differential element behavior and transformer energization records can be analyzed to identify signature patterns indicative of a reversed-polarity neutral CT. While indirect analysis can strongly suggest the polarity error, definitive confirmation requires a direct test, which can only be performed during an equipment outage. This paper presents the DC kick test, describing the procedure, practical field considerations, and interpretation of results, as the conclusive diagnostic method.

The diagnostic approach is validated using a field case involving a 230/115 kV autotransformer at the Snohomish Public Utility District, supplemented by real-time digital simulations that illustrate the effectiveness of the methods discussed. The methodologies and field practices presented in this paper, along with the authors’ shared experience in executing DC kick testing under field conditions, offer valuable guidance for commissioning personnel and protection engineers in verifying correct CT polarity during initial installation and diagnosing potential connection issues, even in the absence of equipment outages.