Abstracts 2020

The APS steering committee of industry professionals have developed a high quality and topical program with engaging information for engineers and technicians and managers from electrical utilities, consultants, service companies, industrial and mining industries as well as those employed in the design, construction, commissioning, maintenance and assessment.

In 2020, APS will come to Sydney with below papers to be presented. Each presentation will be followed by an interactive questions and answers session.

IEC 61850 Based Centralized Substation Protection, Automation and Control – Principles and Benefits

Alexander Apostolov – PAC World, USA

The transition of the electric power industry into a Smart Grid requires the improvement of the reliability, security and efficiency of the electric power system.

The evolution of digital substations based on IEC 61850 sampled values, GOOSE messages and client/server communications is moving into the next phase of higher levels of functional integration – Centralized Substation Protection, Automation and Control systems (C-SPACS).

The paper starts with a brief introduction of the history of centralized substation protection.

This is followed by the description of the components of C-SPACS:

  • Process interface – non-conventional instrument transformers (NCIT), stand-alone merging units (SAMU), switchgear interface units (SIU), process interface units (PIU), process interface IEDs (PIIED)
  • Central Server
  • Communication system

The next part of the paper analyzes the different possible C-SPACS architectures.

The engineering of C-SPACS based on the IEC 61850 System Configuration Language (SCL) is later described.

The functional testing of C-SPACS is discussed at the end of the paper.

Experiences in design and commissioning of a secure substation network architecture

Wenyu GuoOMICRON electronics

Utilities and cyber security auditors are increasingly considering not only the control centre as critical attack vector, but also substations as potential entry points for cyber attacks. An important risk factor are the processes, how the commissioning of the protection and control systems are realized, because testing laptops and test sets are connected either directly to relays or to the station network, which provides an attack path to critical devices. Another risk factor is how remote maintenance access is implemented. Therefore, the architecture for the protection, automation and control system must be reviewed for security. To achieve this, the Swiss generation and distribution utility CKW (Centralschweizer Kraftwerke AG) started a project in 2016/2017 to develop a new reference architecture for their secondary systems, where cyber security was addressed intensively.

This paper starts with an enumeration of the most important cyber attack vectors in the substation lifecycle, followed by a description of the advanced security architecture implemented for the first time in a new greenfield 110kV substation project by CKW. Their design addresses these attack vectors with corresponding countermeasures, providing a very high level of security, while still offering a sensible balance between maintainability and security. The presented design includes multiple levels of security for maintenance remote access, and two firewall layers within the substation network. Additionally, an Intrusion Detection System (IDS) is applied on the station bus to follow the defence-in-depth principle by detecting malicious activity. Selecting a suitable IDS for substations proved out to be challenging, as many IDS provide little support for the special requirements in substation automation systems.

The paper concludes with the experiences and lessons learned during the factory acceptance testing and commissioning of this project.

Best practices and challenges on designing a LAN communication network for Digital Substations

Chirag Mistry GE Grid Solutions, Australia

Digital substations are at the heart of the 3 mega-trends of decentralization, decarbonization and digitalization. It allows utilities to reduce the footprint of their substations, replace oil insulated instrument transformers for optical counterparts, harvest advanced diagnostics and analytics data from their assets and act on such data remotely and expeditiously. All these benefits have a common enabling technology, modern Ethernet networks, enabling all devices in the substation to communicate with each other.

Fully digital substations are already a reality, with installed base growing more and more every year and one of the most challenging parts of moving to this kind of substation is the network engineering. Not because it is difficult to manage, but because it is a completely new field of knowledge to current power system engineers. Also, because it plays a fundamental role in this solution, as the network carries all the data needed for protection and control applications.

This paper aims to present the basic principles and techniques needed for the proper configuration, operation and maintenance of Ethernet networks in digital substations, considering practical aspects of data segregation, prioritization and redundancy for increased reliability. A brief introduction on the benefits and technologies utilized in digital substations is presented. We then discuss the kinds of messages found on such networks and their respective priorities, introducing basic aspects of GOOSE, Sampled Measured Values and PTP messages, including specific profiles for substations applications. Subsequently, we delve deeper in the on how to define a network architecture, following by advantages and disadvantages of each topology and concluding with best practices on network configuration using the most common set of tools, such as Quality of Service, VLAN and Multicast filtering. We discuss the practical application of the concepts, bringing FAT requirements from an actual project with a total of 14 bays. Finally, we present our final comments and recommendations based on the scenarios assessed during the paper.

Performance Evaluation of a NCIT in a Laboratory set up based on Process bus topology

Dinesh Mithanthaya, Principal Asset Strategy Engineer, Western Power

Reliability in protecting costly power assets during an electrical fault is the key feature of any protection system.  With the advancement in Digital Protection System and Substation Automation System (SAS), we can now more effectively manage, control and diagnose faults with minimum downtime than the conventional system. Implementation of digital protection schemes in a High Voltage (HV) substation provides optimized maintenance cost, reduced maintenance diagnostics and improved communication capabilities. Additionally, manufacturers are offering smart sensors that shall replace Conventional Instrument Transformers (CITs). These sensors are known as  Non Conventional Instrument Transformers (NCITs). Emergence of NCITs have made possible direct connections of NCIT to IEDs (protection relays) without the requirement of merging units. The NCITs connected to Intelligent Electronic Devices (IEDs) provide higher accuracy, better transient response and wider bandwidth when implemented in a process bus topology based on IEC 61850-9-2 standard.

Modern NCITs supervises intelligent process bus parameters and but also keeps the assets secured by isolating the assets from major faults while keeping the functionality of the substation philosophy intact. It is seen that use of NCIT could mitigate issues arising out of CIT failures, provide better safety, reliability, and increased asset life. At present, majority of CITs operational in the air insulated and gas insulated high voltage (HV) substations are either oil filled or SF6 type having environmental issues in the event of a catastrophic failure or leakage. NCITs have better performance as compared to CITs without the effect of secondary saturation. However, before these high voltage NCITs could find their way towards mass implementation in smart grids and digital substations, there is a need for further modelling and simulation at the design stage before large scale deployment in process bus based on IEC61850-9-2 for its successful implementation. Optimized Network Engineering Tool (OPNET) or Riverbed Modeler is a popular simulation software for such design and modeling of Ethernet networks. This paper presents a model of OPNET software for the simulation of a NCIT based on digital substation in a process bus environment.

Investigating an interoperable process bus and the gap between IEEE 1588 PTP and IEC 61850-9-2

Gavin de Hosson Senior Engineer – Protection and Control Innovation, Endeavour Energy

Utility adoption of digital substation technology remains at modest levels despite the number of fully operational sites globally and the well cited economic and construction benefits. Acknowledging successful global implementations to date, a deeper understanding of interoperable digital substation elements was sought by investigating the electrical performance characteristics of merging units, the fail over performance of GNSS time synchronisation equipment, and the system interactions between merging units and relays.

The detailed study of multiple GNSS clocks identified that the parameters within a PTP Sync message, such as time_traceable, to be reported differently by clocks during certain failure scenarios (for example, lack of sky visibility, or a disconnected antenna).

The application of the PTP message content also varies between merging unit manufacturers. The PTP Announce and Sync messages thoroughly describe the state of clock including traceability, timescale and definitive inaccuracy. However, each merging unit will reference different parts of the PTP Sync message to generate the single IEC 61850-9-2 parameter SmpSynch.

Well resolved electrical performance of merging units would allow IEDs from one manufacturer to be freely used with a merging unit of another. However, the differences in mapping PTP flags into SmpSynch – and the direct implication this may have on relaying logic – will limit the use of different merging units within any single application – challenging the replacement and substation expansion strategies of digital systems.

Innovative Protection Schemes Using Point-on-Wave Switching

Ernst Camm, Senior Manager – Consulting & Analytical Services, S&C Electric

Point-on-wave closing fault interrupters have been deployed in utility distribution networks for almost two decades. Although the application of these devices has been driven primarily by the significant reduction in network equipment stress and potential damage compared to conventional reclosing when testing for faults, innovative protection schemes associated with these devices have paved the way for many special applications. These protection schemes include: Intelligent Fuse Saving to overcome the limitations of conventional fuse-saving protection schemes, Pulse Finding and communication-enhanced coordination to overcome the limitations of coordinating or grading multiple protective devices in series, and loop restoration. These schemes are possible because of the high accuracy current- and voltage sensing capabilities, rapid point-on-wave closing, and communication capabilities of the point-on-wave closing fault interrupters. This paper will describe the details of these protection schemes and provide specific case studies of applications where it has been successfully implemented.

R-GOOSE a key feature for Distribution Automation and Protection Systems

Hernán Santana NOJA Power

The industry is pushing towards an intelligent and active distribution network that allows the creation of distributed automation and protection systems (DAPS), within a broad communications network, to obtain wide-area monitoring, protection and control (WAMPC). Automatic Circuit Recloser supporting standardized protocols of communication as R-GOOSE and IEC 61499 are the key to make it feasible.

The reclosers are the building blocks of a distributed automation scheme since they are able to interrupt faults in the field and provide the ability to process signals that can feedback to a centralized SCADA system or to a control and protection equipment that is part of a DAPS. Besides, the increasing acceptance and growth of IEC 61850 in the power automation system has brought routable GOOSE (R-GOOSE) which will eventually simplify the way to communicate IEDs located either in distribution or substation environment.

IEC/TR 61850-90-5 introduced GOOSE messages with the option of being routed into

the set of benefits that IEC 61850 already owns, providing the well-known advantages that it has demonstrated in electrical substations for automation and protection

schemes. This article discusses the benefits of having R-GOOSE in a recloser and its applications for distribution automation systems.

The Methodology and Challenges in Retrofitting Arc Flash Detecting Sensors and Protection Units onto Existing Old Switchgear Panels

Steve Dargan,MIEAUST, CPEng, Senior Electrical Engineer, EnergyAustralia

Sy Bui, MIEAUST, Associate, Energy Services, Aurecon

The existing electrical system at Yallourn Power Station includes protection equipment which can detect certain predictable electrical faults, then operating to isolate faulty components. This protection scheme was based on time overcurrent coordination techniques which required the upstream protection relays to have higher tripping times than downstream relays, and personnel near a fault might be exposed to higher than necessary incident energy should an arc-flash event occur.

An arc flash assessment was conducted, which indicated that the arc flash energy for all high voltage switchboards and some low voltage switchboards exceeded the energy level compatible with existing personnel protective equipment (PPE) used at Yallourn Power Station.

To reduce the protection clearance time and the arc flash incident energy, it was decided to retrofit fibre optic light sensors and new modern relays with arc flash protection capability on all 6.6kV switchboards and some major 415V switchboards. When the new protection relay detects fault current and the fibre optic light sensors see a high-intensity light, the relay trips the relevant circuit breaker via its high-speed output contacts, minimising relay trip time to about 1/16 of a cycle, which can reduce the amount of energy in an arc flash event. An additional challenge is that this rehabilitation work had to be done in the shortest possible periods of unit outage as the power station is a base-load generating plant.

This paper describes the methodology as well as some key challenges in retrofitting the arc flash detecting sensors and new protection relays on the old switchgear panels.

Lessons Learned From Generator Destructive Testing

Normann Fischer Schweitzer Engineering Laboratories

Avista Utilities, an energy company servicing part of the northwestern United States, has been in the process of upgrading a set of 8.8 MVA, 4.16 kV generators at one of their hydroelectric facilities on the Spokane River. The authors took this unique opportunity to perform destructive testing on one of these generators prior to its scheduled upgrade. The testing was performed during the fall of 2018. This paper describes the planning and execution of this destructive testing and also discusses the lessons learned throughout the entire process.

In this paper, we discuss the layout of the power station and generator, as well as the constraints they placed on the tests that could be performed. We describe the fault survey we performed on the machine and the resulting fault locations the survey identified for testing. We describe the process used to estimate the fault currents, the test setup and fixtures that were assembled, and the safety precautions established for the various tests. We provide an overview of the test results, including the generator terminal voltages and currents, the branch currents of the faulted phases, and the field voltage and current at the time of the fault. During the presentation, we will show videos taken during the generator tests. Lastly, in the paper we discuss future uses of the fault data, such as protection function development and verification and generator electromagnetic model validation. This paper is the first in a series of papers that will discuss the destructive testing of this generator and what we learned.

Commissioning and Testing case studies, New approaches to reduce commissioning time

Hamish MacGregor and Lara Kruk, Jacobs

Combining industry knowledge and experiences of various approaches to commissioning, it is possible to develop an optimal commissioning practice for greenfield projects.

By developing a commissioning procedure with a detailed test methodology, that makes use of standardised automated relay test plans and utilises software solutions for system-based protection testing, commissioning time can be reduced. The risks associated with non-standard, unproven designs can be managed in a way that will minimise their impact on schedule and the need for float in the commissioning schedule is reduced.

In addition to an updated commissioning procedure, certain design principles can assist in reducing commissioning time. By implementing an individual switch bay room concept, whereby all protection and control equipment for a single bay are installed in a modular building the majority of the stage 1 commissioning tests can be undertaken at the factory and there is no reliance on the completion of civil and primary works to proceed with this testing.

This paper provides a comparison between the established commissioning practices followed on a recent greenfield project with an updated practice based on a combination of documented process, pre-developed automated test plans, pre-developed station models for system testing and design principles, with a breakdown of the time required to undertake activities in order to demonstrate where time savings in commissioning may be achieved.

Protection Relay Maintenance from an OEM’s Perspective

Daniel Abetz, Application Engineer – Digital Grid – Siemens Ltd, Australia

Maintenance testing of protection relays can be laborious, time consuming, complex and is fraught with inherent risk. With the increasing number of functions being centralised into a smaller number of devices, each with inbuilt self-testing functionality, maintenance and asset managers need to carefully consider the best way to optimise their maintenance regimes. This paper discusses the recommended maintenance routines from a relay manufacturer’s perspective, so as to make full use of internal test functions in modern protection relays and protocols. It will start with a discussion of the architecture of a modern protection relay and the available internal diagnostic functions. Next, the philosophy of testing will be examined to determine relevant boundaries for testing. Finally, testing in a digital substation will be examined, with several examples of testing errors along with real world failures being presented throughout. Several design and configuration suggestions will also be included to ensure that full use is made of the internal diagnostic functions.

Best practice and new approaches to reduce commissioning time – an iterative model

Herb Moore Commissioning Engineer Citipower & Powercor

Background – What we are doing in our organization

With the purchase and rollout of new Omicron CMC356 test equipment and a new ITR

(Integrated Test Report) initiative implemented by our Protection & Control Group, it was decided that standardized ITR and associated relay test plans are required.   

To achieve this using the Omicron CMC356 multiple Omicron Control Centre (.occ) files have been created, each one intended to test all required functions of a respective relay.

Why we have chosen this path

We have chosen this pre-commissioning and commissioning philosophy to enable continual improvement and correction. This helps to identify errors and issues quickly and incorporate fixes into new releases, rendering each one slightly better than its predecessor. 

Previously, there were multiple copies of Integrated Test Plans and accompanying .occ files throughout the organization to test the same relay. This previous practice was inherently variable which should be avoided. 

The new methodology offers the following advantages:

– Repeatability

– Issue and error identification and resolution given single source of creation

– Performance measurement – comparable metrics for speed and quality of testing across sites

– Continual improvement since there are one set of files that can be iterated on. All levels can input suggestions and corrections

– Single points of responsibility during project lifecycle as a result of clear lines of authority (relating to document management)

he development model showing this methodology will also be presented. A look into implementation on a 351S Feeder Management Relay

This will be a brief case study walking through an actual example of the implementation of this methodology. 

Techniques to reduce commissioning time – including code

A result of this new methodology has been automation in testing that is transparent, repeatable, and testable. 

A python script has been created to automate the setting of outputs on the SEL relay during testing. This realizes a savings of approximately two hours of testing per relay.

The script and further suggestions for automation philosophy will be discussed in the presentation.

Implementation of the Wide Area Monitoring Scheme in South Australia

Leonardo Torelli Technology Manager, Protection and Control at CSE Uniserve, Australia

Wide Area Monitoring System, WAMS, is one the most reliable method to understand the behaviour of the power system during a disturbance and relies on the use of synchrophasor technology. Gathering current, voltage measurement information in different parts of the network allows utilities to analyse the network, predict the response and provides opportunity to implement fast and proportionate active control to stabilise the power system.

Following the South Australia September 2016 blackout, the Australian Energy Market Operator, AEMO, recommended further investigation to improve the existing System Integrity Protection Scheme, SIPS.

This paper elaborates the project recently initiated by Electranet to deploy a WAMS to analyse the network and its behaviour during disturbances, expose Electranet business to the WAMS technology and demonstrate during a 12 month trial period a pilot “ Out of Step” control scheme to further reduce the likelihood of the separation of South Australia from Victoria during a major disturbance.

Time in Substation Protection and Control Systems– Principles and Applications

Alexander Apostolov – PAC World, USA

This is a tutorial type paper intended to describe the role that time plays in modern substation protection and control systems.

It first introduces the use of time for traditional protection and control applications, predominantly for post-fault analysis of protection operations.

Later it focuses on modern state-of-the-art digital substations based on the IEC 61850 international standard for electric power system communications. It is developed in a way that allows it to support many different protection, automation and control applications. Time plays a very important role in the implementation of these applications and as a result is a key component of the IEC 61850 standard.

The paper identifies the requirements for time synchronization for protection, control, recording and event analysis. The use of 1 millisecond or 1 microsecond accuracy of the time synchronization is described.

The second part of the paper discusses the use of time in the IEC 61850 modelling of different data objects and services. The use of the Coordinated Universal Time (UTC) and the concepts of timestamps for different common data classes is later presented. Time quality as an attribute in the object models is also described, including issues related to leap seconds, clock failure, and clock not synchronized. The definition of Time Performance Class and the different levels defined in the standard is later presented.

Timestamps in GOOSE messages and Sampled Values messages are also discussed, including the use of the sequence counter in the latter as a timestamp and its processing for protection and disturbance recording applications.

The third part of the paper discusses SNTP and the utility profile of the Precision Time Protocol (PTP) defined in IEC 61850 9-3 as the time synchronization methods that can be used in IEC 61850 based systems. The changes in time synchronization methods between Edition 1 and Edition 2 of the standard and the impact on the time synchronization system architecture is covered. The selection of the time synchronization method as a function of the use of synchro phasor measurements and merging units is described.

The use of different time sources is covered in the next part of the paper. Time synchronization based on GPS, Galileo, GLONASS and Beidou is discussed. GPS spoofing and the impact of solar flares on time synchronization is also described. Using time synchronization sources with multiple satellite sources and with embedded atomic clocks is later analyzed.

The use of timestamps from time synchronized IEDs for calculation of the transmission time over the substation local area network or wide area applications is later described. The impact of loss of time synchronization on different protection schemes within the substation and between substations is also discussed.

Interoperability of Line Differential Protection

Joerg Blumschein Siemens

Line differential protection is used for a long time to protect overhead lines and cables of transmission and distribution systems. The basic principle of line differential protection is Kirchhoff’s current law. Due to this principle line differential protection is strictly selective to clear faults on the protected line.

To apply Kirchhoff’s current law a line differential protection needs the currents from both ends of the protected line. The currents from the local end can be measured directly by means of current transformers, connected to the line differential protection device. The remote end currents however cannot be measured directly by the local line differential protection device. In general, the remote end currents are measured by a line differential protection device of same type and afterwards sent via communication link.

Due to bandwidth restrictions of the communication link, differences in pre-processing of the measured values and other device specific implementations there is no interoperability of line differential protection. In general line differential protection requires both devices from the same manufacturer. Often the same device type or even the same firmware version is needed. Today there is no interoperability for line differential protection. In case one substation gets an update of the line differential protection, the remote substation needs an update of the related line differential protection too.

The paper describes a real case how interoperability was achieved for line differential protection of different protection platforms of one manufacturer. The problems and limitations for this use case are explained in detail.

In addition to this the paper suggests an implementation of line differential protection based on sampled measured values and GOOSE according to IEC61850 and IEC61869. With this approach, the communication interface between the line differential protection devices becomes interoperable. More flexible solutions are found to be possible. For instance, a line differential scheme might consist of only one line differential relay, receiving sampled measured values from a merging unit located at the remote end. The trip command for the remote end might be transferred via GOOSE to the merging unit located at the remote end. For redundancy even two different line differential protection relays could be used feeding each other with the sampled measured values from the remote end.

Unexpected Output from Delta connected CTs

Pranesh Pal Principal Engineer Network Performance – Powerlink Queensland

The normal action of the earthing transformer is to pass zero sequence current.  Delta connected CTs are provided to filter out the zero sequence currents. This arrangement of the CT can be used to provide fast and sensitive protection in the earthing transformer itself.  No current output is expected from the Delta Connected CTs for any earth faults on the system. During a single line to ground (SLG) fault, the magnetic flux in the zig-zag transformer coils are not equal in the faulted phase. Therefore, a zero sequence current flows through all the windings of the transformer, and at the neutral, they are added up. An earth fault on the system resulted in an unexpected output from the Delta connected CTs. This paper attempts to explain the observed fault currents and suggests how to implement changes to obtain a more secure protection system.

The evolution of transformer protection schemes and how to keep up with testing

Maryam Khallaghi OMICRON Electronics

New developments in the field of power transformer protection are promising higher sensitivity and higher stability at the same time. But are these developments applicable to every power system? How much improvement is provided and are they worth the investment of deploying new protection principles? And finally, how do we test it?

This paper will investigate two major development:

Time-Domain Algorithms: Due to modern transformer core materials and increasing relay processing power, time-domain waveshape-based algorithms are becoming attractive alternatives to traditional harmonic-based methods for discriminating between fault and transformer inrush conditions. While time-domain inrush detection increases the speed and security of transformer protection, it also creates a need for new testing methods. Testing with superimposed harmonics (2nd, 4th, 5th, etc.) will not work anymore.

Restricted earth fault (REF): REF protection increases the sensitivity for internal earth faults close to the starpoint of the transformer. Testing the REF element without disabling other elements, which is considered harmful, is often challenging.

While not specific to transformer protection, IEC 61850 Sampled Values (SV) and low power instrument transformers (LPIT) are providing further benefits to the application. The paper will show how we can take advantage of SVs to simplify and extend the test setup, esp. for large protection schemes with many current inputs, as it is the case for example for three-winding transformers. 

Further we will investigate a system-based test approach, where the transformer non-linear behavior of inrush and overexcitation conditions and internal faults are simulated, as a simple and efficient solution for the challenges mentioned above.

Using Dynamic Simulation Software (PSCAD) to study and determine suitable generator pole slip protection settings

May Huang, MIEAUST, Senior Electrical Engineer, Aurecon

Usman Mahmood , M. Eng. (Power Generation), CPEng, MIEAUST, Electrical Services   Engineer, EnergyAustralia

Pole slip is a condition when a generator falls out of synchronism under abnormal system conditions, such as long clearance time of a high current fault at the transmission substation where the generator is connected to. When pole slipping occurs in a generator, large and rapid oscillations in active and reactive power will occur between the generator and power system, causing severe damage to the generator turbine, overheating the rotor and the stator. Pole slip protection settings are usually difficult to manually calculate using just the generator parameters and system data. Hence, a power system simulation software is essential to dynamically simulate the generator behaviour under such transient conditions. It is also used to determine correct pole slip protection settings to safeguard generating units against harmful effects of pole slipping conditions.   

In this paper, a typical example of how such a dynamic simulation study, using a simulation software PSCAD, was performed on a large generating power station to simulate the generator behaviour under power swing conditions and to determine suitable pole slip protection settings for such generating units. A PSCAD model was created, comprising of the generator AVR, under-excitation limiter, power system stabiliser and the load drop compensation. Two operating scenarios were considered, one with a single generating unit in service, and the other with both generating units in service. Critical fault clearance time was found by running the simulation with different fault duration, to determine the threshold when the generator unit starts pole slipping. Subsequently, the generator impedance locus for different fault clearance time was studied, to check whether the proposed pole slip protection settings were adequate. The pole slip protection settings need to ensure that the relay will not operate for fault duration that is insufficient to cause the generator to pole slip; and that the relay will operate for a genuine pole slip condition. 

This study has demonstrated that using dynamic simulation modelling is essential in dynamic modelling of the interaction between a power network and generating units and to verify the adequacy and effectiveness of any proposed pole slip protection settings.

Line Current Differential : Improvement for detecting Saturated CT and Reliability Line Current Differential Relay’s outside zone fault experience

Reza Widya Hutama, PT. PLN Persero UPT KALTIMRA, Indonesia

In this paper the challenges will be discussed in the relay line current differential (LCD) when there is a saturated Current Transformer (CT). Selectivity is an important point for protection system reliability. When there is no selectivity there is a possibility of the mal function of the protection relay. Beside that it can cause difficulties when evaluating the disturbances that occur. Saturated CT will produce an inaccurate magnitude of current. The current calculation read on the LCD will produce a value that can make the LCD work even if it is not in the protection zone. Basically there is a parameter setting on the LCD such as slope and value trip current. These parameters setting will not help when there is a differential current value that is calculated and exceeds the setting value and will cause the relay is working.

The discussion of “new methods” that can be done to detect anomalies in saturated CT is discussed in this paper. Utilization of calculations and any protection functions is available on LCDs can be combined to detect anomalies on CT and allow preventing the occurrence of LCD mal functions. When the anomaly can be detected, it will be easy to evaluate on improvements to the existing protection system

Current transformer saturation - how, when, why, and how to guess it

Terry Foxcroft Power Test Services

Understanding current transformer saturation is critical when using traditional instrument transformers. There are several methods used to approximate the saturation effect and resulting waveforms. This paper discusses why saturation occurs, and two main programmes available for the saturation analysis. It also discusses the issues when using IEEE based methodology on IEC based class current transformers.

It will also provide an Excel spreadsheet for calculation of PX class current transformer saturation.

Mitigating Bush Fires with a reliable detection solution for overhead lines up to 36kV


Overhead distribution lines are used to provide power to customers sometimes over long distances. Upon ground fault occurrence (a bird extending its wings, vegetation, wind effect, broken conductor etc), the generated fault current makes the upstream recloser trip and isolate the faulty section of this overhead line.

A broken conductor touching the ground may start a bushfire in certain conditions. This type of fault may be detected from an upstream recloser using ANSI 46 (based on currents) or from a downstream-located device using ANSI47 (based on voltages). When the ground fault current is high enough for the recloser to detect it, this means the fault current is quite high: a Petersen coil located at the primary substation can quickly reduce it (this is the case in Europe). When the ground fault current is too low, neither the recloser not the Petersen coil can detect it: but the current is still sufficient to start a bushfire.

A Modular Feeder Automation RTU can be used in this instance and is made of several parts:

  • The Head Unit Gateway (local/remote communications, secure webserver, etc.)
  • MV/LV monitoring module
  • Power Supply module
  • Distribution Transformer Monitoring

Using ANSI 47 algorithm, the distribution transformer monitoring module can detect an MV broken conductor occurring upstream and forward the alarm through the Head Unit Gateway. This solution applies to overhead lines fitted with three phase conductors.

The equipment is to be installed at each end of the circuit (main and branches) and connected to a 3-phase MV/LV transformer output (R, S, T, N).

A typical equipment shall consist of a small Modular Feeder Automation RTU cabinet fitted with a Head Unit Gateway, MV/LV Monitoring Module, Power Supply Module with small backup battery and a wireless option (embedded LTE modem or a radio). The LV Monitoring Module processes the data it measures from the 3-phase transformer output: upon broken conductor occurrence, it generates an alarm. This alarm is then forwarded by the Head Unit Gateway (in DNP3 protocol, etc.) through the wireless link to the recloser located upstream to make it trip and isolate the fault.

Broken conductor detection ability is no longer limited to high ground fault currents