Abstracts 2022

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.

The APS will be held over 2 days as a hybrid event. The event will take place at Novotel on Collins in Melbourne.  Each presentation will be followed by an interactive questions and answers session. Attendees from all over the world can also join the symposium from the comfort of their home or office and join the presentations live and have the possibility to submit questions to be discussed and answered by the panel of presenters at the end of the day.

Point on Wave Switching Applications and Adjustments

Trevor Scott – Siemens

Point on wave switching on circuit breakers is often installed on Transformer, Capacitor, Transmission line and Reactor substation bays to avoid potential plant and systems hazards resulting from inrush current, over voltages, and re-striking issues.

The point on wave control function has usually been implemented in a dedicated device supplied by the circuit breaker manufacturer.

The evolution of protection and control functions into consolidated hardware platforms make it possible for the Point of Wave function to now be incorporated in protection IEDs and merging units.

This presentation will detail the theory of point on wave switching for different applications which inform the configuration of the function in the design phase of a power system project.

The testing of this function is very important since is it not possible to complete settings required without knowing actual circuit breaker operation timings. Examples are to be presented on how to test and adjust the function to ensure correct operation.

The Implementation and Design Decisions of Process Bus Technology for Distribution Substations

Gavin DeHosson – Endeavour Energy

In 2019 Endeavour Energy was presented with an increasing number of greenfield substation construction projects. With a view to support efficient design, construction, and operations a small team was formed to review Secondary Systems philosophies. With previous exposure only to IEC 61850 station bus (MMS) the team reviewed the benefits that an IEC 61850 process bus could bring to future substation builds. By mid-2022 Endeavour Energy had commissioned its first “fully digital” process bus at a 132kV to 22kV zone substation utilising Sampled Values, GOOSE and MMS in a fully interoperable setting. The purpose of this paper is to provide a case study of the journey that Endeavour Energy followed over these 3 years and document the design decision philosophy relevant in the utility context.

The paper will discuss the three distinct project phases (research, design and validation, and commissioning) and go on to discuss the multiple proof of concept and pilot projects, the cross functional design teams, and outcomes of supportive relationships with industry partners. The paper will also focus on a key design objective to achieve a system with a high level of maintainability and provide a seamless transition to digital substations for operational staff.

Optimal Use of IEC61850 Test Modes in Substations

Daniel Abetz – Siemens Ltd

In this paper, we will investigate the different test and simulation modes offered in the IEC61850 standard and how they can be used to create an operational advantage for industrial and utility users. Attention is then given to the design and prototyping stages of a project, where testing requirements must be initially considered and addressed. The use of test modes in regular operational activities will be described by several typical use cases for both station bus and process bus applications. The advantages of controlling test modes at the functional level rather than device level will be presented. A method to test this functionality using Digital Twins of protection devices will be presented, showing how verification can be performed already at the design phase without any physical IEDs, and how Digital Twins can also integrate into multi-vendor solutions.

Engineering and moving data for Asset Management, Smart Grid, Renewables, DER and Microgrids

Rodney HUGHES – Rod Hughes Consulting Pty Ltd

Ohm’s Law and Kirchhoff’s Law still form the basis of all electrical engineering. However, with his year as the 20th birthday of the IEC 61850 engineering process “to configure IEDs to communicate”, this paper explores just how much we depend on communications in the ever-increasing pressures of asset management, smarty grid, renewable energy, DER and microgrids.

Obviously, the emergence of IEC 61850 is a “game changer” with totally different engineering processes as well as the physical implementation of signal transmission for protection and SCADA. For some the change has been in total immersion to the full extent offered by the Standard. For others, it has been to various degrees of change of engineering process and/or physical implementation. For some the change may yet to be adopted, or perhaps even reverting to the “old ways”.

Over the same period, we have seen, and continue to see the ever-increasing demands for some sort of higher intelligence in our power system operations, asset management and all things to do with Smart Grid, Microgrids and all manner of Distributed Energy Resources. The demand and use of information about the power system has just “exploded” from the “dozen or so” data points that existed in the 1990’s to now several (hundreds of) thousand individual pieces of information.

The issue at hand for engineers is not the “objective” as such, but how to implement them in “new and improved” engineering solutions with each new project to work towards the overall objectives in a coherent progressive manner. This paper reviews where IEC 61850 is going far beyond substation protection and SCADA.

74 or 86, High or Low Burden, and TCM

Rodney HUGHES – Rod Hughes Consulting Pty Ltd

Protection has certainly become a domain of technology and sophistication. Digital, then numerical and then Intelligent Electronic Devices have challenged both old and young engineers for a few decades. The “digital” or “IoT” revolution has taken over much of our protection systems engineering thoughts, tools and processes. It is topical and necessary to explore the range of knowledge and applications they apply to.

We have already seen the move to digitalisation of analogue measurements for current, voltage, temperature, position .. infact over 20 different analogue sensors. We are yet to see the explosion of digital interfaces to intelligent switchgear, but it is on the not-too distant technical-reality horizon.

However, the principles and primary role of protection relays and systems remains the same … detect a fault and reliably initiate tripping of a circuit breaker when required but with security not to trip when not required.

Until digital interfaces to the switchgear are commonplace under IEC 62271 3 HV Digital Interfaces based on IEC 61850 (Ed 1 as of 2006), we still require the wire-based trip circuits as the signalling between the relay and the circuit breaker.

Whilst we spend a lot of consideration of the protection function the trip circuit and even the tripping relay are prime components of a reliable protection system.

This paper explores the often-overlooked requirements for device #86 Tripping Relays (as distinct from device #74 Auxiliary) and the correct implementation of Trip Circuit Monitoring.

Case Study: Role of DC systems in the operation of a Protection Scheme

Usman Mahmood – EnergyAustralia

Protection and Control (PAC) Systems are an essential and critical part of any power network. The failure of such a system to operate when required can have cascading detrimental effects, resulting in the destruction of equipment and loss of the supply to other healthy parts of the network. The PAC systems in a typical power network monitors the network, controls the operation of circuit breakers/isolators to allow routine switching operations, detects a fault and isolate faulty sections of the network.

Traditionally, dual redundant DC supplies used for the PAC systems in power stations, substations, and other major industrial facilities. The main reason for using DC supply in PAC systems is to provide a continuous power supply. DC is a reliable source of power supply because it can obtain from batteries. The DC supply instead of AC Supply in a PAC system also gives some additional benefits such as less reaction time, and simpler circuits for connection of redundant supplies using the diode auctioneered arrangement. However, such systems also have certain limitation and earth faults on the Dc systems can present over/under voltages situations in a diode auctioneering arrangement, resulting in catastrophic destruction of the system.

This paper presents an overview of the current practice of DC supplies at thermal power stations in New South Wales. This paper also discusses the key issues to be considered when designing and operating such critical auxiliary systems.

Centralized Protection and Control for Distribution Substations. (A fresh novel approach to protection & control.)

Anisur Rahman – ABB Australia Pty Ltd.

Power distribution systems are one of the most complex infrastructures found worldwide and they are expected to operate with high quality and reliability. There is a growing need for flexible protection and control products, and for flexible solutions and services to support and manage those products. The concept of centralized protection and control (CPC) is not new, but only the advancements in computing technology and international standards have made it a feasible alternative for modern substations. The key technical enablers for Centralized Protection and Control are the development of IEC 61850 standard as described shortly below:

IEC61850 Station and Process Bus: IEC 61850 standard have made fast and standardized Ethernet-based communication more available. The station bus as defined in IEC 61850-8-1 allows relay-to-relay communications. The process bus as defined in IEC 61850-9-2 allows sharing of digitized information from instrument transformers or sensors in a standardized way to other relays and/or CPC units. This has enabled shifting of protection and control functions between different relays and/or CPC units at the substation level.

Merging Unit: The interface of the instrument transformers (both conventional and non-conventional) with a relay and CPC unit is through a device called Merging Unit (MU).

Substation Time Synchronization: IEEE 1588v2 and IEC 61850-9-3 makes it possible to achieve a time synchronization accuracy of 1 μs. This is required if an IEC 61850-9-2 process bus is used.

Communication Redundancy: High availability and high reliability of a communication network are two very important parameters for architectures utilizing a CPC system. IEC 61850 standard mandates the use of IEC62439-3 standard wherein clause 4 of the standard defines Parallel Redundancy Protocol (PRP) and Clause 5 defines High-Availability Seamless Redundancy (HSR). Both methods of network recovery provide “zero recovery time” with no packet loss in case of single network failure.

ABB’s Smart substation control and protection SSC600 (CPC) is a novel approach to protection and control in distribution networks – centralizing all protection and control functionality into one single device on the substation level. The ability to protect and control a wide variety of utility and industrial applications with a single device allows convenient station-wide visibility, minimal engineering, and easy and cost-efficient process management.

SSC600 is IEC 61850 standard-compliant and offers unprecedented flexibility throughout the substation’s entire lifetime. Fully modular software allows it to change with the evolving grid and meet the challenge of increasing digitalization. The modification can be done on site – by end-users – without network or cloud access. Advantage of only having to engineer or modify one device instead of all bay-level protection and control devices with the new centralized approach.

Centralized Protection and Control (CPC) is a promising new concept for distribution substations, and it has several benefits in comparison to the conventional relay-per-bay based approach. Consolidating multiple relays (30 relays) into one device reduces system complexity and offers effective ways to manage protection and control functions in the network. In addition to the benefits related to protection and control functionality, there is also the possibility to get other advantages such as a Centralized Fault Monitoring System (CFMS) for the complete substation for easy and efficient fault analysis. As the centralized unit has access to all substation measurements simultaneously, the same data can also be used for substation-wide disturbance, fault, and event recording purposes that can be post-analyzed in the same or in a separate system. The main benefits from the solution are related to increased flexibility and performance and reduced overall lifecycle costs.

Six-phase Line Transmission – What It Is and Why We Need It

Alex Apostolov – PAC World Magazine

Since the beginning of the 21st century the development and installation of renewable generation globally exploded exponentially, becoming a source of large amounts of clean power. However, due to the nature of the energy sources – typically wind and solar, the virtual power plants based on this technology are located in remote areas far from the large load centers. It is clear that this creates a problem – how to deliver the power from where it is produced to where it is needed. There are already times when grid operators have to dump energy produced by wind turbines on windy days because regional power systems cannot handle it. That is why many utilities around the world have been looking at all the possible solutions to the problem. but there is one potential solution that almost nobody is talking about – six-phase transmission. What will happen if we tell the industry that we can increase the power transfer of many of the existing double circuit transmission lines by 73% which may meet many of the existing requirements for transferring power from the new renewable power plants to the large load centers that these transmission lines are any ways connected to. This appears to be the most promising solution, because it meets the need to increase the capability of existing transmission lines and at the same time respond to the concerns over electromagnetic fields. The paper introduces the concept of six phase line transmission and how an existing double circuit three phase transmission line can be converted to a single six phase line. It later looks at the experience with the high phase order demonstration project at New York State Electric and Gas in the early 1990s which converted an existing 115 KV double circuit line to a 161 KV 6 phase line. The modeling of the line for short circuit currents calculations, the protection system implemented based on the integration of existing state of the art microprocessor based relays into a six-phase protection system and the experience of the operation for two faults that occurred when the line was operational prove that this can be achieved, especially with the developments in protection and communications technology available to us today. The last part of the paper describes the protection system for a six phase line based on the IEC 61850 technology.

Accelerated Protection Schemes for Systems with High Penetration of Inverter Based Resources

Alex Apostolov – PAC World Magazine

In its effort to help resolving the impact of fossil fuels-based generation on global warming, the electric power industry is switching to an ever-growing use of renewable distributed energy resources. However, this is changing dramatically the characteristics of the electric power grid which requires changes in the protection systems used in areas with high penetration of DERs. One of the main characteristics of renewable energy resources is that they are typically connected to the electric power grid through inverters, which under short circuit conditions do not produce fault currents the same way synchronous generators do. This makes challenging the use of the traditional overcurrent or distance protection schemes. On the other hand, there are requirements for a ride through capability of the DERs which means that they have to be able to withstand the short circuit fault condition and remain in service until it is cleared by the protection system. Unfortunately, the traditional time overcurrent or multizone distance protection are not going to be able to meet the requirements for fast fault clearing which will lead to the loss of generating sources. The good news is that the developments of communication technology and availability of accelerated protection schemes offer a solution to both these challenges. The paper first looks at the requirements for fast fault clearing based on the analysis of the ride through characteristic defined by many countries. It then analyzes the performance of step distance protection under fault conditions in systems with high penetration of DERs and demonstrates that the traditional zone 2 operating times for faults at the end of the protected line are going to lead to the loss of many DERs. The second part of the paper analyzes the availability of accelerated protection schemes and more specifically looks at the weak infeed logic. This analysis demonstrates that such a protection scheme can clear a fault anywhere in the protected line without any significant time delay which will maintain the operation of the DERs because of the short fault clearing time. The main challenge for the implementation of this scheme is that it requires a communication channel between the two ends of the protected line. That is why in the last part of the paper we look at what communications options are available to provide a link between the relays at both ends of the line in the most efficient way. Routable GOOSE is an option that is considered the most promising because it does not require a dedicated communications channel while at the same time significantly reduces the fault clearing time. The testing of such protection schemes is discussed at the end of the paper.

LIine Protection Testing and Fault Data Analysis

Eduardo B. Hollanes – National Grid Corporation Of The Philippines

1. Testing of Line Protection with Impedance characteristics extracted from relay xrio file. 2. Relay fault data analysis which can be viewed on impedance characteristics to determine what zone where the fault belong.

New Protection Method to Detect a High Voltage Broken Conductor in Distribution

Leonardo Torelli – CSE Uniserve

Distribution protection schemes have reached a high level of reliability to detect most fault conditions. However, there are some types of faults which are more challenging and the optimum equilibrium between protection dependability and security is not simple. Broken conductors can take place due to a previous fault, conductor aging, storms, line failures or road accidents. Eventually, a broken falling conductor touches the ground and might generate a high impedance fault, which is also difficult to be detected. The worst-case scenario is that the undetected downed conductor initiates a fire. In distribution, due to the presence of distributed energy resources, location of the broken conductor, low load conditions and single-phase switching, the traditional I2/I1 technique might not be adequate. This presentation details a new algorithm to detect and isolate a broken overhead line before touches the ground, using PMU or Analogue GOOSE data. The new algorithm has been tested using RTDS with a large case library of typical faults, broken conductor, and various DER penetration on the feeder. Now, the scheme is implemented in a field pilot project. The goal of this new solution is to reduce the risk associated with a broken falling conductor in a high-risk fire area. Leonardo Torelli

Requirements and Technological Trends on Stand Alone Merging Units

Chirag Mistry – GE Grid Solutions

“Since early 2000s, international boards such as IEC and IEEE have introduced a series of standards which rule the communication process within Intelligent electronic devices (IED). The IEC 61850 Standard describes the information model and the communication services that must be supported on every function to be performed by systems for power utility automation.

Standardization of the communication services and information models was important for the digital substation concept. In addition, another important step towards obtaining a fully interoperable Substation Automation System, is the standardization of the physical and digital interfaces.

In the context of representing interfaces to primary equipment, the IEDs in charge of acquiring voltages/currents from instrument transformers, digitize and transmit them via Ethernet networks are known as SAMU (Stand Alone Merging Units) or MU (Merging Units). The recent IEC 61869 standard series brings a more comprehensive way to characterize the analogue and digital interfaces for Instrument Transformers, especially with -13 and -9 parts covering specially SAMU and MU requirements. Before IEC 61869, standards were not suited for SAMU or MU applications in terms of performance, dynamic ranges, EMC performance and environmental aspects and transient performances.

Despite all the advantages that IEC 61869-13 brings to the SAMU/MU scenario, some concerning points arise in the hardware design aspects of the product. By specifying that every acquisition channel needs to be rated for both protection and metering applications, in addition to the enlarged values defined as preferred for dynamic range, signal measurement clipping, transient response, thermal withstand and frequency response; imposes serious challenges for the analogue acquisition technologies currently in use, prominently dominated by magnetic core and shunt resistors.

On the other hand, IEC 61869-9 brings some challenges to the communication aspects in term of modelling, configuration, and backward compatibility. One concern arises in this regard is the existence of a mismatch between IEC 61850 series and IEC 61869-9. Since the last available edition for the IEC 61850 (2.1) was released after the last edition of the IEC 61869, making the latter being outdated compared to the former, thus some Sampled Values communication Protocol (SV) enhancement are not included in IEC 61869.

With specific focus on the IEC 61869-13, use cases of SAMUs operating within different levels described in the standard are studied using simulation software and test sets aiming to discuss the impact of the new requirements in real applications for digital substations.

The intention of this presentation is to illustrate how these two standard series complement each other, how they differ from their predecessor standards and the challenges faced by the current technologies for analogue interface on both protection and metering applications to attain the exigencies described in there.

Autoreclose Optimization in Hybrid Transmission Using Fault Locator Based on Traveling Wave

Anton Junaidi, Andi Setiawan, David Mizpa Grace – PT. PLN (Persero) UIP3B Sumatera

PLN as a company that manages the supply of electricity is always trying to improve the supply and reliability of electricity for consumers. Protection on the transmission line greatly determines the reliability of the distribution of electric power so that it needs good attention in the implementation of settings and the application of autoreclose.

Traveling Wave technology is currently generally used in Fault Location device. The Fault Locator device using time domain technology will produce an accurate and fast estimate of the fault location.

Sumatera – Bangka interconnection transmission line is one of the Hybrid transmission lines in the working area of UIP3B Sumatera, which consists of various types of transmission lines consisting of Over Head Line, Under Ground Cable, and Submarine Cable with a total length of 65.73 km. Under these conditions, a transmission protection scheme is needed along with a very reliable and selective Auto Reclose function to be able to distinguish between disturbances on the transmission line which allows the auto reclose function to work or not.

By combining the Line Current Differential as a Protection Relay and function of Fault Locator device based on Traveling Wave with time domain technology on the Sumatera – Bangka interconnection, we will get a Hybrid transmission protection system that is reliable, selective and fast, so that the distribution of electricity between these 2 sub-systems can be more reliability.

Inverter Based Generation - From a Protection Viewpoint

Ritesh Bharat – CitiPower and Powercor

The push for green and clean energy is resulting in addition of more and more inverter based renewable generation into the grid. Consequently, decommissioning of traditional thermal power plants is on the rise. This change in generation mix is presenting new challenges to the power system. Conventional generators, which had a predicable reaction to disturbances, are now being replaced with thyristor-based stations which throttle the fault current to levels well below the load current. This makes it hard for the protection to differentiate between what is normal and what is abnormal. This presentation will touch upon some of the issues arising due to increase in renewable energy sources and it’s countermeasures.

Experiences of IEC 61850-based Grid station

Thai Anh Tran – Applied Technical Systems Join Stock Company (ATS JSC)

Integrated computerized system with multi-vendor IED for Station bus, Process bus and applications in tthesystem operation.

Enhancing Transformer Protection Reliability with System-Based Testing

Christopher Pritchard – OMICRON Electronics GmbH, , Austria

While the basic premise of transformer differential protection is straightforward, numerous features are employed in relay algorithms to compensate for challenges presented by the transformer differential application. As a result, designing a transformer protection scheme and calculating the right settings can be challenging. Therefore, validating the correct behavior by testing before the scheme goes into operation is advisable.

Traditional settings-based tests quickly reach their limits when it comes to such validation. Setting-based tests assure that all measurements and derived quantities are measured and calculated accurately and that the overall relay hardware including inputs and outputs are functioning, by defining sequence of steady state values. When testing the restraint characteristic, for example, one can verify whether the characteristic has been parameterized according to the setting specifications. However, this method doesn’t validate that the characteristic matches the power transformer and current transformers (CT) used for the specific application. In many cases, the test quantities applied are not even realistic fault conditions.

A system-based test approach can complement traditional tests by providing the important validation. The idea is simple: if we want to make sure that the relay trips for an internal fault, we just simulate an internal fault to test the response of the relay. If we want to make sure the relay is secure against tripping for through faults, we just simulate through faults and verify the relay does not operate. Thus, a system-based testing solution calculates the testing quantities within a sub-transient power system simulation, directly outputs the signals with an amplifier, measures the response, and assesses the result.

This paper will explain both test approaches and compare them with a focus on the validation of challenging power system conditions. We will share some real-world cases of CT saturation and how the resulting issues were discovered during a system-based test. In the second part, we will describe how system-based testing can be used for modern protection functions such as inrush detection with waveform analysis (e.g., dwell detection) even in the field. We will share test results showing the behavior during inrush, sympathetic inrush, and faults during inrush of such algorithms. A traditional test method consisting of a fundamental waveform and second harmonic would not be sufficient for testing these sophisticated algorithms. Last, we will share how insufficient testing, due to the complexity of traditional testing approaches, can lead to misoperations of restricted earth fault (REF) protection and how we can improve this. Further, we will share a case study and utility findings when performing system-based testing, where the sensitivity of the REF protection did not meet their expectation.

Put Love into your SCL files - The Positive Return will follow

Fred Steinhauser – OMICRON electronics GmbH, Austria

The engineering was always a decisive task for the realization of a substation project, even in the days before IEC 61850 was deployed. Back then, the engineering could often build on already existing projects and the tasks were often not made explicitly visible.

With IEC 61850, the engineering became the fulcrum for designing, building, commissioning, and operating a substation. This was implemented by the definition of the System Configuration Language (SCL), a standardized, machine readable format for IEC 61850 configuration data. The presence of the SCL and its support by the compliant products of all vendors is the basis for an engineering process that integrates multi-vendor systems.

The presentation points out where in the lifecycle of an IEC 61850 project SCL data are created and used and what are the crucial elements to provide the basis for efficient work with modern tools.

Advanced Testing for Optimal Efficiency

Frederic Dunet – OMICRON electronics France SARL

Sharing Experience of IEC 61850 Substation in Operation

Diptiman Yadav – Jemena