Abstracts 2014

By: Alexander Apostolov – PACWorld, USA 

IEC 61850 based protection, automation and control systems with different levels of implementation are currently used in thousands of substations around the world. However there are still many protection specialists that are not comfortable with using this communications based technology for protection applications.

The goal of this paper is to highlight the key principles behind the GOOSE messages and based on this understanding to answer the question in the title of the paper.

The paper focuses on several key to the protection specialist issues that are critical for the protection of the electric power system:

• Performance
• Flexibility
• Efficiency
• Reliability and availability

Each of the above issues is covered based on the detailed analysis of the requirements of distributed protection schemes and the comparison between the IEC 61850 GOOSE implementation and the traditional hard-wired protection scheme implementation.

One of the key parameters is the transfer time of signals between protection function elements in multifunctional IEDs working together in a protection scheme. The factors affecting the transfer time in GOOSE based and hard-wired schemes are analyzed.

The requirements for adaptation of protection schemes to the changing electric power system, especially with the penetration of distributed energy resources, require flexibility that is much easier to achieve using GOOSE instead of hard-wired interfaces.

Different efficiency criteria are considered and it is shown that they can be met much easier using GOOSE messages.

The principles of GOOSE communications and the use of advanced methods such as PRP are described and it is shown how they can improve the availability and reliability of protection schemes compared to the conventional hard-wired solutions.

By: Yang Lu – Siemens Ltd., Australia and Kevin Hackart – Present Group

IEC 61850 substation automation protocol applications have been emerging in Australian Power System industry.  Through the past 12 years of experience since the IEC 61850 standard was published, the communication protocols, data models and engineering principles have been well defined. Vendor’s product conformance testing is defined in IEC 61850-10, whilst high level system testing principles have been defined in IEC 61850-4 “System and project management”.  However, due to the variability of schemes, the standard does not include well defined practical functional testing procedures. CIGRE Technical Brochure 401 “Functional Testing of IEC 61850 Based Systems” provides some high level concepts associated with system testing, there is much detail associated with these requirements.

This paper focus on two of the main station bus functions of IEC 61850 communication protocol, i.e. peer to peer inter-IEDs communication through IEC 61850 Publisher-Subscriber GOOSE and Client-Server reporting through IEC 61850 MMS. This paper shares the recent experience of testing a large IEC 61850 system, including a number of tests, validations and associated troubleshooting techniques to meet the system’s functional requirements. These tests include:

• Multi-vendor IED compatibility test
• IEC 61850 Multi-vendor SCL file exchange register validation
• IED firmware and communication module firmware validation
• Layer 2 network completeness and healthiness validation
• Cause and affect matrix testing for GOOSE functions
• Dataset healthiness verification
• Client-Server reporting validation test

This paper then further explore the option to apply practical testing techniques such as:

• GOOSE isolation
• Layer 2 network performance
• Integration of IEC 61850 testing utilizing protection relays testing device

By: Graeme Heggie – ElectraNet

Protection relays are increasingly complex and systems for controlling protection settings and protection testing have been slow to be updated, this has resulted in a number of setting errors going undetected through installation and commissioning. Once these errors are detected – possibly as the result of an unexpected operation – a protection setting change is required. In the past such setting changes would have required personnel to be present on site to apply the change. However now, due to numerical relays communication facilities it is possible to remotely access devices and apply changes from the office, particularly useful and efficient when substations are many hundreds of kilometres away.

This paper will describe our experience of remote setting changes and processes used to control these changes etc.

By: Alexander Apostolov – PACWorld 

The wide spread development and implementation of IEC 61850 based substation protection, automation and control systems is raising a lot of issues related to the testing of devices and systems based on the standard. The main reason is the replacement of the hardwired interfaces between the protection IEDs that work together in different protection, automation and control schemes with communications messages.

The specialists involved in the testing of such schemes are used to a physical isolation of the test object based on the use of test switches that allow, on one hand to open the circuit that trips the breaker and at the same time to replace the analog signals from the secondary of the current and voltage transformers with signals coming from the test equipment.

The replacement of part or all of the hardwired interfaces with communication links requires the development and implementation of methods and tools that maintain the same level of security during the testing process, while at the same time take advantage of all the benefits that IEC 61850 provides.

The paper first introduces the principle requirement for isolation of IEDs from the point of view of the different types of tests.

The second half of the paper describes the features in Edition 2 of IEC 61850 that can be used for virtual isolation.

The last part of the paper discusses the tools that can be used to perform the testing based on the IEC 61850 Ed. 2 definitions and how they meet the requirements for virtual isolation from a practical point of view.

By: Shantanu Kumar, Narottam Das and Syed Islam – Curtin University

Due to increased application of digital equipment in modern substations, utilities and industries are leaning towards IEC 61850 for substation automation, control and protection.  This paper discusses the impact of sympathetic tripping on a healthy 22 kV feeder and its mitigation based on the IEC 61850 protocol.  A typical 132/22 kV zone substation is discussed in the study and illustrated in detail.

Sympathetic tripping is caused due to a high load conditions which is deemed by the intelligent electronic devices (IED’s) to be an out of section fault. This results in unnecessary tripping of the 22 kV circuit breaker by the IEDs.  The occurrence of out section fault could be attributed to an unbalanced load in the distribution feeder due to delayed voltage recovery condition.  The impact of which could lead to spurious tripping of the healthy feeder load in the vicinity.  Furthermore, when the supply is restored after a prolonged outage and with the rotating equipment in switched-on condition, the current in the circuit could exceed the normal feeder current by 6-7 times, creating an inrush situation.

The paper proposes a method to mitigate the sympathetic tripping based on an IEC 61850 by comparing high speed peer-to-peer GOOSE (Generic Object Oriented Substation Event) messages between the IED’s at process and substation bus level.  

By: Chirag Mistry; Sankara Subramanian; Krishnakumar Venkataraman – Alstom Grid

High impedance fault (HIF) exposes great hazard for personal safety and property security. High impedance fault (HIF) in MV distribution with restricted fault current cannot be detected and cleared by conventional over current relays. In this paper, an integrated scheme utilizing different features of HIF is presented. Various documented field data has been investigated and summarized to get the most distinctive features of HIF. Based on these features, a simulation model using arc thermal equation and random factor has been developed. The integrated scheme investigates into different scopes of the fault features ranging from transient high frequency, harmonic distortion to fundamental intermittent. EMTP (Electromagnetic Transients Program) simulation results show that the integrated scheme can detect most HIFs and discriminate HIF from other interference scenarios such as CT saturation, load nonlinearity and capacity transients. Therefore, this scheme achieves a better result with reliability and security.

By: Michael Buckeridge – Ergon Energy

Ergon has developed sophisticated commissioning systems and tools that provide a consistent and safe commissioning outcome. 

The Ergon Commissioning System covers the five phases of the commissioning process Factory Acceptance Testing (FAT), Site Acceptance Testing (SAT), Site Integration Testing (SIT), Pre-Energisation Testing and Post-Energisation Testing.

At the heart of the Ergon Commissioning process are a set of Excel based tools that encapsulate the engineering judgment behind the commissioning process.  The tools mandate the commissioning tests and acceptable results required to enable the plant to be energised based on cost, the risk to people, plant and the system.  The test technician enters the test data directly into the test sheets in the tools and this enables the test results to be verified against the Ergon Maintenance Acceptance Criteria (MAC) which in turn gives the technician an immediate on site pass fail response.  

Entering the test data directly into the test tools makes the results legible, allows the results to be stored easily and in the future the data can be imported into the Ergon Plant Data Base for trending of plant performance.

Ergon has contracts with a number of collaborative partners who work with Ergon to accomplish Ergon’s capital works program.  The commissioning system and tools produce a repeatable and consistent outcome independent of the company completing the commissioning work.

By:  Apichat Angsuwan – Electricity Generating Authority of Thailand (EGAT)

Transmission systems have many types of bus arrangement but selection of a particular type depends upon the system voltage, position of substation in electrical power system, flexibility needed in system and cost. Double bus single Breaker is a bus arrangement which uses many isolators to select the zone of protection for each bay. Protection can be programmed via logic functions and set to required criteria, relay testing equipment also has improved to be able to test relay’s complicated functions more quickly and accurately.

Bus differential relay is a main focus of bus protection. To confirm that it functions accurately, it needed to be tested prior to interface to the system. This paper will discuss the performance of testing equipment used for commissioning and test of bus differential relay in several conditions according to EGAT’s criteria, circuit breaker and power system. 

By: Alexander Apostolov – PACWorld 

The requirements for improvements in the efficiency and quality of protection schemes at the transmission and distribution level of the electric power systems highlights the need for development of new methods and tools that can help the industry achieve these goals.  That is why it is very important to start a discussion on the opportunities that exist to develop a set of engineering tools based on the development and experience with the use of utility standards and the IEC 61850 substation configuration language.

The new IEC 61850 international standard for substation and power system communications is not just defining a new protocol, but also introducing abstract models of primary and secondary substation equipment, communications systems and the relationship between all of them. It also defines an XML based format for the description of the above in a standard way that can be used at different stages of the engineering process based on an object oriented approach.

At the same time CIGRE WG B5.27 produced a four step standardization process, which combined with the IEC 61850 modeling and substation configuration language can be used to significantly improve the engineering process from substation protection, automation and control systems.

By: M.Ghezelayagh, Transend     

A significant number of techniques have been developed and applied for detection of islanding for distributed generators (DG) on distribution networks. The types of distributed generators which have been considered are mainly renewable energy resources such as solar/ photovoltaic systems. The common anti-islanding techniques which have been used for DG systems have been mainly classified as Passive and Active network which includes the followings: 

1. Utilizing frequency and voltage based relays, harmonic detection technique and measurement of negative sequence component of voltage (Passive (Passive)
2. Using signal generators and detectors schemes (Active)

Few publications exist to elaborate about the detection of islanding in EHV transmission network (TG). The characteristic of islanding in DG network as compared with TG network differs with respect to followings:

1. In DG network many distributed generators are connected to a single distribution feeder while in TG network mostly a single large power station remain connected to a portion of a transmission network after isolation from main grid.
2. The variation in frequency, phase angle and voltage of a TG network after islanding is different from DG due to system inertia of the islanded network and characteristics of the generation.
3. The generation in TG network can be a large wind farm  or synchronous  generators while for DG  it is mostly solar photos or mini  generators

In this document practical anti-islanding schemes for TG networks are discussed.  It is envisaged whether the passive and active methods which have been applied widely for detection of anti-islanding in DG system are also applicable to TG systems. In addition Specific techniques which are mostly applicable to TG network are discussed.  These are as follows:

• Synchro-phasor
• Communication based methods
• SCADA script calculation methods
• Signal generator and detector schemes

The advantages and disadvantage of each method with respect to reliability, security and cost is described. For this purpose anti-islanding schemes of four real TG systems are described. The operational field experiences of each scheme are given and recommendations for selection of the best scheme based on particularity of TG network are made.

As back up for anti- islanding detection scheme, frequency and voltage elements of the main numerical protection and control devices of transmission lines and generators are proposed to be utilized instead of dedicated relays as in DG networks.  The required system studies for appropriate setting of these elements based on consideration of operational tolerances of primary equipment particularly generators under abnormal system frequency and voltage are discussed.

Finally, although there are significant numbers of standards for DG systems but there is none for TG systems. Consequently the requirement of standard and National Electricity Rules for anti- islanding scheme for TG system is discussed.  Future TG standard should address the required number of schemes, permissible time and the level of abnormal system voltage and frequency for operation under islanding and the required pre-commissioning and commissioning testing of the schemes. Development of such a standard will help the electricity companies to reduce the cost of provision of these requirement based on each individual case.

By: Usman Mahmood – Energy Australia and Sy Bui – Aurecon

Protection systems are an essential and critical part of any power network. The failure of a protection system when required to operate can have cascading detrimental effects, resulting in a loss of supply to other healthy parts of the network. On the other hand, a protection mal-operation can cause unintended loss of production and revenue. It is essential to devise a protection testing regime to suit the plant operating conditions, equipment ages and conditions, operational history and regulatory requirements.

A typical protection system consists of four main key components: measuring devices such as current and voltage transformers, processing devices such as protection relays, external auxiliary devices such as Buchholz, temperature devices and interrupting devices such as multi-trip relays. Each of these key components as well as the overall protection system requires different testing methods to verify that its operation matches with its intended operating characteristics. Some of these tests are normally carried out at the time of commissioning; others are usually done on regular basis, at minor or major maintenance periods, to ensure ongoing performance of the system as part of compliance requirements of the National Electricity Rules (NER) and connection agreements.

Electromechanical relays are proven to be reliable in the past but required periodic testings to adjust for possible drifts in the pick-up and operating time of electro-mechanical components. With the advance of multi-function digital protection relays, these drifting issues are no longer a concern. However, the digital protection relays can be mal-operated due to the electromagnetic and harmonic interferences and algorithm’ “lock-out” problems.    Conventional testing methods may not be suitable for testing digital protection relays, and there is a need to perform additional tests in order to identify possible failure modes. 

This paper presents an overview of the current practice of protection testing at thermal power stations in New South Wales. This paper also discusses the key issues to be considered when formulating a protection testing regime. 

By: Christopher Pritchard and Thomas Hensler – OMICRON Electronics Austria

Test and verification of a busbar protection for complex busbar topologies with multiple busbars, couplers, bays and feeders has always been one of the most challenging tasks for commissioning. A single test device injecting currents at only a single CT location does not provide enough confidence for the correct operation of the protection. Using a simulation based approach, where the whole busbar topology with all its switch configurations is modelled within a test software, offers new possibilities for all the fault scenarios, which are important to verify, such as faults inside and outside the protected area or even faults in “dead zones” of the protection between a CB and its corresponding CTs. With a test software that can react to the individual CB trips with an iterative closed-loop simulation, the real behaviour of the busbar protection including breaker failure functions can be seen. This can be achieved with multiple GPS time-synchronized test devices.

By: Lee Westphalen – Electranet

Device configuration management of an ever increasing number of critical substation intelligent electronic devices is crucial.  Issues such as network security, network reliability, fault management and restoration processes are all reliant upon current and correct configuration information available with high level of accuracy.  

Access to accurate, current intelligent plant configuration information will contribute to faster, more reliable fault analysis and subsequent restoration, and will enhance operational processes to better manage network operations and performance.

This paper discusses the process development, cultural behaviour requirements and application software required to manage such complex configuration

By: Terry Foxcroft – Snowy Hydro

The 330 kV busbar topology at Upper Tumut Switching Station is two bus sections with a reserve or hospital bus. There are eight feeders at Upper Tumut switching Station, connecting Tumut 1 and Tumut 2 Power Stations to Canberra, Yass, Khancoban and Talbingo.

The power stations have two generators per transformer and line, with generator circuit breakers between the generator and transformer. The transformers are left de-energised when there is no generation. The first unit on a transformer must close on and run up to the 330 kV switchyard and synchronise.

The selection of which bus to synchronise is determined by disconnector positions. Also, and circuit breaker may be bypassed and the bus section of bus coupler circuit breaker used in its place.

This results in an extremely complex synchronising scenario.

This paper describes the function of the switchyard synchronising circuits, some of the different operating functions and the complex synchronising solution required to perform all the functions with maximum system flexibility. It describes the use of line directional protection relays reprogrammed to perform synchronising functions, and the design to remove the need for auxiliary selection relays.

By: Christopher Pritchard and Thomas Hensler – OMICRON Electronics Austria

Most of the overhead lines in our transmission systems today are operated as parallel lines with two 3-phase systems. During operation of such parallel lines the mutual coupling between the lines has a considerable impact on the measured fault impedance for single-phase-to-ground faults. Using new test software it is possible to analyse this impact for the different fault scenarios and the behaviour of the protection devices precisely using a transient network simulation. Different vendors of protection devices offer different possibilities and settings to cope with mutual coupling, which should be compared. Finally some considerations about real line configurations with mutual coupling are made and concepts for protection design with a good selectivity are discussed.

By: Graeme Heggie – ElectraNet

A follow up from a paper presented last year that signalled AERs intention to collect data regarding the incorrect operation of protection. This paper will discuss how ElectraNet interprets this requirement, giving an insight into the fault investigation process, use of fault recordings, event records etc. The paper will also discuss some protection operations that will be of interest to all (including use of a paper presented in the 2013 APS) – touching on root causes and corrective actions.

Provincial Electricity Authority (PEA) has experienced with 4 manufacturers of arc detection system, protecting over a number of units of 22 kV Metal-Clad Switchgear. PEA adopted the first arc detection system in 19xx. Since then till now, the main problem is verifying the product specification by acceptance testing, especially for tripping time of the system because of a lack of test tools. In 2013, we use a prototype of an arc flash initiator to study and design of acceptance testing process. The results give us valuable information on acceptance testing problem, the test tool problem and some criteria should be specified in the specification.

By: Dean Richards – Protection & Control Services LLC and Dustin Tessier – Tesco Group

The intent of this paper is three-fold: first to provide a brief overview of IEC 61850 and its value-added features; second to discuss the various IEC 61850 use cases found within the industrial and power utility domains; and finally to provide design considerations that identify areas of overlap where common practices ought to be taken.

Despite the popular belief that the “power” domain and “industrial” domain have intrinsically unique principles, this paper suggests the gap is decreasing, and through the use of IEC 61850 we can adopt a single strategy that capitalizes on a common technology platform.  This will ultimately streamline the specification, design and commissioning processes for power and industrial users alike.  This will minimize the overhead by eliminating the need to build two sets of infrastructure in parallel, and provides greater reliability by avoiding common points of failure such as gateways, protocol converters, etc. IEC 61850 still provides users the flexibility to address the challenges found within each domain, which is indeed unique.

By: Ezekiel Madzikanda – ZINFRA GROUP

As Distributed Generation gains popularity in Australia, particularly in Tasmania a number of safety issues need to be considered. We recently designed a distributed generation scheme where anti-islanding was a condition for connecting the DG to the network. There are a number of islanding techniques available, communication based and locally built-in detection schemes. These schemes have their own advantages and disadvantages. There is another technique that is gaining popularity in distribution networks owing to its simplicity of application. This technique is based on voltage distortion and uses the distribution line for sending the signal to the DG. This type of signal implementation is not new; it has been used for a decade in wire communications. A signal generator is installed at the point of connection and generates a signal to the DG where a signal detector is installed. The signal generator will continuously generate signals on the distribution line. The signal is optimized so that it does not interfere with normal system operation. This carrier line signal will propagate down the distribution power line. The signal pattern is not repeatable in nature. A signal is one pulse every 4th cycle. It then looks for 4 of these pulses in a row to be missing; a representation of an Islanding condition .The signals are obtained by subtracting two cycles of voltage waveform where one cycle contains the voltage sag and the other does not. The result of the subtraction is the voltage signal. The paper discusses the issues that were experienced during commissioning of this scheme and other anti-islanding techniques explored.