Queensland regional electricity distributor Ergon Energy has improved network reliability and is future-proofing its network. Deploying SCADA is helping achieve results.
Ergon has a Network 2030 Vision to enhance real-time monitoring and control of its systems in order to respond to events, as well as deliver a self-healing network that automatically identifies, isolates and responds to system disturbances and faults.
Two initiatives making this happen are part a company-wide reliability improvement program and includes Supervisory Control and Data Acquisition, or SCADA, and an all-encompassing or ‘ubiquitous’ telecommunications network called Ubinet – that today links 40 depots and 90 substations.
Ubinet uses both Ergon’s and other parties’ infrastructure to maximise the efficiency of investment. These parties include Powerlink, Queensland Rail, Nextger and commercial carriers where suitable. Building the Ubinet network involved the construction and installation of more than 55 telecommunication shelters, 73 communication poles, and 33 telecommunication towers and masts around the state.
The first of the Ubinet implementation was completed in late 2012. The second phase, which involves the replacement of analogue two-way radio network with a P25 digital radio system integrating voice, GPS and Telemetry Data capability, is expected to be complete by 2020.
By August 2013 Ergon’s SCADA system was providing monitoring and supervisory control for 729 distribution re-closers and more than 400 of its 500 zone substations. SCADA is now present in 86 per cent of Ergon’s substations and covers 93 per cent of feeders on the network. Operational Control Centres in Townsville and Rockhampton monitor the system of Local Control Facilities (LCFs) within the substations and a centralised master station.
Presently the standard Remote Terminal Unit (RTU) is the Invensys (Foxboro) SCD5200 (C52). The C52 has been used by Ergon Energy since 2004 and accounts for 66 per cent (522/789) of RTUs in service. There are a wide variety of RTUs, installed prior to 2004, which have limited or no intelligent capabilities. Hardwired input alarms are sent to, and output controls received from, the control centre. In addition to hardwired inputs and outputs, the C52 RTU communicates to Intelligent Electronic Devices (IEDs) performs automated control routines and provides the interface to the master station and the LCFs.
There are several automated substation business-as-usual routines performed within the SCADA system. These are done as calculations within the RTU and are based on standard designs and customised for the site where applicable. Ergon uses standard designs for Automatic Voltage Regulation (AVR) and Capacitor Automatic Control in addition to several site specific routines used for Load Shedding, Plant Overload Protection, Auto Close, Auto Reclose, and SVC control.
A Distribution Management System (DMS) is the foundation information and decision support system for the deployment of intelligence in the distribution network. As part of its desire to reduce upward pressure on prices by reducing operational expenditure while increasing reliability standards, Ergon is currently evaluating tenders for purchase of a DMS solution which would herald increased automation and support for new technologies. Besides efficiency, a suitable DMS will also improve business continuity, enable a smarter network, allow the company to improve quality of supply, improve safety outcomes and enhance Ergon Energy’s customer interaction.
Deployment of a DMS application package will involve change within the operational sphere, coupled with extensive data cleansing and capture. This will be the first stage of an ongoing DMS installation strategy to progress Ergon on the Smart Grid path, which will require communication with as many distribution devices as necessary in order to obtain the most complete picture of the network in real time. In addition to the devices that are currently being monitored by the existing SCADA system, this includes the deployment of and communications to line fault indicators, intelligent grid monitors, sectionalisers (and other switching devices), voltage regulators, capacitors, embedded energy resources, distribution substations and potentially other distribution equipment.
Having Ubinet as an ubiquitous telecommunications network has enabled Ergon to meet its core network performance targets, protect electricity assets, enhance community safety, and significantly reduce reliance on commercial carriers. Other benefits from the initiative include rapid identification of power network faults (meaning faster restoration to customers when faults occur) efficient and accurate monitoring and control of Queensland’s power grid, and enablement of an independent telecommunications network that can be used in disaster response situations when commercial carrier networks may be congested or damaged.
Customers in regional Queensland are now enjoying the benefits of increased network investment over the past decade with dramatic improvements in both the frequency and duration of power supply interruptions. Outages across the network declined by 37 per cent between 2005-06 and 2012-13 with the average amount of time customers spent without power falling 36 per cent.
On average, Ergon’s customers experienced 2.8 outages a year, lasting 5.7 hours in total. This was equivalent to customers having power supply available 99.935 per cent of the time in the year. Customers experienced, on average, 4.5 hours of unplanned outages and 1.28 hours of planned outages during 2012-13.
These reliability improvements reflect the significant investment and priority Ergon Energy has placed into improving customer service and achieving the Minimum Service Standards in line with its regulatory requirements.
Chief Executive Ian McLeod said Ergon Energy had introduced a range of programs since 2004-05 to improve reliability in response to the findings of the first Somerville inquiry.
In addition to the SCADA program, other measures include:
• A significantly increased vegetation management program that removes trees or branches within specified corridors around power lines. This is being further enhanced and delivered more cost effectively though the use of 3D aerial data capture and virtual modelling technology (ROAMES) to monitor vegetation clearances from power lines.
• Regular asset inspection cycles to identify equipment at risk of failing and then replacing or repairing it before an unplanned outage occurs.
• Greater redundancy in the network, especially for supplying larger population centres. In some locations, this means a substation can maintain supply to customers if one of its transformers is out of operation, or that a key high-voltage power line may be duplicated.
• Greater co-ordination and packaging of works to maximise outcomes during planned outages.
• Increased use of generators for planned outages and disaster response.
• Augmenting the capacity of the network to cope with peak loads without shedding customers on the hottest and coldest days of the year.
• Increased number of switches and ties on the network, enabling smaller sections of the network to be isolated for repairs while power is maintained or reinstated to most customers from another feeder line.
• Detailed storm and cyclone season preparations, covering both preventative maintenance and staff planning for various disaster scenarios.
• Using weather forecasting services to predict storm activity and prepare additional resources to respond to faults.
• Refurbishment and replacement of aged assets.
Mr McLeod said these investments had produced tangible benefits demanded by customers and regulators from a reliability perspective.
However, he also said that the level of investment was unsustainable in an environment where demand and consumption were contracting and customers were substituting some of their energy needs through other means, such as solar PVs.
Also, further increased spending across the board would not deliver the same degree of improvement as in the past.
“We also acknowledge that this increased investment over the past eight years has been among the factors contributing to higher electricity prices,” he said.
“Our customers are telling us they are now generally satisfied with reliability levels and are more concerned about affordability.
“While we will continue to invest in the network where prudent to improve reliability and efficiency, it will be carefully targeted to ensure greater productivity per unit of energy.
“We are now focused very much on our worst performing feeders, often the long SWER (Single Wire Earth Return) lines in rural areas, and looking for cost-effective ways of improving reliability and quality of supply for those customers.
“For a number of years, we have been trialling battery systems to support peak load and maintain supply quality and this has proven successful.
“The outcome is a broader roll out of this technology and greater savings on the traditional infrastructure solutions.
“For the majority of our customers though, our goal is to maintain their existing standards of reliability, while restraining our overall expenditure so the network component of prices rises from 2015-16 is below the rate of inflation.”
About Ergon Energy
Ergon is a Queensland Government-owned corporation which supplies electricity to around 710,000 customers across an operating area of more than one million square kilometres – around 97% of the state of Queensland – from the expanding coastal and rural population centres to remote communities of outback Queensland and the Torres Strait.
Ergon Energy’s electricity network consists of approximately 160,000km of powerlines and one million power poles, along with associated infrastructure such as major substations and power transformers. The company owns and operates 33 stand-alone power stations that provide supply to isolated communities across Queensland which are not connected to the main electricity grid. Since August 2007, Ergon Energy has owned and operated the Barcaldine gas-fired power station along with its associated infrastructure, which supplies power to the main grid. Ergon Energy has around 4,600 employees and an $11.5 billion asset base.