Northern Ireland Electricity Finds Map to Modernity

Managing the delivery of electric power to more than a half million customers is no easy task-particularly when the utility delivering that power keeps its facility records spread out over thousands of aging paper maps.

That was the situation Northern Ireland Electricity (NIE) faced as little as two years ago. But since kicking off a large-scale GIS implementation in May 1998, the utility has transformed its mapping and asset management process from archaic to cutting-edge. Initial reviews of the new GIS have been positive, and NIE is already looking at ways to derive future business benefits from the modern mapping system.

NIE is responsible for the transmission and distribution of electricity to more than 680,000 customers in an 8,680-square-mile service territory. The utility’s distribution system is made up of more than 32,500 miles of circuit, and NIE operates 63,900 substations. Prior to the recent GIS implementation, NIE’s thousands of maps containing all of the utility’s asset information were maintained centrally in the geographic records section of the utility’s Belfast headquarters; the master records were held on plastic velographs or linen. It was an inefficient system, and one that was growing less efficient by the day.

“Some of the maps were more than 30 years old and in various stages of deterioration,” said Craig Mitchell, NIE’s deputy project manager. “Sixty percent were on a system called the county series with the remainder on the Irish grid system. All of the maps needed to be on the Irish grid, so a decision was made to move it all to one system.”

At that point, NIE officials had a choice: transfer the utility’s aging maps to an enhanced manual system or move to a digitized single-map record. NIE opted for a modern, computerized GIS and began an evaluation process.

“We spent about a year to a year and a half doing site visits over in the states and in Great Britain, talking to other utilities that had been doing GIS work,” Mitchell said. “We had a fairly extensive look around to see what others were doing and what were the best solutions.”

Besides consulting other utilities, NIE had its own GIS experience to draw upon, although the utility’s previous attempt at modern mapping and facilities management was not successful. “A few years previously, we had tried another company’s GIS solution, but we mutually agreed to separate about a year into the project,” said Mitchell. Part of the reason NIE pulled out of that previous implementation had to do with cost. “We weren’t going to get the system we wanted at the cost they (the supplier) had signed on for,” said Mitchell.

Having learned from its previous GIS experience and the experiences of others, NIE was prepared to bring its mapping system into the computer age. During their evaluation of systems at other utilities, NIE officials were impressed by the Autodesk VISION system in use at Yorkshire Electricity. In the end, NIE would work with Autodesk to build a customized solution based on VISION. NIE named its customized solution the Geographic Network Information System, or GNIS. The implementation project kicked off in May 1998 and was completed in December 1999.

With the complete system in place for less than a year now, NIE has already nearly finished conversion of its overhead network. While not quite as far along with the conversion of its underground network records, Mitchell said the rest of the conversion should be completed in a few months.

Even at this early stage, Mitchell said NIE is experiencing marked improvements in mapping efficiency. One of the GNIS system’s more immediately evident advantages is the ease with which NIE can fulfill requests for system information. “Before, when someone asked where one of our plants was, we had to go find the hard-copy map, make a photocopy of it, mark it up and send it out,” Mitchell said. “That would have taken maybe 15 or 20 minutes to do each of those. Now we can do 20 or 30 of those in the same amount of time.”

Mitchell also said that with the immediate, updated locational information provided by the single map record and the ease with which utility employees can navigate the map, NIE will be able to respond much more quickly and accurately to a power failure or other crisis. NIE has made it easier for its employees to access the valuable information in GNIS by making it available via the corporate intranet. Using the intranet, employees are able to pull up mapping information on their desktop PCs-an ability not afforded by the previous paper-based system. In the future, the utility hopes to make its maps available on an extranet, giving certain outside entities the ability to retrieve NIE’s facilities information.

NIE also has taken steps to make the power of GNIS available to its mobile work force. GNISView, a GNIS spin-off that NIE requested partway through the implementation, makes data available immediately to mobile workers via laptop computers. Currently, GNISView is being used by the teams that inspect overhead power lines from helicopters. Using GNISView in conjunction with GPS, the helicopter crew can identify their exact location and pan along on the map while flying.

NIE’s next task will be to integrate GNIS into its other corporate systems-an undertaking Mitchell said should be relatively trouble-free because of the way Autodesk built the GNIS solution. “One of our reasons for choosing the Autodesk product was its Oracle nature,” he said. “Everything is stored in Oracle, including the maps. Most of our corporate data is also stored in Oracle, so we felt the links between systems would be much simpler to build.”

SCADA System Helps Utility Meet Needs of Changing Industry

Changes in electric utility business environments mean that power distribution systems must respond quicker and be more efficient. To make operations as efficient and cost effective as possible, public and private utilities alike are focusing on programmable logic controller-(PLC-) based supervisory and data acquisition (SCADA) systems.

One such system was recently commissioned by Public Utility District no. 1 of Klickitat County (KPUD) in Goldendale, Wash. KPUD’s SCADA system is an excellent power management tool enabling better response to changing load. In addition, the system provides quicker notification of substation alarms allowing for fast response or repair.

KPUD Background

KPUD provides electric, water and sewer services to 10,000-plus customers within the county, spread across approximately 1,500 square miles, averaging fewer than six customers per pole mile. KPUD’s electrical power system includes 15 substations (eight of the 15 are points of delivery) containing equipment of various vintages ranging from 1940s to 1980s. KPUD owns 50 percent interest in a 10 MW hydroelectric plant on the McNary Dam, as well as a 50 percent of a 10 MW methane gas generation facility. In 1997, KPUD contracted with Chelan PUD, Wenatchee, Wash., to manage its power acquisition.

KPUD realized that Chelan PUD would need to monitor KPUD loads and resources on a real-time basis in order to make purchasing decisions. KPUD’s current system did not have the data collecting capabilities required to address this need, having only standard metering devices. To remove these deficiencies, KPUD undertook a capital project to implement SCADA county-wide for their power system.

KPUD prepared a complete specification for the SCADA system based on the following goals:

  • Real-time data collection (four second update),
  • Remote metering of real-time demand and hourly power usage,
  • Fail-safe, robust, easily upgradable, long-term operation able to grow with the utility,
  • Established equipment manufacturer and support network, and
  • Timely and cost-effective implementation.

Using this specification, KPUD conducted an extensive search and evaluation of SCADA system equipment providers and integrators. Proposed systems ranged from traditional RTUs to custom hardware and software. PLC-based systems from all the major manufacturers were represented among the proposals. KPUD wanted a PLC-based system since it would be software upgradeable and has been an industrial standard for many years. After carefully evaluating each proposal, KPUD chose Programmable Control Services Inc. (PCS), an Allen-Bradley authorized control systems integrator.

The PLC-based SCADA System

PCS provided KPUD with a complete SCADA system using Rockwell software and Allen-Bradley equipment. The system consists of SLC 5/03 PLCs and PowerMonitor IIs at each of the 15 substations, and a master PLC (SLC 5/04) with an interface to a Windows NT PC running RSView32 as the primary operator interface application.

The master PLC gathers load data from all the substations on a polled by exception basis via radio modem link to each substation PLC, or by backup telephone modem link in the event of radio communications failure. ESTeem radio modems are used because they provide a preferred connection to Allen-Bradley architecture. A Microsoft Visual Basic program that receives and transmits data through Rockwell Software’s RSLINX DDE server facilitates the backup telephone modem link.

Real-time Data

The RSView32 logs the load data from all point of delivery substations to a file that Chelan PUD accesses at regular intervals. A Basic module in the master PLC has been programmed to provide a modem interface that will transfer data directly from the master PLC to Chelan PUD at a four-second update rate. Chelan PUD is planning to use this interface at a future date.

Power System at a Glance

The RSView32 application displays current process data, which is also logged to a disk and/or printer. Alarms include items like over/under voltage, over/under current and equipment condition, such as transformer over-temperature or regulator position. The system can page operations personnel in the event of an alarm, and a touch tone telephone interface is available for operator retrieval/acknowledgement of alarms and remote system operation.

Remote Operation

The RSView32 operator interface terminal provides an interface for KPUD to operate equipment at substations as far away as 70 miles. This functionality includes operation of reclosers, and remote voltage reduction to avoid demand levels.

SCADA Allows for Process Improvements

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Since the April 1998 system commissioning, the SCADA system has helped KPUD learn about its process. For example, the SCADA system provided KVAR profile data at the Bingen substation indicating the load was lagging during the week and leading on the weekends. Further investigation determined that an industrial customer with a highly inductive load did not have enough capacitor banks to compensate and was leaving the banks online on the weekend when inductive load was offline. KPUD used the profile data to calculate the needed capacitor banks’ size and is currently installing the banks to compensate for weekday load. KPUD is also working with the customer to coordinate its capacitor banks for the weekend load. “While we knew power factor correction was required, we did not have the data to properly correct the problem,” said Jim Smith, a KPUD system engineer. “Without the SCADA system we may never have seen this opportunity.”

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