UNC Breaks Ground on Underground Distribution Project
Projecting growth of their primary load base to increase by 5.9 million square feet of educational facility over the next decade throughout their 700-acre campus, University of North Carolina facility managers initiated a study in 2001 to improve system reliability as well as meet increased load.
Four years later they are breaking ground on a multi-million-dollar underground distribution system (UDS) expansion, the design for which is derived from transmission line protection and system grid coordination concepts. Similar concepts were employed in two of the largest automated switching projects in recent history: International Drive in Orlando and Lake Pontchartrain, near New Orleans.
Functioning much like a municipal utility, the university purchases bulk power on the open market and distributes it to more than 1,000 customers on its campus as well as the city and county. System planners are especially sensitive to reliability concerns. UNC has managed its power distribution since 1895.
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UNC’s facility supervisor Pat Andrews has overseen the project from the fact-finding stage and will continue to monitor construction progress. Andrews states he was influenced in his decision to improve customer reliability on the university’s system by an article he read in a trade journal in 2001 and the results of a metering fact-finding study completed in 2000 by Booth and Associates, Raleigh, N.C.
The Consulting Engineering firm has served the University of North Carolina for more than twenty years, according to Michael Clements, P.E. with Booth Associates, and was subsequently selected to provide electrical design services for the UDS project.
The closed loop systems envisioned will improve customer reliability in the event of a cable fault due to the ability of the high-speed relays and switches to sense and isolate a faulted cable section within six cycles. This clears the faulted area before circuit breakers open the entire circuit.
Forty high-speed SF6-insulated load break switches equipped with vacuum interrupters will be supplied by Canada Power Products Corp. They will be interconnected with a high-speed fiber optic cable network, providing the necessary communication route for the 110 Schweitzer Engineering Laboratories’ relays and redundant SCADA master station by Survalent Technology. Thirty-eight circuit breakers will provide protection for major outages.
Nine separate ductbank runs (totaling approximately 15,000 lineal feet) have been identified and prioritized for installation. The new ductbanks will be installed in accordance with UNC-CH’s standard ductbank design detail that provides conduit capacity for power, telecommunications and control circuitry. Underground cables will be upgraded to 750 MCM where ductbank capacity allows, which will greatly improve the ability of the university to switch loads as needed.
An additional capability afforded with installation of the fiber optic system is implementation of the recommendations for remote meter reading from the 2000 Metering Study (approximately 325 3-phase meters must be read). Meters will be monitored for SCADA purposes (identifying faults, etc.) and also to support the university’s EMCS and other power data programs.
Projected completion of the far-reaching project is set for end of third or start of fourth quarter, 2006. University system personnel are undertaking the switch installation and cable upgrade. à¢®à¢®
SDG&E Begins Testing Broadband Over Power Lines
San Diego Gas & Electric (SDG&E) in July unveiled details of its planned pilot test of broadband over power line (BPL) technology.
SDG&E planned to begin testing the technology Sept. 1, 2005, and will continue the pilot project for up to a year. The pilot will test a variety of BPL equipment in different geographic and demographic areas. The first phase of the pilot will take place in the San Diego neighborhood of Kearny Mesa.
“We are excited to be testing this innovative technology,” said William Reed, senior vice president of SDG&E. “If the technology is compatible with our electric facilities, it may pave the way for a host of utility functions that will benefit customers, including shorter outages.”
In the first phase, SDG&E will concentrate on testing the technology’s utility applications, including remote control of utility equipment; instant, accurate status reports about grid conditions; and compatibility with advanced metering infrastructure, a technology capable of automating the measurement of customer energy usage.
If BPL is compatible with the SDG&E electric grid, it has the potential to enable broadband Internet service at nearly every electrical outlet.à¢®à¢®
Deadline Approaching for 2005 Projects of the Year Awards
The Nov. 14, 2005, deadline is fast approaching for the third annual Utility Automation & Engineering T&D Projects of the Year Awards.
The awards program is designed to honor the most innovative electric power transmission and distribution technology implementations and engineering projects undertaken by North American electric utilities during the course of the last year.
Nominations are being sought in the following four categories:
“-T&D Automation Project of the Year (includes distribution automation, transmission automation, T&D management systems, substation automation, SCADA/EMS implementations, and related field devices and systems);
“-AMR Project of the Year (implementations of automatic meter reading technology, systems and equipment);
“-Geospatial Project of the Year (includes implementations of AM/FM/GIS, mobile computing, field force automation, mobile workforce management, outage management/response systems, and systems integration); and
“-Non-automated T&D Engineering Project of the Year (Includes underground and overhead transmission/distribution line construction, substation construction projects, and expansions/upgrades to existing facilities).
All utilities involved in transmission and/or distribution of electric power are eligible for the awards, including investor-owned utilities, federal power agencies, municipal utilities, and rural electric cooperatives. Also eligible are RTOs, ISOs, independent transmission companies, and other T&D-owning/operating entities.
While award winners must be utility companies or other T&D-owning entities, any interested party may submit an entry for consideration. Utilities, vendors, consultants and others are all welcome to submit nominations. One award-winning utility will be recognized in each category.
Those who wish to nominate a utility for one of the Projects of the Year Awards must submit an entry form (available upon request from firstname.lastname@example.org) and a detailed written description of the nominated project. To be eligible, projects (or significant phases of the projects) must have been completed between Oct. 16, 2004, and Nov. 1, 2005.
Deadline for entries is Nov. 14, 2005.
Award winners will be recognized and presented with their awards during the keynote session of DistribuTECH 2006 in Tampa, Fla., on Feb. 7.
Last year’s Projects of the Year winners were:
“- Niagara Mohawk: Automatic Meter Reading Project of the Year
“- ENMAX Power: T&D Automation Project of the Year
“- San Diego Gas & Electric: T&D Engineering Project of the Year
“- NSTAR Electric & Gas: Geospatial Technologies Project of the Year
For more information on the 2005 Projects of the Year Awards or to receive an entry form and entry requirements, contact Steve Brown at (918) 831-9579 or email@example.com.à¢®à¢®
$400 Million Transmission Project to Benefit Long Island
Neptune Regional Transmission System (RTS) has awarded Siemens Power Transmission and Distribution (PTD) a contract worth more than $200 million to construct an undersea high-voltage direct-current (HVDC) transmission link between Sayreville, N.J., and North Hempstead in Long Island, N.Y. Neptune RTS, the project developer, will make the electrical connection available to supply electrical energy from the New Jersey grid to cover increasing demand for power on Long Island. The project will be implemented by Siemens, which will engineer and supply the HVDC system, and Milan-based Pirelli Energy Cables and Systems, which will provide the 65-mile-long submarine power cable. The total contract value is in excess of $400 million. Plans are for the system to begin operation in mid-2007.
“It is critical that we develop new technologies to provide more flexibility in the transmission and distribution of our nation’s power supply,” said Dave Pacyna, president and CEO of Siemens PTD. “This system will provide the reliable, consistent and safe transmission of power from the New Jersey PJM Grid to Long Island.”
In addition to providing technological expertise, studies, and engineering services during project development, Siemens will provide the initial operation and maintenance services for the system during a five-year period.
“Neptune RTS’s mission is to develop commercially viable energy solutions for the U.S.,” said Ed Stern, president of Neptune RTS. “With energy demand increasing worldwide, high-voltage direct-current transmission will play an increasingly important role, especially as it becomes necessary to tap energy reserves whose sources are far away from the point of consumption.”
HVDC technology is used as an alternative to conventional alternating current transmission because it is the most efficient way of transporting large quantities of energy over long distances. HVDC transmission systems also are controllable, adding more flexibility and stability, limiting the effects of disturbances such as blackouts.
In addition to enabling energy purchases from New Jersey, the Neptune system will enable energy purchases from suppliers in Pennsylvania and Maryland, potentially benefiting the greater New York area.à¢®à¢®
Hawaiian Electric Implementing Direct Load Management
Hawaiian Electric Co. (HECO) is implementing a system wide direct load management program that will provide a foundation for reducing peak electrical demand and provide its customers new choices for reducing electricity costs. The company was also interested in an important feature embedded in the control devices manufactured by Cannon Technologies Inc.: line under-frequency (LUF) automatic protection.
Since HECO is an island utility with no interconnection to the national grid, the LUF protection feature built into Cannon’s load management receivers is very important to the utility. The feature turns each managed load into a real-time safety valve which will instantly react to power system instabilities by shedding load. The feature can be adjusted and enabled remotely through the communication link. Control events are generally signaled by the utility through paging communication, but the LUF feature works locally and independently at each load connected to the load management receiver in order to be effective at combating frequency problems-which can occur instantly and without warning.
The HECO program targets water heaters on the island of Oahu. The program’s primary purpose is to allow HECO to operate reliably with smaller reserve margins, but customers will also benefit from fewer outages related to frequency droop events.
Keith Block, manager of the residential direct load control program, explained, “Island networks are particularly susceptible to under-frequency problems due to the closed nature of the system. Without the ability to draw on reserves from neighboring utilities, frequency will decline any time one of our generating units unexpectedly drops off-line. While not every frequency decline will trigger the load management receiver, Cannon’s LUF devices will be an important tool in preventing outages caused by under-frequency events.
“We have already seen the LUF feature perform in a small frequency droop last month; it works just as we intended,” Block added.
Joel Cannon, president of Cannon Technologies said, “It’s nice to see utilities valuing the advanced protection features of our load management devices. We have offered LUF in receivers for a long time, but its value is more evident now as distribution systems are under more stress.”à¢®à¢®
Progress to Install 2.7 Million AMR Meters in Florida, Carolinas
Progress Energy has entered into a contract with Itron to replace 2.7 million traditional electromechanical residential meters with Itron’s CENTRON solid-state electricity meters equipped with Itron’s embedded automated meter reading (AMR) technology.
The CENTRON digital meters are more accurate than electromechanical meters and difficult to tamper with, which is expected to reduce cases of energy theft. The new meters will be read automatically via radio signal, thereby eliminating manual data entry errors, the need to access the premise and greatly reducing or eliminating estimated and inaccurate bills.
Installation of the system began in Florida this summer and in the Carolinas in September, with a two-year completion date. To meet that schedule, Itron will install an average of 7,000 meters each workday across Progress Energy’s territories. Using Itron’s vehicle-based mobile AMR technology, a single meter reader will be able to read 10,000 meters or more each day. Through manual methods, readers have been able to read only about 400 meters a day.à¢®à¢®
KCP&L Rolling out Wireless Monitoring and Control
Kansas City Power & Light (KCP&L) is moving forward with a wireless monitoring and control project rollout with Telemetric’s DNP- Remote Telemetry Module (RTM). KCP&L is using the Telemetric DNP-RTM to monitor and control network protectors located in vaults in the Kansas City metropolitan area. The DNP-RTM communicates with ETI/Richards Manufacturing relays that provide detailed status information on their network protectors. This will allow KCP&L to immediately respond to network protector operations and any other anomalies before they are reported by customers. KCP&L is also installing Telemetric TVM-3 monitors in vaults at various key network locations to monitor three-phase voltage.
After successfully testing cellular communications in typical vaults, KCP&L decided to completely roll out the Telemetric DNP-RTM and ETI/Richards relay combination to all of its network protectors.
“This project will reduce operating and maintenance expenses through the wireless monitoring and control of our grid and spot networks,” said Bill Herdegen, KCP&L vice president of customer operations. “In addition, it will enhance safety for our personnel by providing remote control operating functions. Our system operators and engineers will have a convenient overview to manage network-operating conditions. As a result, our network customers will enjoy improved service quality.”
The DNP-RTM was developed in conjunction with KCP&L and other utilities as a general-purpose communication device suitable for use with any intelligent control that supports the DNP 3.0 protocol. Telemetric worked closely with KCP&L to tailor the DNP-RTM to meet the company’s specific application requirements that were not previously available at a cost-effective price.à¢®à¢®
ABB Joins EPRI’s IntelliGrid Consortium
ABB recently signed a multi-year agreement to join EPRI’s IntelliGrid Consortium.
The IntelliGrid Consortium is an association of electric utilities, manufacturers, researchers and federal/state agencies working together to apply state-of-the-art communication and control technologies to the electric infrastructure. Their goal is to enable a grid that is self-healing, predictive and more secure. After publishing the Integrated Communication Architecture Guidelines in 2004, the group is now focusing on the application of that architecture throughout the industry. ABB brings to the group its know-how in product innovation and manufacturing, a necessary ingredient as the consortium works with its utility partners to implement the vision.
“To transform today’s electric grid into a sophisticated, integrated delivery system, all parties must work together from the beginning to understand the potential and needs of all those involved,” said Bernhard Eschermann, ABB’s head of power technology research. “EPRI’s IntelliGrid program represents a unique opportunity for us to work side-by-side with leading utilities and industry groups to do just that.”à¢®à¢®
Hunt Power Offering Satellite Service for Elster Meters
Hunt Power recently announced its ability to collect energy usage data from Elster Electricity ALPHA Plus meters via satellite. In a move last fall, Hunt Power launched a two-way satellite service to read GE KV2 series meters for utility customers like the Lower Colorado River Authority. With the support for Elster ALPHA Plus meters, Hunt Power is now able to conduct satellite meter-reading for more than half of all electric meters used by utilities.
“Utilities tell us that one of their greatest challenges is reflecting accurate meter data in customer bills,” said Daniel Price, Hunt Power’s vice president of strategic development. “Satellite is now a proven communications option that works without any “Ëœline-of-sight’ requirements. Therefore, utilities no longer have to depend on ever-changing cellular technology.”
Hunt Power’s satellite service offers a daily meter read that captures stored 15-minute interval data. The data remains secure for many reasons, including the fact that the satellite signals are transmitted in short bursts on frequencies determined by momentary conditions.à¢®à¢®
Alabama Power to Boost Transmission Capacity with ACCR Conductor
Alabama Power Co., which supplies electricity to 1.3 million homes, businesses and industrial facilities, will become the third major utility to install 3M’s Aluminum Conductor Composite Reinforced (ACCR) electricity conductor. The ACCR is a new type of metal overhead line that can reportedly double the transmission capacity of conventional conductors of the same diameter, without requiring new towers or any visual changes.
The ACCR will replace a key 10-mile line in northeastern Alabama. The change is being made because the existing conductor would be at capacity for certain contingencies resulting from the addition of new generation during summer peak loads, beginning in 2008. Installation of the ACCR is expected to begin in January 2006.
The new 3M conductor, which is heat-sag resistant, was developed to reduce the potential for thermally constrained transmission lines. In addition, the ACCR provides the industry with a metal overhead conductor solution.
Alabama Power, the second largest unit of Southern Company, supplies energy to two thirds of the state. Its selection of 3M’s ACCR to improve capacity on a key line follows similar decisions by Xcel Energy, for a 10-mile line in Minnesota, and the Western Area Power Administration, for an 80-mile line along the Colorado River in Arizona.
“The use of the 3M conductor for this project allowed us to avoid the replacement of 22 transmission structures and the installation of eight additional structures,” said Andy Wallace, transmission line manager for Alabama Power. “This will significantly reduce our construction time frame and allow the line to be taken out of service for this project without impacting the reliability of our grid.”
Tracy Anderson, 3M project manager for the ACCR, said interest in the new conductor “is building quickly as a cost-efficient and reliable way to relieve many of the national grid’s potential bottlenecks. Before bringing this product to market, we devoted four years to rugged, extensive field testing with several utilities and the Department of Energy, under virtually every conceivable atmospheric condition. The ACCR met every expectation.”
Anderson noted that the first two purchases of the ACCR were made by utilities that participated in the field testing, for installation in areas subject to extreme weather conditions.
The ACCR contains a multi-strand core of heat-resistant aluminum matrix composite wires. The conductor retains its strength at high temperatures and is not adversely affected by environmental conditions. Its light weight and reduced thermal expansion properties are what enable installation on existing towers, with no requirement for visual changes to a line or additional rights of way.à¢®à¢®
Open Standards, Cyber-threat Driving SCADA Market Trends
Analysis from Frost & Sullivan, North American Power Transmission SCADA Systems Markets, reveals that revenue in these markets totaled $150.3 million in 2004 and projects to grow to $214.7 million by 2011.
But, according to Frost & Sullivan, vendors often fail to present a convincing business case and electric utility personnel fail to demonstrate a clear justification for investment on SCADA to the approving officers-despite being convinced of its need. Vendors need to work closely with SCADA utility personnel and refashion their approach to justifying investments in the solution, according to the global consulting company.
In addition to quantitative benefits such as operational savings, direct cost savings and opportunity cost savings, it is useful to present the investment in broader terms, such as utilities’ business strategies, corporate responsibility, infrastructure security, deregulation, public image, and liability risks.
Frost & Sullivan warns that as new-generation SCADA systems incorporate open standards, including Internet Protocols and networked communications, the threat of cyber intrusions from hackers looms large.
“In response to the increased security concerns, vendors are updating and modifying sales pitches such that the security issue plays a central role in the presentation agenda,” said Roberto Torres, Frost & Sullivan strategic analyst.
Facilitated by the trend toward open standards, electric utilities have gradually evolved from a pattern of major upgrades every 10 or more years, to smaller, step-by-step upgrades every two to three years, Frost & Sullivan finds.
“As prices of SCADA systems continue to decline, the biggest growth opportunity lies with electrical municipalities and rural cooperatives, most of which do not have these systems but are now exploring their installation,” Torres said. “The urgent need to upgrade energy management systems in response to grid instability problems assures strong short-term prospects for the North American power transmission SCADA systems markets.”à¢®à¢®
Trans Bay HVDC Project Gets Green Light from Cal ISO
Trans Bay Cable (TBC), a subsidiary of international investment and advisory firm Babcock & Brown, has received approval from the California Independent System Operator (ISO) for its proposed high-voltage direct current (HVDC) transmission line. This key regulatory decision confirms the project’s importance as a much-needed energy transmission source for the state.
The Trans Bay Cable is a 59-mile-long HVDC transmission line that will run under the bay from the city of Pittsburg, Calif., to San Francisco. At each end of the cable, a converter station will be built to convert the current into direct current or alternating current, as appropriate, for use on the power grid. The project will not need its own power plant, but rather will transmit existing power from the Pittsburg Substation to a converter station in San Francisco.
The ISO’s Board of Governors chose the TBC project over several other alternatives as the most feasible energy transmission project for San Francisco and the greater Bay Area for years to come.
“San Francisco does not generate enough power for its businesses and residents,” said TBC project manager David Parquet. “This project is an environmentally benign way to meet San Francisco’s energy needs without disrupting other Bay Area communities with transmission line construction.”
Babcock & Brown’s partner in the TBC project is the City of Pittsburg. The city will eventually own, operate and maintain the assets of the project. Babcock & Brown will provide the development and long-term financing for the project.
The ISO’s approval follows a July decision by the Federal Energy Regulatory Commission (FERC) to accept the Trans Bay Cable’s request for certain rate principals which will provide the project with an adequate rate of return on its investment to finance the project.
Now that these two key regulatory approvals have been obtained, the TBC project will move to complete its environmental review of the transmission line. An Environmental Impact Report (EIR) will be conducted for this project and will include studies of the project’s effect on marine life, noise, public health, transportation and other topics. The City of Pittsburg is the lead agency for the environmental review of this project. Construction of the project should begin in 2006 after its permits and approvals are complete, and the cable should be ready for operation in 2009. à¢®à¢®
Iowa Lakes Electric Co-op Integrates Field Design and GIS
Iowa Lakes Electric Cooperative (ILEC) has successfully deployed Powel-MiniMax’s Utility Decision Support Platform (UDSP). ILEC’s first two UDSP modules, StakeOut and GIS, are expected to provide a single platform for seamless field-to-office work order integration.
The scalable design of the UDSP product lets utilities customize a solution that meets current business needs, and then integrate additional modules later to further automate operational processes and connect to enterprise-wide systems.
“Essentially, we want to stake a job in the field and move the data into our GIS maps automatically,” said Steve Erickson, ILEC’s supervisor of operations administration. “With StakeOut and the GIS module working together, we will accomplish this goal. The effects on productivity, cost-efficiency, and customer service will be considerable.”
According to Erickson, linking field design and GIS will immediately streamline work order processes that rely on manual data entry.
“Every time one of our crews sends in a service order, each department reviews the document, extracts relevant information, and re-enters the data into an appropriate application,” Erickson said. “Without an integrated solution, there is no other way for utilities to distribute this information. By running our field design and GIS from a single platform, we can save several steps and reduce the risk of data entry errors.”
Fewer errors are expected to drive significant cost savings for ILEC. With the previous system, if an error was detected-for example, if the same transformer was listed for two accounts 40 miles apart-it could take days to resolve. A field crew had to revisit the site and confirm the details. Plus, field crew schedules are determined weekly so new requests can sit in the queue for several days.
Erickson said that with the new solution, the co-op can virtually eliminate these problems and spend far less time cleaning up data. “We will also be able to process billing much faster and spend more time responding to customer needs-both of which will significantly improve service levels,” he said.
Corey Maple, CEO of Powel-MiniMax, agreed. “Ultimately, our solutions help utilities make operational improvements that enhance customer service,” he said. “This gives our customers a strong competitive advantage.”
After the GIS module is fully implemented, Erickson and other ILEC executives will consider adding business functionality, such as engineering analysis and outage management, to the platform. UDSP uses a single asset database that allows engineering analysis calculations to be completed much faster than ever before. It also offers modules for asset management, outage management, planning and project management, work order management, web viewing and maintenance.à¢®à¢®
Newly Patented Technology Helps Transformers Keep their Cool
The U.S. Patent Office has awarded Trexco a patent for its technology, which promises to add capacity to power transformers in the nation’s electric grid. The new technology works by capturing waste heat generated by load losses from the transformer and uses the energy to dynamically manage the unit’s operating temperature. Trexco’s system is intended to keep transformers cool, allowing utilities to increase the loading-carrying capacity of existing transformers.
“By reducing the operating temperatures of transformers, our system also will prolong the lifespan of the equipment,” said T. Dan Bailey, Trexco’s CEO. This benefit is why Trexco branded its technology the Transformer Extender.
By decoupling the transformer capacity from the ambient conditions, the Trexco Extender will increase substation and grid reliability, add to system security and greatly aid in substation asset management, Bailey said.
The U.S. utility industry utilizes more than 100,000 high- and medium-power transformers as part of the national electrical grid. Anthony M. Visnesky Jr., Trexco’s chief technology officer and the technology’s co-inventor, said that if the company’s technology becomes widely used, it could help prevent blackouts.
The first commercial installation of a Transformer Extender should occur in the first half of 2006, Bailey said. An 11-member utility industry advisory group is formulating the technical criteria for the test program to validate the commercial-scale performance parameters of the Extender on a 40-MVA power transformer. This test will be conducted during the first quarter of 2006 under the auspices of the National Electric Energy Testing Research and Applications Center of Georgia Tech.
Trexco successfully demonstrated the technology on a commercial scale during tests in April 2003 at Wellman Furnaces in Shelbyville, Ind. Wellman, which Trexco has contracted to manufacture the Transformer Extender, and the University of Indianapolis have joined with Trexco in a year-long effort to ensure that the system will meet utility industry requirements.à¢®à¢®
Miner & Miner, ViryaNet Integrate Products to Improve Crew Management
Miner & Miner, a Telvent company, and ViryaNet recently announced an initiative to integrate their Responder OMS and Service Hub products to provide integrated crew management for outage restorations and repairs in the field. The two companies revealed the first stage of the integrated products at the ESRI User Conference in San Diego in late July.
Responder is a GIS-hosted outage management system (OMS) that leverages .NET and ASP technology to enable trouble call and outage incident management in a scalable and configurable environment. The Responder Trouble Call Analysis (TCA) Engine uses an iterative prediction algorithm to determine which interruptible network device caused an outage. The display utilizes ESRI’s ArcGIS and allows utility personnel to have a spatial view of the locations of trouble calls, enabling analysis of outages and immediate dispatch of crews.
ViryaNet’s Service Hub for Utilities is a workforce management system that receives work orders from external systems, schedules work orders to engineers, sends all relevant data to mobile devices, and returns updated data from the field to external systems. The solution provides the ability to oversee distributed field staff and other resources, including internal employees and subcontractors, through a universal scheduling and dispatch approach.
The integrated products will enable utilities to visualize and predict where outages are occurring and dispatch crews in a way that maximizes resources and minimizes network downtime. Dispatchers and call centers can quickly see the status of incidents and provide estimated restoration times to customers.
“This effort illustrates one of the key concepts behind Responder, which is to provide an open platform that can integrate within the IT infrastructure to multiply business benefits,” said Jeff Meyers, Miner & Miner president. “Integration with ViryaNet Service Hub is going to enable users to take advantage of very advanced dispatching and crew management functionality from an industry leader.”
“The integrated Responder and Service Hub products will provide utility companies a comprehensive solution that addresses the management of the entire restoration cycle, from initial outage, to personnel scheduling, to problem resolution, to follow-up field reporting,” said Samuel HaCohen, ViryaNet’s board chairman. à¢®à¢®