Four Utilities Garner Awards At DistribuTECH 2007

By Steven M. Brown, editor in chief, and Kathleen Davis, associate editor

An innovative transmission design meant to alleviate one of the most notoriously congested areas in the U.S.; a multi-territory, multi-state, multi-commodity metering system; an automation project whose benefits may go beyond the small industrial park where it went live; and an integrated GPS/GIS/mobile asset management solution-all were named recipients of Utility Automation & Engineering T&D’s annual Projects of the Year awards during the DistribuTECH 2007 keynote session.

Click here to enlarge image

Now in its fourth year, the awards program is designed to honor the most innovative electric power transmission and distribution technology implementations undertaken by North American electric utilities each year.

Winners of the 2006 Projects of the Year Awards were:

  • AMR/AMI Project of the Year: Unitil;
  • T&D Engineering Project of the Year: Northeast Utilities;
  • T&D Automation Project of the Year: We Energies; and
  • Geospatial Project of the Year: BC Hydro.

Unitil’s System-wide AMI Project

The winner of the 2006 Advanced Metering Project of the Year Award isn’t one of the bigger implementations in recent history, but it is a unique one in several ways.

When Unitil made the decision to proceed with a system-wide gas and electric advanced metering deployment in 2005, they had a number of challenges in front of them: Their service territory covers three distinct areas in New Hampshire and Massachusetts; they serve both urban and rural customers; their topography ranges from flat and open to wooded and hilly; and, they wanted one system to cover all gas and electric meters in this diverse territory.

An installer preparing to reinstall the index along with a Badger Orion endpoint module to transmit gas readings to the multi-utility endpoint in the electric meter in the basement of the house. Page 12 photo: (l-r) Utillity Automation & Engineering editor Steve Brown and Electric Light & Power managing editor Nancy Spring present the metering Project of the Year award to Glenn Appleton, Mike Deschambeault and Raymond Morrissey from Unitil at DistribuTECH 2007 in San Diego on Feb. 4.Click here to enlarge image

“We were seeking a system capable of reading both electric and gas meters in the Fitchburg (Mass.) area and the electric meters in our other service territories,” said Glenn Appleton, director of meter and service at Unitil.

Unitil installed an advanced two-way power line communications-based system from Hunt Technologies to meet this challenge. Gas metering is done using Hunt’s multi-utility endpoint and short-range radio from Badger Meter, which sends gas meter consumption data to the electric meter at the same customer’s premises. Both electric and gas readings are transported over power line to the substation and from there back to Unitil’s operating center.

An installer heading around the house to program a Hunt MUE endpoint (electric) to receive the signal from the gas endpoint.Click here to enlarge image

“We leaned toward a power line carrier-based system for a number of reasons,” said Mike Deschambeault, Unitil’s AMI project manager. “We wanted the range and the communication functions the system provides. It’s a new communication system for us, but it has the look and feel of something we’re used to. The one thing we know is our distribution system.”

In addition to a multi-utility system capable of reading electric and gas meters, Unitil preferred a fixed network that would function well in the area’s hilly topography and link between numerous communities. Past experience with RF convinced staff that 100 percent coverage would be difficult to achieve without installing and maintaining an extensive infrastructure.

Finally, Unitil wanted a scalable technology capable of providing a level of functionality for value-added benefits, such as on-demand reads, voltage monitoring, time-based rate structures, outage management and remote service disconnect.

The TS2 Multi-utility system best fit all of these criteria. It is the first power line carrier-based AMI system to function with a short-hop RF device to read electric, water and gas meters with one system.

At the core of the system is a multi-utility module equipped with an antenna that enables it to communicate by way of short-hop RF with a module in either a gas or water meter. The module seamlessly integrates into an electromechanical or solid state meter. It returns up to three separate meter reads to a data collector in the substation using FDMA (frequency division multiple access) power line carrier technology. This enables the module to remain in constant and simultaneous communication with the data collector.

The multi-utility system is designed to work with Badger Meter’s ORION transmitter for either gas or water. The ORION gas module mounts on the gas meter using a custom adapter plate that fits between the meter and the index. During installation, the module is programmed with the current gas meter reading, so account history is maintained.

The module encodes the gas meter reading, meter identification number and tamper information. It transmits at a frequency in an unlicensed frequency band at predetermined periods, so no “wake-up” signal is required.

According to Alan Swanson, TS2 product manager at Hunt, the main advantages of deploying a fixed network multi-utility system is the continuous communication with the endpoint. Data is available on a daily basis to support off-cycle reads. Tamper and outage information is automatically collected. Customer service is improved because historical data is available to help resolve billing issues.

“A multi-functional AMI system provides more complete system coverage for a combination utility and a strong return on investment, while being simpler to administer and maintain,” Swanson said.

Unitil is a combination utility with three distinct service territories in two states. Based in Hampton, N.H., it provides retail electric service to 100,000 customers, and natural gas service to 15,000 accounts in New Hampshire and Massachusetts. The utility’s Fitchburg, Mass., distribution center serves 27,500 electric and 15,000 gas customers across six area communities. Over half of the town’s housing stock was built prior to World War II, and predictably, many of the meters are in hard-to-read locations. As part of its system acceptance test, Unitil installed the multi-utility system in 1,000 of its most challenging locations.

According to Deschambeault, Unitil was anxious to see if the RF component of the system would work as advertised.

“We’ve had different experiences with RF over the years and that part of the system was a concern for us at first. Would it do what it was supposed to do?” he said.

Ultimately, the robustness of communication between the electric and gas meters met, and in some cases exceeded, expectations. Even in the most difficult locations, only three required a repeater between the electric and gas meters.

As of the end of January 2007, the AMI project in Unitil’s Massachusetts service area is 95 percent complete. Customer data is being collected, and billing information compiled, automatically, and remotely, for nearly 40,000 gas and electric customer accounts.

NU’s Bethel-Norwalk 345-kV Project

On Oct. 12, 2006, Northeast Utilities (NU) successfully energized a new 21-mile 345-kV transmission circuit. One of the largest transmission projects recently completed in the country, the $350 million Bethel-Norwalk project was completed two months ahead of schedule and about $15 million under budget. The project used two different 345-kV underground cable technologies in a transmission line that is alternately overhead and underground and also utilized technology such as gas-insulated substations to meet site limitations. Based on the challenging nature of the project and the benefits it provided a historically congested part of New England, Bethel-Norwalk was named the recipient of our 2006 T&D Engineering Project of the Year award.

Northeast Utilities’ Bethel-Norwalk project included the longest length of 345-kV solid underground cable in the U.S.Click here to enlarge image

Completing Bethel-Norwalk was an important step toward solving one of the most critical electrical grid bottlenecks and threats to electric reliability in Connecticut, New England and the country. Bethel-Norwalk was needed because of southwest Connecticut’s isolation from New England’s 345-kV electric transmission grid.

The project achieved the following:

  • Improves reliability by providing a new path for bulk power to flow into the area;
  • Increases capacity (600 MW, emergency 1,200 MW) to a transmission-constrained area (southwest Connecticut);
  • Reduces (by more than a third) existing transmission congestion and related costs which currently exceed $300 million/year; and
  • Provides greater access to competitively priced generation.

While completing Bethlel-Norwalk was a technical challenge, just getting the project off the ground and in motion was no simple task. In October 2001, NU submitted the Bethel-Norwalk project application to the Connecticut Siting Council as an all-overhead 115-kV/345-kV double circuit transmission line located in the existing 115-kV right of way. In June 2002, the Connecticut legislature passed a law imposing a moratorium on new transmission, thus delaying the siting council’s one-year statutory deadline for review. The law also established a working group to evaluate alternatives to the proposed transmission line.

After evaluating 14 hybrid designs, in September 2003 the siting council issued its final approval of a configuration that had the transmission line alternating between overhead and underground (on both the 115-kV and 345-kV circuits). Norwalk, one of four towns impacted by the project, filed an appeal in November 2003 effectively delaying the project until August 2004, when the appeal was dismissed and the project could finally get under way.

When all was said and done, NU ended up with a far more complex project because of the “porpoising” design. The new 345-kV transmission circuit uses two different underground cable technologies, including the longest length of 345-kV solid underground cable used in the U.S. In addition, sections of the existing overhead 115-kV transmission circuits between two substations had to move underground to accommodate the 345-kV line. After a 36-month siting process, NU completed all underground and overhead construction in just 16 months.

The new 345-kV line includes 8.5 miles of new overhead construction and 11.8 miles of 345-kV underground cables. NU used 345-kV high-pressure fluid-filled (HPFF) cable systems for the majority of the underground portion of the new 345-kV line, and 2.1 miles of 345-kV cross-link polyethylene (XLPE) cables.

“Underground high-voltage cable construction is not just buried overhead conductor,” said Laurie Aylsworth, NU’s transmission project director. “With overhead construction, the utility is working within its own rights-of-way; but existing rights-of-way were not suitable for the type of equipment necessary to install underground cable. That forced the construction into state roadways and rights-of-way. This resulted in another agency dictating work hours and road restoration specifications, in addition to forcing work stoppage during winter months.

“Due to the thermal characteristics of burying high-voltage cable, once the conduit was installed, the trench had to be back-filled with a flowable fill,” Aylsworth continued. “That requirement necessitated disposing of 14,000 truckloads of soil (most of which had to be taken to landfills). The other major challenge of underground construction is the “Ëœunseen,’ all the unidentified obstacles in the roadways such as abandoned gas lines and old drainage pipes. The trenching crews found everything from old clay aqueducts to layers upon layers of concrete.”

At Plumtree Substation in Bethel, NU constructed a 345-kV outdoor gas-insulated substation (GIS), required because the space for expansion was severely constrained by adjacent wetlands. At Norwalk Substation, NU installed an indoor 345-kV GIS system, autotransformers, three underground 115-kV line sections, a fourth 115-kV switchyard bay, and a 345-kV line terminal structure. In addition, 345-kV line transition stations were constructed in Bethel, Redding, and Wilton at points where the 345-kV line transitions from overhead to underground construction.

More than 200 tons of steel were delivered and erected for Northeast Utilities’ Bethel-Norwalk project.Click here to enlarge image

NU’s project team, led by Aylsworth, leveraged experienced internal personnel with consultants and contractors for the tasks that required special expertise or large teams, with the achieved goals of limiting financial risk while maximizing control. NU transmission engineering staff completed the engineering and design for both the substations. POWER Engineers Inc. engineered and designed all line components between the two substations as well as managed the construction. Other contracts issued included:

  • Mitsubishi Electric, which furnished GIS equipment at two substations;
  • McPhee Electric Ltd., which performed substation civil and electrical engineering and transition stations electrical engineering;
  • Siemens, which furnished and installed three reactors;
  • W. A. Chester, which furnished and installed 10 miles of 345-kV HPFF underground cable;
  • Kiewit Construction, which furnished and installed 10 miles of 115-kV XLPE underground cable;
  • New River Electrical Corporation, which furnished and installed 2.1 miles of 345-kV XLPE underground cable;
  • M.J. Electric, which constructed 345-kV overhead line;
  • Blakeslee Arpaia Chapman, which performed civil engineering at transition stations and civil engineering on the 345-kV XLPE line; and
  • Sertex, which furnished and installed fiber optic cable system.

With the Bethel-Norwalk project, NU believes it has built the right solution at the right time to strengthen Connecticut’s energy grid. The complex construction project begins to solve the need to reinforce the state’s electrical infrastructure, immediately improves the long-standing reliability challenges in southwest Connecticut, and makes the regional transmission grid more secure and efficient, all while saving Connecticut consumers millions of dollars in congestion costs.

We Energies DA Project

One of the chief criteria used in determining Project of the Year award recipients is how beneficial the project is not just to the utility that undertook it, but to the industry as a whole. The winner of the 2006 Automation Project of the Year award met this criteria by helping to develop equipment and techniques that can be applicable at most any utility.

In 2001, We Energies helped start a consortium of six utilities, which would work together for the advancement of distribution automation. The group, known as Distribution Vision 2010 (or DV2010), focused on developing universal concepts and techniques that would be applicable at any utility. The group also focused on working with manufacturers in the development of new equipment for the implementation of these technologies.

Installation of one recloser with the RuggedComm Ethernet Switch in the DV2010 enhanced Cooper Form 6 recloser control box.Click here to enlarge image

The DV2010 Advanced Distribution Automation (ADA) system was defined as four tiers of automation which would work independently to achieve automation and operational improvements in each tier. The four tiers could be applied in various combinations to achieve specific performance objectives to suit different DA applications.

We Energies DV2010 project in New Berlin, Wis., developed the technologies and techniques used to implement three of the four ADA concepts by establishing a high-reliability premium power park built upon the existing power distribution infrastructure of a 600-acre, 30-year-old industrial park. The project established a closed loop network tied to multiple sources at the primary operating voltage.

The distribution network integrated three separate feeders in the New Berlin Industrial Park serving approximately 100 industrial customers inside the park and 3,000 residential customers outside the park. The network is segmented into four premium operating districts (PODs) using five Cooper Power Form 6 reclosers enhanced with DV2010 features. The alternate line is tied to the network at two locations, using a fifth DV2010/Cooper Form 6 recloser at the first location and a feeder through four position Reverse Vacuum Fault Interrupter (RVFI) also using enhanced DV2010 protection features.

Tier 1 of the DV2010 ADA defines an improved overcurrent protection scheme based on directional overcurrent practices. Enhancements were made to the Cooper Form 6 recloser control to implement two independent sets of directional overcurrent elements in the same control. This allowed traditional overcurrent protection coordination techniques to be used throughout the network to assure proper fault detection, coordination and isolation without the need to rely on communication based controls.

Tier 2 of the DV2010 ADA defines a communication-based enhanced protection scheme that operates faster than traditional time-overcurrent systems. The Tier 2 techniques were implemented in the Cooper PROView software using the PeerComm communication protocol over a dedicated LAN constructed throughout the New Berlin Industrial Park using fully redundant single-mode fiber optic network between five recloser locations, the padmounted switchgear and the substation.

The PeerComm protocol continuously posted data from each control to the PeerComm Network every 6 milliseconds. This allows new DA-augmented protection schemes to be implemented using POD logic techniques which properly identifies the location of a fault on the network in one cycle and isolates the POD at all automated points surrounding the fault in an average of five cycles. This technique isolates the fault to a single POD on the network and eliminates momentary interruptions to all other PODs, which results in a significant reduction in customer outage minutes.

Momentary faults within a POD are coordinated with the Tier 1 and Tier 2 protection scheme within the design of the POD logic by an automation technique called “dynamic reclosing.” This technique allows low-cost traditional overcurrent devices to be used within automated PODs to isolate faults on small taps or at single customers without interrupting customers on the network. The dynamic reclosing feature automatically detects temporary reconfigurations in the network and automatically adjusts the protection scheme to dynamically move the point of reclosing on the network to the most advantageous location.

Tier 3 of the DV2010 Advanced DA system defines the DA Controller functionality that automatically executes remedial switching operations to restore power to unfaulted sections of the distribution system after the initial fault had been successfully isolated. The DA Logic processor module is used to define a logical model of the network within the Orion5R control. This unit gathers data from each field device to identify the location of the fault and automatically execute sequenced switching operations to properly isolate all points of the faulted section of the circuit and restore service to the unfaulted sections through bridging.

The alternate network line was integrated into the design to provide extra capacity and relieve overloads if a fault occurred in certain PODs when loading was very high. The system automatically reconfigures the network through a high-speed transfer using both Tier 2 and Tier 3 DV2010 techniques to complete a sequenced closed switch transition transfer in up to three devices in approximately six cycles.

In 2001 and 2002, We Energies worked with Cooper Power Systems to develop the planning and design of the network concepts used at New Berlin in 2001 and 2002. Development of the enhancements to the Cooper Form 6 recloser and the reverse VFI were completed by Cooper Power systems in 2005. The DAMaster was developed with Novatech for WeEnergies starting in 2002 and continues to be enhanced. Construction at New Berlin was completed in 2005 and field tested in early 2006. The system was placed in service on March 30, 2006.

There have been five faults on the system at New Berlin since it was placed in service. Each fault was properly identified and isolated in by the Tier 2 enhanced protection scheme in four and a half cycles. Momentary faults were properly coordinated with the DA devices to eliminate the momentary interruption to the industrial customers in the park.

BC Hydro’s “ËœSAM’ Geospatial Project

BC Hydro has garnered the 2006 Utility Automation & Engineering T&D magazine’s Geospatial Project of the Year-thanks to SAM.

Power line technician Harold Wootton in a BC Hydro line truck equipped with the SAM application.Click here to enlarge image

“BC Hydro is pleased to be recognized for development of the Spatial Asset Management (SAM) program,” said Ralph Zucker, director of asset investment and reliability. “Given the wide geographic distribution of our assets, the complexity of the system, and concerns for aging components, reliability and safety, there is no doubt about the value that the SAM program will return to the organization. Knowing where our assets are and being able to identify and manage work electronically will provide significant cost and service benefits for us and for our customers.”

SAM-or “spatial asset management”-provides BC Hydro with a unique integration of asset maintenance information with global positioning system (GPS) capabilities embedded in a geographic information system (GIS) format, which is available on mobile units to support maintenance and repair of the distribution system.

BC Hydro owns and operates 57,000 km of primary (overhead & underground) distribution lines with approximately 47,500 km of overhead distribution corridor. The original cost of the distribution assets is $3 billion, with an estimated replacement cost of $5 billion.

Prior to the implementation of SAM, the management and maintenance of BC Hydro’s distribution assets used a number of stand-alone applications and databases. Asset and maintenance information was managed separately. There was no centralized, integrated data base of asset and maintenance records.

BC Hydro’s maintenance planning and IT departments collaborated to bring SAM to life. The project was approved in August of 2003, with the field test pilot program running from February to April 2005. The installation began in May of 2005 and was completed in September of last year.

The SAM system has directly delivered results in several key areas, including: increased efficiency of maintenance crews, reduced cost of asset inspections, improved analysis of asset conditions, and it has reduced the cost of administration of multiple stand-alone maintenance systems. Indirectly, the SAM system also contributes to improved reliability and reduced costs to BC Hydro’s customers.

“During major storm repairs [in Nov. 2006], SAM maps and GPS provided quick identification of fallen conductors, loop feed systems IMO, supply fuses and lateral fusing. These along with detailed and accurate trouble reports allowed for quick and safe restoration of power,” stated Duane March, a trouble technician with BC Hydro.

“I consider SAM to be a vital tool for field users . . . my endorsement of this program is not lightly given, and it’s currently the only software program that I use which I feel is worthy of that promotion.,” be added.

The utility was specific about the benefits of SAM-right down to nitty, gritty details.

When maintenance and construction work order information was previously stored in separate databases, it would take several weeks to update the asset information with results of the construction program. As a result, maintenance work was sometimes scheduled without knowledge of construction work that had been completed on that site a few weeks before, or crews would be mistakenly deployed to conduct maintenance work on assets that had just recently been rebuilt. By combining maintenance, construction and asset data in a single database, the SAM system has greatly reduced this type of scheduling inefficiency.

Additionally, crews arriving at a site to perform maintenance work can now access digital maps of the work site and distribution asset information using the GIS system. Three immediate benefits of this particular capability include:

  • Digital maps are more likely to be up-to-date than paper.
  • The amount of map-based information is far greater when in digital format than when in paper-based format.
  • With a digital rather than paper-based system, field staff is able to more easily note and record discrepancies between the asset data base and the physical asset. Since the deployment of SAM, field staff has recorded approximately one hundred asset correction notes per month. The result is continuing improvement in the accuracy of existing asset records.

And, when field crews using SAM arrive at a site, the system will use the GPS coordinates to automatically bring up the GIS maps and asset information for the area. Time spent searching for correct maps and asset information is substantially reduced.

Additionally, all distribution assets are given an annual inspection. These inspections are typically “drive-by” checks by a field service crew that are intended primarily to detect unreported failures that create unsafe conditions. Typically, these inspections were completed with paper-based systems or stand-alone laptop applications.

The integrated nature of the SAM system has greatly increased the efficiency of this inspection process. As a SAM-equipped vehicle now drives down a street, the system will use the GPS to automatically locate maps and asset information for the immediate area. The field staff records inspection data directly to the system as the vehicle moves down street, and the system records all assets inspected.

Finally, maintenance work can now be displayed graphically with GIS information. This allows designers to more easily see a job in the context of other construction or maintenance work scheduled in the area. This has allowed greater scheduling efficiency.

With all these benefits, it’s easy to see why BC Hydro’s “SAM” installation won geospatial project of the year.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at

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