During the Keynote Session of the recently completed DistribuTECH 2005 Conference and Exhibition in San Diego, four utilities were recognized for extraordinary achievements through Utility Automation & Engineering T&D‘s Projects of the Year Awards. The awards are designed to honor the most innovative electric power transmission and distribution technology implementations undertaken by North American electric utilities each year.
Winners of the 2004 Projects of the Year Awards were:
San Diego Gas & Electric: T&D Engineering Project of the Year
ENMAX Power Corp.: T&D Automation Project of the Year
NSTAR Electric and Gas: Geospatial Technology Project of the Year
Niagara Mohawk: Automatic Meter Reading Project of the Year
SDG&E’s Upgrades Improve Reliability and Reduce Energy Costs
On Sept. 19, 2004, San Diego Gas & Electric (SDG&E) energized new 500-kV gas-insulated switchgear (GIS) and a step-down transformer at its Miguel substation in Bonita, Calif. This marked the first time SDG&E has used gas-insulation technology to expand a substation, which offered a creative and cost-effective solution to the challenges of limited space and an aggressive construction timeline.
Based largely on the size, speed and ingenuity of this project-and the benefit to customers-Utility Automation & Engineering T&D named it the winner of its 2004 T&D Engineering Project of the Year Award.
From concept to completion, the project took less than a year-an unprecedented timeframe for a project of this complexity, which typically would take two to three years. According to the manufacturers, the Miguel upgrade was the fastest 500-kV GIS project built in the world to date. The record pace was due to meticulous coordination between the company and its contractors for “just in time” design, material delivery and construction.
SDG&E set a fast track for this top-priority project because state and federal regulators identified Miguel as one of the most congested transmission hubs on California’s power grid. The completed project has enhanced SDG&E’s energy import capability, improved system reliability and produced immediate energy cost savings for southern California customers of approximately $18 million per year.
A bit of history leading up to the project: When the 500-kV Southwest Powerlink between Arizona and California went into service in 1984, the line terminated at a 500/230-kV, 1,120-MVA step-down transformer bank at the Miguel substation. This key east-west transmission line is routinely loaded to its maximum transfer capability of more than 1,000 MW daily.
After market deregulation, more than 8,000 MW of new generation was added in Arizona and connected to the Hassayampa/Palo Verde 500-kV switchyard, the eastern terminus of the Southwest Powerlink. In addition, 800 MW of new generation in Mexico was connected to the Southwest Powerlink at the SDG&E Imperial Valley (IV) substation, southeast of Miguel.
Work completed at its Miguel Substation in fall 2004 garnered San Diego Gas & Electric the 2004 T&D Engineering Project of the Year Award.
The IV 230-kV yard was rebuilt in 2003 to accommodate the expected generation addition. Due to system impedances, the power flows west to the Miguel substation, creating a transmission bottleneck and causing more than 8,000 hours per year of congestion at Miguel.
In May 2003, SDG&E proposed four key projects to ease the congestion at Miguel:
Add a new GIS with a 500/230-kV, 1,120-MVA transformer at Miguel.
Upgrade the Miguel-Imperial Valley series capacitors from 1,400 amp to 2,600 amp.
Re-conductor 2.6 miles of 138-kV transmission line.
Install a new 230-kV line from Miguel to SDG&E’s Mission substation in central San Diego.
The first three projects have already been completed and have increased the import capability from about 1,100 MW to 1,500 MW. And, when the 230-kV line is in place, the congestion at Miguel should drop to nearly 1,000 hours per year, thus increasing SDG&E’s import capability to 2,000 MW along the path through Miguel.
SDG&E’s novel approach to solving the congestion problem at Miguel started with a hands-on, cross-departmental oversight team that included engineering, maintenance and construction, operations, project management and procurement. The team decided to keep all construction on the originally graded pad areas of the existing substation to avoid a lengthy permitting and review process.
An air-insulated design was considered but rejected because it would have required an area the size of nine football fields. The GIS alternative not only met the size constraints of the proposed project-fitting in 1/100th of the space-but left room for future expansion to keep up with growth in customer demand. The GIS also offered improved reliability and safety, and required less maintenance.
Six manufacturers expressed interest and committed to meeting SDG&E’s December 2004 target in-service date. SDG&E arranged to have all companies present their bids, products and capabilities, and, a month later, the contract was awarded to Mitsubishi.
A team, consisting of SDG&E electricians, was then trained at the factory and assembled the GIS on-site, under Mitsubishi’s direction.
“All parties involved worked in parallel, as a unified team. The engineering was performed up-front; so, when it was time to negotiate the contract, we went to the plant and said this is exactly what we want, if you can build it. We then signed the contract and materials were being ordered that same day,” said Terry Snow, SDG&E’s major projects principal engineer.
“The team approach is what made this project so successful,” Snow said. “Everyone was equal and everyone understood we didn’t have time for normal operations. We identified problems and worked through it together. If we had not had the teamwork approach, it would not have worked.”
SDG&E’s award-winning project included the following design highlights:
Three, single-phase 373-MVA, 500/230-kV autotransformers (1,120-MVA, 3-phase bank) manufactured by Siemens were relocated from Imperial Valley to Miguel.
GIS was installed within the boundaries of the original transformer yard featuring:
A three-element ring bus with a fourth breaker for a line reactor.
A future expansion design to accommodate three bays of 11â„2 breaker, double bus arrangement.
A ring bus that can expand to a four-element ring without an outage of any of the existing elements.
A building designed to fit within a 40-foot-by-120-foot area.
The GIS building and a new 20-foot-by-40-foot, 500-kV control house were designed to fit between the current line and a future tie line A-frame in the existing transformer yard. The control house contains the new relays for the two transformers, tie line and reactor-protective relays and two DC batteries. The 500-kV equipment is now on its own DC system, which is a major enhancement to substation reliability.
An emergency bypass was added to allow the two transformer banks to be energized in the event of a failure in the GIS tie line. This allows restoration of the banks in less than one day.
Two 230-kV bays were expanded and replaced two breakers.
ENMAX DA Project Achieving Impressive Results
When it is completed, the multi-year distribution automation (DA) modernization program currently under way at ENMAX Power Corp. will include an estimated 200 automated switches on 80 distribution feeders. It is said to be the largest DA project of its kind in Canada. Based on results of the completed Phase I of this project, ENMAX garnered the 2004 T&D Automation Project of the Year Award.
The project, which aims to improve electric system reliability to Calgary, Alberta, Canada, employs an automated system that uses a combination of distributed and centralized intelligence to automatically isolate faults and then restore service to unfaulted sections.
Phase I of the project involved the automation of 19 distribution feeders using 14 pad-mount and 32 overhead switches. As of October 2004 (the time of the Projects of the Year judging), more than 700,000 customer outage minutes had been saved and 4,000 customer outages avoided on these automated feeders.
ENMAX owns, operates and maintains the regulated T&D system that serves approximately 1,000 square kilometers of Alberta, Canada, including Calgary and the surrounding area. ENMAX’s delivery system includes 33 substations served at 138 kV and 69 kV. The distribution system is operated as an open-loop radial system at 25 kV and 13.2 kV. It includes numerous normally open ties between feeders, making it an ideal candidate for feeder automation.
ENMAX’s award-winning DA project began in 2002 when the utility hired KEMA Consulting to perform a system automation study to determine the effect DA would have on system reliability. The study concluded that ENMAX could achieve its reliability targets by implementing feeder automation, and that the initiative would be economically viable when customer outage cost savings were considered.
In April 2003, the project was awarded to S&C Electric Co. The company was contracted to supply switchgear, automation equipment, radio communications equipment and to provide project management, commissioning and training services.
Equipment installation began in August 2003. The core of the DA system at ENMAX is S&C’s IntelliTEAM II Automatic Restoration System, an advanced DA system that utilizes distributed intelligence and peer-to-peer communications to constantly monitor the power system. When a fault occurs on the line, the system sectionalizes the line to isolate the faulted section, and then restores service to all unfaulted line sections. IntelliTEAM II utilizes multiple circuit ties in a wide variety of circuit configurations to maximize the probability that a restoration solution can be found. Further, the system uses distributed intelligence to prevent line overloads-enabling ENMAX to apply automation on circuits that would have otherwise been unsuitable for the task.
Phase I of the DA project (see Figure 1) involved the deployment of 14 S&C Remote Supervisory PME Pad-Mounted Switchgear units and 32 Scada-Mate Switches.
Calgary-based SUBNET Solutions Inc. is also involved in the ENMAX DA project. SUBNET is focused on two key areas; the DNP3 data communications throughout the system and the development of specialized automation logic to work in conjunction with S&C’s IntelliTeam II logic to meet ENMAX’s automation requirements.
SUBNET’s data communication involvement included the configuration of ENMAX’s GE Power Systems redundant D200 RTU devices to communicate over a combination of Ethernet and Utilinet Radio communications to S&C IntelliTeam II controllers located at key switching points in the ENMAX distribution system. SUBNET was also responsible for configuration and commissioning of the DNP3 LAN/WAN communications utilized within the ENMAX DA program.
According to a presentation delivered by ENMAX and S&C Electric at DistribuTECH 2005, one of the more challenging aspects of the project was incorporating feeder breakers, most of which are controlled by electro-mechanical relays, into the control scheme. In a collaborative effort between ENMAX, S&C and SUBNET Solutions, a centralized programmable logic module was developed for restoring the first line segment outside of the substation. The software program interface detects breaker trips and lockouts, and integrates the information with controls on the feeder to determine fault location. If the fault is beyond the first automated switch, the logic closes the breaker automatically. The substation logic system is integrated with the IntelliTEAM II system on the feeder to provide a complete automation solution for ENMAX.
The ENMAX DA project was chosen as the 2004 award-winner based on the size and scope of the project, and the reliability improvements achieved as a result of the Phase I implementation.
Phase I of the project, which was focused on the 25-kV distribution system, was completed in March 2004. As of November 2004, there have been 11 outage events on the automated feeders. During these events the automation system has averted an estimated 862,000 customer outage minutes and 6,800 customer outages. This translates into an 8.6 percent reduction in SAIDI and a SAIFI reduction of 1.7 percent, which is significant considering that only 16 percent of ENMAX’s customers are benefiting from this first phase of the project.
Phase II of the project began in August 2004 and includes an additional 10 feeders on the 13.2-kV system. The full build-out of the project will include an estimated 200 automated switches on 80 distribution feeders, which represents approximately one-quarter of ENMAX’s distribution feeders.
NSTAR Enhances Outage Restoration
As Massachusetts’ largest investor-owned electric and gas utility, NSTAR is tasked with keeping power flowing to more than 1.3 million customers in eastern Massachusetts. As part of that effort, NSTAR undertook a project in 2003 and 2004 to automate and streamline outage response by integrating multiple IT systems, including its outage management system (OMS), geographic information system (GIS), customer information system (CIS), trouble dispatch and supervisory control systems.
That project has been a success and netted NSTAR Utility Automation & Engineering T&D‘s Geospatial Technologies Project of the Year Award for 2004.
The integration effort depended first of all on accurate GIS mapping, which was helped along by the completion of a highly detailed landbase provided by James W. Sewall Co. During the mapping process, Sewall used softcopy photogrammetry to capture 300,000 utility poles and other infrastructure from aerial photography. Scanned at high resolution, the photography enabled Sewall photogrammetrists to obtain a capture rate of 89 percent. To achieve 100 percent representation, the new maps were compared with existing pole maps and edited.
With this landbase, IT consultant firm Logica developed for NSTAR a representative model of the distribution system for GIS integration, converting such data as pole attributes, circuit IDs, transformer drops and underground distribution.
Armed with accurate mapping information, the next step in the project was for NSTAR to bridge the gap between its OMS, GIS and call center systems. It did so by developing a middleware application called GATOR, which stands for Graphical Analysis Tools for Outage Restoration.
GATOR allows NSTAR’s OMS and call center systems to interact with both tabular and graphical vector information stored in the GIS. Now, when the call center receives an outage report, the call is routed to the OMS, which accesses the potential location of the outage, the relevant circuit data and customer data from the GIS. A work order is then generated that addresses not only the reported location, but the full extent of the outage, resulting in reduced outage restoration time and customer minutes lost.
Pete Dion, NSTAR’s manager of electric service, said there were two primary drivers behind the GATOR project. One was the need for a graphical tool to analyze outages more efficiently.
“What we had in our legacy system was the ability to analyze outages only on a tabular list,” Dion said. “You would sort it by circuit, by time, by location and all that, but it was more or less all on a spreadsheet. You couldn’t link it graphically.”
Now, as a result of the GATOR project, NSTAR has the ability to analyze outages graphically. Tom Gilbert, senior programmer/analyst for dispatch and restoration systems at NSTAR, said having that ability has made a big difference in the restoration process. “We can look at an entire geographical area and see what the patterns of outages look like. We can determine where we need to move crews and equipment to take care of the outages,” Gilbert said.
Dion noted the need for better communication with customers as GATOR’s second driver.
“Before, we didn’t have an efficient mechanism to provide customers with feedback on how a job was going,” Dion said. “With GATOR, once we analyze a job we create a job-specific message that is available to our customers immediately. Any customer that calls in the affected area will get the message that we know what’s going on, the status of the job and the estimated time of restoration. That information was only available manually and on an ad hoc basis in the old system.”
GATOR was implemented in three phases. In Phase I, CGI, an IT and business process services firm, developed a sophisticated algorithm to improve the estimated time to restore (ETR) calculation, taking into account the job type and current status of the restoration process. To improve the ability of NSTAR’s call center and customer service representatives to respond to calls for information, additional development by CGI delivered an advanced customer message (ACM) module using real-time feedback of more accurate information on the status and nature of the outage incident.
Rather than using the conventional connectivity model, CGI modified its OMS solution in Phase II to manage outages based on geographical proximity. With a seamless integration to ESRI’s ArcGIS solution, a high-availability application was developed that involved creating, editing and managing outage polygons by more than 30 dispatchers located in two major dispatch centers. The CGI/ESRI OMS was also integrated with other NSTAR systems through an enterprise application integration bus from webMethods.
Phase III involves the integration of CGI’s ACM outage information with NSTAR’s interactive voice response (IVR) system. In June, NSTAR extended the reach of the recently developed ACM outage information to customers who access Twenty First Century Communications (TFCC) IVR system. CGI will also provide call recording and automated customer callback functionality through the IVR.
As a result of the GATOR project, NSTAR now has a more efficient outage management process that expedites outage response and increases customer satisfaction. After unplanned outages, customers have their power restored more quickly-in some cases, before they even call in.
From start to finish, this entire outage management improvement initiative took about a year-and-a-half. Much of the project’s success can be attributed to teamwork and strong executive buy-in.
“GATOR has been extremely successful from a project management perspective,” said Roberta Mattox, NSTAR’s director of systems integration services. “NSTAR management had the foresight to bring together a talented team, including representatives from electric operations, NIS (NSTAR Information Services), human resources and customer care, headed by project leads from both electric operations and NIS. Dispatchers, our end users, also participated during the development, acceptance testing, and implementation phases.
“The project has been delivered on schedule and budget. The enthusiasm, teamwork, and dedication of the team members has been the key to the project’s success,” Mattox concluded.
Eugene Zimon, NSTAR’s senior vice-president and CIO said: “The faster and more accurately we can assess outages and determine our estimated time to restore, the better we can keep our customers informed about the status of an outage. By utilizing our IVR to provide outage status, we are improving customer service while at the same time, lowering our costs.”
Niagara Mohawk Goes 100 Percent Solid-state with AMR Project
Utility Automation & Engineering T&D‘s 2004 Automatic Meter Reading Project of the Year Award went to Niagara Mohawk for its large-scale electric and gas AMR project.
In 2002, Niagara Mohawk, an energy distribution subsidiary of National Grid USA, wanted to increase efficiency by using a mobile automatic meter reading (AMR) system that could pay for itself and reduce operational costs.
The utility also needed to upgrade its aging metering system since many of the electromechanical electricity meters were pushing 25 years of service, approaching their life expectancy. The question was whether to change-out all the meters or retrofit some, or all, of the utility’s 1.5 million meters with AMR endpoint devices.
Niagara Mohawk’s deployment of 1.5 million CENTRON meters has resulted in cost savings, better customer service and the 2004 AMR Project of the Year Award.
Niagara Mohawk provides electric service to approximately 1.5 million customers and natural gas service to about 570,000 customers in upstate New York. It is the second largest combined electric and gas utility in New York. The territory covers 24,000 square miles with meter readers spread throughout the region.
“It’s a cumbersome and expensive project to retrofit electromechanical meters that are about 25 years old with ERTs (encoder receiver transmitters),” said Evelyn Kaye, Niagara Mohawk’s AMR project manager. “It became obvious that sending the meters to a vendor to have AMR modules installed, redistributed and installed again-especially meters in service for nearly the duration of the life expectancy-would not be the most cost-effective path to take.”
Niagara Mohawk executives considered the overall costs of retrofitting aging meters and deployment efficiencies. The effort to pull out old electromechanical meters, install the ERT, clean it up and then replace the meter was an expensive operation, given the age of some of the meters. Although the utility originally considered purchasing some new meters and retrofitting the rest, after extensive research, company officials decided on 100 percent deployment of Itron’s solid-state CENTRON residential meter.
Solid-state meters are generally believed to be more accurate than traditional electromechanical meters. Solid-state meters also have no mechanical parts and use electronic circuits to measure power. This accuracy enables utilities to improve revenue assurance and provide more accurate billing to customers.
“With the CENTRON meter, we avoided the additional steps necessary to retrofit a meter, thus reducing shop and installation time,” said Tony Pini, Niagara Mohawk senior vice president for customer service. “We now have brand new, state-of-the-art, AMR-ready meters that are more accurate.”
After realizing the initial time and cost savings of the project, Niagara Mohawk officials accelerated the installation process, completing the new meter installation of 1.5 million meters in 18 months, a year earlier than initially expected.
The CENTRON meter has allowed Niagara Mohawk to capture usage data that has never been captured before, which translated into increased revenue.
Malcolm Unsworth, vice president and general manager for Itron’s hardware solutions group, pointed out some other advantages of the CENTRON meter.
“The CENTRON meter is more accurate at loads below 700 watts (light load) and starts measuring energy at lower power levels (5 watts), thus capturing usage that usually goes unbilled,” Unsworth said. “Solid-state meters also eliminate the drifting problems between the meter’s register and the AMR read that could occur with electromechanical meters, again saving money by capturing usage that is generally lost.”
Unsworth also went on the to say that as a rule of thumb, utilities save $1 per meter per year with solid-state meters, thus there is a definite cost savings for Niagara Mohawk and its 1.5 million installed CENTRON meters.
“The accuracy is much higher-like the difference between analog and digital-both work, but one is more precise and catches more usage data,” Unsworth added.
To date, Pini said, “Itron’s solid-state meters have met and exceeded the utility’s expectations. As a result of solid-state metering and AMR technology, Niagara Mohawk has chalked up an 83 percent reduction of labor costs.
“We’ve improved our safety records and are providing more accurate bills, which leads to improved customer satisfaction,” Pini added. “The savings are showing up everywhere from meter reading to the call center. And, using one meter model simplifies Niagara Mohawk’s meter population and inventory management.”
Niagara Mohawk officials were also impressed with Itron’s ability to meet their delivery/installment requirements, often exceeding 100,000 installed units per month, though the contract only specified 65,000 per month.
Transportation costs, uniform costs and medical costs have also been reduced with the use of AMR and CENTRON meters. In addition, bills are now issued monthly in rural New York – previously residents received a bill every other month, which generated more calls and complaints because the amount looked higher than normal.
“The utility has also increased cash flow with monthly billing, while savings are showing up with fewer re-reads and customer complaints,” Pini said.
Capturing more usage data, using fewer employees for meter reads and running the metering system more efficiently due to AMR has sold Niagara Mohawk on the solution it implemented.
“We have an entirely new meter system that is saving us money and more importantly, provides better customer service because of its accuracy,” Pini said. ï£ï£