Tips & News - April 2014

Tips & News - April 2014

ENDURING PRODUCTS AND PEOPLE YOU CAN DEPEND ON. www. hubbe l l powe r s y s t ems . com TIPS NEWS Vol. 18 No. 1 | april 2014

special I EEE Edit ion

In this issue: Northeast Missouri Electric Power Coop Substation Rebuild | TowerPak ® Solutions | Clean Line Energy Project

In This Issue

Changes in Leadership Positions Hubbell for Continued Growth

22 Tips of the Trade: How to Solve Anchor Problems The key to solving a problem with power-installed screw anchors is to analyze what happened when the problem occurred. Studying anchor damage caused during installation tells a great deal about what went wrong. First Foray into Distribution Automation 24 Vectren Energy Delivery makes their first distribution automation project a success with Hubbell’s automated-ready switches.

Our competitive advantage starts with our people. Through ongoing investments in our employees and operations, we are able to drive continued improvements in safety, quality and service.

2013 was an active year for Storm Soldiers; The Untold Story of America’s Other Heroes. More than 7,000 people gathered at tradeshows, industry events and film festivals across the country to watch the documentary. Thanks to overwhelming support from the community, we are able to donate $60,000 to linemen charities. We continue to host screenings for the public and are actively pursuing other mediums for promoting awareness for lineman. If you haven’t seen the movie yet, ask your Territory Manager for a pass to the HPS Hospitality suite in Chicago. Storm Soldiers: A Year in Review


Gerben Bakker President, Hubbell Power Systems, Inc.

Innovative Engineering: Q&A with Johnathan Adams As a product development engineer, Johnathan Adams is committed to developing products that serve our customers. See page 28 to learn more about the product he has engineered to provide innovative solutions for the communications market.

I EEE Ch i cago, I L april 14-17

Message from Gerben Bakker

Bill Tolley, former President of HPS, has assumed the newly created position of Senior Vice President, Growth and Innovation for Hubbell Incorporated. In this newposition, Bill leads the efforts to accelerate growth across all three Hubbell operating units. With the appointment of Mr. Tolley to his new role, Gerben Bakker was appointed President of Hubbell Power Systems, Inc (HPS). During his career with Hubbell, he has held a number of positions around the world in the Power Systems and electrical segments and international businesses, including President, Hubbell Brazil and VP, Strategic Sourcing, HPS. He was named Division VP for HPS in 2009.

Hubbell Power Systems is on a path for continued success, given our commitment to service and operating excellence along with a broad product offering. Our competitive advantage starts with our people. Through ongoing investments in our employees and operations, we are able to drive continued improvements in safety, quality and service.


10 Nothing Lost, Everything to Gain: TowerPak ® Solutions During the tough winters in Alaska, transmission line repair and construction are challenging. Making matters worse, product often gets lost in the snow along the lines. Find out how our TowerPak ® kitted solutions helped Chugach Electric complete their project ahead of schedule with no product lost.


An ambitious substation rebuild overcomes outage limitations and space constraints Northeast Missouri Electric Power Cooperative needed to rebuild most of its Henry substation in 30 days. The work had to be completed in tight quarters, on a short deadline and while the substation was still energized. Chance ® helical piles were the only way to go on this project.

Welcome to the Hubbell Family: Opti-Loop ™

Hubbell Power Systems, Inc. proudly announces the addition of Opti-Loop ™ Fiber Optic Storage Systems (FOS). Opti-Loop FOS fits into our connectors product line, expanding our products and services to the communications market.

In support of our customers’ needs, HPS is well positioned for actionable growth through innovative newproduct development and additional product lines and brands that complement our existing portfolio in the utility industry.




Plastic Enclosures

Grain Belt Express Transmission Project Signs Deal With HPS and Other Missouri Suppliers

PenCell ® PE-20 Underground Enclosure

AG-20 pedestal with a PE-20 base

The Grain Belt project is an approximately 750-mile overhead, direct-current transmission line that will deliver up to 3.5 GW of renewable power from Kansas to communities and businesses in Missouri, Illinois, Indiana and states farther east.



Clean Line Energy Partners has announced agreements to source products and services from Hubbell Power Systems Inc. (HPS) for its Grain Belt Express Clean Line project. The Grain Belt project is an approximately 750-mile overhead, direct-current transmission line that will deliver up to 3.5 gigawatt of renewable power from Kansas to communities and businesses in Missouri, Illinois, Indiana and states farther east. Clean Line says ABB, General Cable and HPS employ a total of nearly 1,000 Missourians, and the project represents an approximately $500 million investment in Missouri. HPS has been designated as the preferred supplier of insulators and hardware for theGrainBelt project. HPSwill manufacture the hardware and the core of the polymer

insulators at its Centralia, Mo., facility and establish a supplier base within the project area to source raw material from local businesses, including companies in Illinois and Indiana, according to Clean Line. To support Grain Belt Express, HPS will invest over $9 million in its Centralia plant. “Clean Line Energy is committed to sourcing as many of the needed materials as possible from local companies in the Grain Belt Express project area,” says Clean Line President Michael Skelly, adding, “Webelieve it is increasingly important to invest in energy infrastructure that will contribute to local economies and create new jobs in communities across Missouri and the region. The Grain Belt Express partnership will create an estimated 52 jobs at the Centralia Facility over the life of the project.

The addition of PenCell ® rounds out the HPS enclosures product line for the electric utility, commercial and industrial, communications and water markets.

Hubbell Power Systems, Inc. is proud to introduce the extension of our enclosures line with PenCell plastic enclosures. The PE-20 underground enclosure works as an underground vault and can be paired with the AG-20 Pedestal to meet grade level needs. PenCell plastic enclosures are offered in a number of sizes, shapes, depths and locking options to meet specific job applications. PenCell enclosures are RUS accepted and are proudly made in the USA. Visit for more information.

Features: • Light weight - easy to lift • Manageable - easily cut conduit entry points in the field • Strong - load ratings of 3000-5000 lbs • Versatile - provides a base for the AG-20 pedestal

- mark mikes, Division Vice present hubbell power systems, inc.




Reprinted with permission from September 2013 issue of TDWorld magazine.



for an outage with ITC Midwest and the Midcontinent Inde- pendent System Operator (MISO). A significant amount of coordination and planning was needed to schedule the out- age, so other substation improvements also were planned. ITC Midwest’s long-term plans included increasing line ten- sions, which would increase the load on the 161-kV tower. Therefore, Northeast Power planned to replace it, as well. Get Ready, Get Set Northeast Power hired V&S Schuler to design and manu- facture the three-bay 161-kV structure and one of the 69-kV towers. CLC Engineering was retained to design the other seven 69-kV towers, which were fabricated by Lehigh Utility Associates Inc. CLC Engineering designed new single-column steel can- tilever towers with one further enhancement. To help speed up the rebuild work, the new towers were designed to handle mechanical load coming from only one side, with no load on the other side. This was recommended so that when workers transferred the lines to the new towers during the scheduled outage, the towers would not be overstressed. The stronger towers also would be able to withstand additional mechanical loads Northeast Power might add in the future. The existing aluminum lattice towers had a 3-ft by 3-ft (0.9-m by 0.9-m) base plate. The new towers had a smaller 1.5-ft by 1.5 ft (0.5-m by 0.5-m) base plate. However, the exist- ing concrete foundations were not adequate for the new struc- tures and loadings. This put Northeast Power’s engineers in a difficult position. Thirty days was not enough time to remove the 69-kV towers, tear out the existing foundations, pour new foundations and set the new towers. An alternative solution was required. CLC Engineering suggested the foundations could be aug- mented and helical piles could be used to support the new foundation sections. Helical piles can be drilled into the soil with a drive motor, and they are faster and easier to install than a traditional poured-concrete foundation. This seemed like a good solution. More importantly, it was the only viable solution, given the scope of work and time constraints. However, Henry substation is not a big, spacious substation. Workers could not get drilling equipment into the south side of the 69-kV foundations because of energized bus work and underground duct work. The only option was to extend the foundations to the east, west and north. While Northeast Power was designing the augmented foundations, it received news from one of its distribution co- operatives that a new fertilizer plant was being constructed in its territory, and the plant would add 35 MW of system load. The utility decided that system stability made installation of a transformer close to the new load the best solution. This was done and allowed the installation of a second transformer at Henry substation to be deferred. The second transformer at the Henry substation is now scheduled for a 2020 installation.

A work crew installs helical piles around three sides of an existing foundation. Henry substation was still necessary; the 69-kV towers had to be replaced and the foundations had to be augmented. This alone would require a significant amount of work. For instance, to remove the aluminum structures, the coop would have to remove several switches, conductor and bus pipe. In addition, Northeast Power planned to replace old control cables, add a 161-kV breaker, add two 161-kV disconnect switches, replace several relay panels and replace wiring in the control building. So, engineering and planning for this work continued. The coop hired a geotechnical firm to perform soil tests and finalized the designs for the new 69-kV foundations. For- tunately, the Henry substation is sitting on about 20 ft (6 m) of good compacted clay. The coop approached Hubbell Power Systems to find a helical pile solution. Northeast Power pro- vided the soil reports, foundation loading requirements and height constraints. Hubbell Power Systems specified which he- lical piles to use and the torque requirements. Work Begins With plans complete, Northeast Power crews began work in the energized substation in March 2013. This included the relatively easy work in the 161-kV yard. The new 161-kV tower was an A-frame and its foundations could be poured beside the existing foundation, in an unimpeded area. On the 69-kV side of the yard, the work was more challeng- ing. The existing 6-ft by 6-ft (1.8-m by 1.8-m) concrete founda- tions were 7-ft (2.1-m) deep. To meet the new load and mo- ment requirements, the foundations had to be expanded to 12 ft by 9 ft (3.7 m by 2.7 m). The main problem, of course, was clearances. The vertical restriction was 15 ft (4.6 m). Hubbell Power Systems specified helical piles with shorter-than-typical lead sections, and Northeast Power used 5-ft (1.5-m) extension rods. Even so, the coop had to be creative when it came to driv-

Tight Times, Tight Spaces An ambitious substation rebuild overcomes outage limitations and space constraints. S ometimes things do not go as planned. Northeast Missouri Electric Power Cooperative (Northeast Power) can attest to that. In 2011, it became clear the coop needed to rebuild most of its Henry substation, transformer. Three 69-kV feeders exit the substation, but there are eight 69-kV deadend structures: one feeds a capaci- tor bank, one is a transformer low-side breaker bay and the others are for future expansion. Workers drive in helical piles to augment a 69-kV tower foundation at Henry substation. Helical piles were the only way to go on this project. The work had to be completed in tight quarters, on a short deadline and while the substation was still energized. By Jamie Page , Gary Wood and Kevin White , Northeast Missouri Electric Power Cooperative

The substation was built in the 1980s and the transformer was 1973 vintage. System studies showed if that transformer failed, voltage regulation in the area could be a problem. In the existing system configuration, Northeast Power needed a second transformer at the substation. Plans were made to add another transformer and install heavier 69-kV conductors, an additional static wire and flying taps. Thus, the 69-kV substa- tion structure towers would have to support a greater load and increased over-turning moment. When the transformer was added, the towers would have to be upgraded, as well. With an idea of what the scope of the work would be, the next step was to schedule an outage. Because the substation is in a critical area, the coop could only get an outage when the load was low — in the spring or fall. Northeast Power de- cided to perform the work in the spring of 2013 and arranged

but it could only schedule a 30-day outage to do so. To get the project done within the limited outage time, the coop had to do as much work as possible prior to the outage. One of the biggest challenges was finding a way to upgrade eight 69-kV foundations while the substation was still ener- gized. Dealing with planning changes, downpours, late frosts and a transformer failure made the job all the more difficult. Scope and Challenges Northeast Power is a generation and transmission coopera- tive, serving eight member-distribution cooperatives in north- east Missouri and southeast Iowa. It has 56 employees. The coop’s Henry substation is located in a critical growth area where voltage sag is a problem. Two 161-kV lines, from ITC Midwest, LLC, power the substation and its single 56-MVA

How to Augment a Foundation Even without the transformer installation, work at the

September 2013 |

September 2013 |






Acknowledgement The authors thank Lee Goen, senior Chance anchor- ing application engineer, Hubbell Power Systems, who was helpful in selecting a helical pile solution that met Northeast Power’s clearance and load requirements for this project. Jamie Page ( is a professional engineer and has worked for Northeast Power since 2008. Previ- ously, he was the city engineer for Hannibal, Missouri, U.S. Gary Wood ( has worked for Northeast Power for more than 30 years. He started out as an apprentice lineman and, over the years, has moved up to line- man, assistant superintendent of lines and, finally, operations manager. Kevin White ( is a professional engineer. He joined Northeast Power in 1993 as substation and metering manager. He became manager of engineering and operations in 2006.

Horseshoes and Porcupines Each horseshoe-shaped foundation addition is supported by four helical piles: two along the east side and two along the west side. Workers drove the piles in until 12,000 ft-lb (1600 m-kg) of torque was achieved. Then they cut off the top of each pile, 1 ft (0.3 m) below the future concrete surface and welded-on metal caps. To transfer the shear forces from the new section to the existing foundation, Northeast Power designed a sys- tem of dowels. Workers bored 12 horizontal holes 12 inches (0.3 m) deep into each side of the existing founda- tions, for a total of 36 per foundation. Crews inserted 2-ft (0.6-m) sections of 7 / 8 -inch (22.2-mm) rebar in each hole to tie the whole thing together. Workers noted that, from a top view, “The foundation looked like a big porcupine.” The only minor problem encountered during the instal- lation of the 69-kV foundations was solved with a hammer. Before driving in the piles, workers made up steel cap plates, with precut holes, to slip over the top of the rod. But the top sections of some of the pile extension rods got a bit out of shape after being torqued into place by the digger-derrick au- ger motor. The malformation of the extension rods was not significant and workers hammered the cap plates on success- fully. The concrete mixture was adjusted to speed up the cur- ing process and ambient temperature was watched carefully. March is typically cool in Iowa and the temperature fell be- low freezing a few times. When this happened, Northeast Power used insulated blankets over the freshly poured foun- dations. By the time the Henry substation was de-energized, on April 29, 2013, 95% of the foundation work was completed, most of the conduit was installed and some of the ground- ing was done, as well. It is worth noting that, while crews were hard at work in the substation, line crews were systematically inspecting and preparing the lines, so they would be in per-

was dead. Now, in addition to the scheduled work, Northeast Power also had to replace the transformer. The unit was sal- vaged and a spare was installed during the scheduled outage. This added to the workload significantly. One other unplanned job was completed during the first two days of the outage: crews temporarily connected the sta- tion’s 28-MVAR capacitor bank to the 69-kV system with an emergency tap. This last-minute decision was made to provide the utility a comfort factor — in case there were any system voltage problems — while the substation was out of service. A Fine Result This was one of the most complex projects Northeast Power has tackled. All of the work and engineering was done in-house, with the exception of the steel design. Getting ev- erything done required the support and assistance of every department and person in the cooperative. The substation was reenergized on May 29, 2013. Everything was completed on schedule.

ing equipment. A digger-derrick truck was brought in instead of a larger piece of equipment. Workers had to remove the Kelly bar from the auger and then attach the torque indicator and instal- lation tool directly to the motor shaft. This helped with the clearance issues and gave workers a couple of feet to spare. Nevertheless, the coop had to de-energize and remove the 69- kV transfer bus to begin the foundation work. Also, energized 69-kV circuits had to be de-energized on an individual basis to allow crews to complete the helical pile installations one foundation at a time. At that point, Northeast Power was facing time constraints and unfavorable ground conditions. Loads, which were normally loop fed, were placed on radial feeds. Once the piles were in place, work proceeded faster, but the spring weather caused a few problems. It rained every other day. The foundation holes filled up with water and had to be pumped dry on a daily basis. However, the damp soil seemed to make it easier to install the helical piles. After the helical piles were cut and capped, workers added the rebar dowels and built the concrete form. This foundation is ready for the modified mix of concrete.

Companies mentioned: CLC Engineering | Hubbell Power Systems ITC Midwest | MISO | Northeast Power V&S Schuler | Companies mentioned: CLC Engineering | Hubbell Power Syst ms | ITC Midwest | itc-holding .com MISO | Noreast Power | V&S Schuler |

fect condition during the sched- uled outage. Crews trimmed back trees, and inspected poles and hardware. In one case, a danger pole was guyed before the outage (it has since been replaced). Then the Transformer Failed A month before the sched- uled outage, the single 56-MVA transformer at the Henry sub- station tripped off-line and blew gas out of the load-tap changer (LTC) compartment. Workers ran a Doble test and dissolved gas analysis on the unit. It did not look good. Northeast Power ini- tially thought only the LTC had faulted, but, through testing and evaluation, determined the unit

1 year April 18, 2013 – April 18, 2014

sold nearly 5,000 copies of the book/DVD combo, and other merchandise

raised $60,000+ for linemen charities

awareness More than 7,000 people have watched the movie

This smooth finished foundation covers all the work involved in the installation of helical piles that were used to extend the foundation from its original dimensions.

Support a lineman today, visit

September 2013 |



“ The Quartz Creek line is critical because it is the only transmission

line connecting the two dams to the rail-belt. “

- shawn wendling

- by patricia irwin, PE

In Alaska, the 115-kVQuartz Creek transmission line connects two hydroelectric dams on the Kenai Peninsula with the ‘rail-belt’—an area containing Alaska’s railroad, its most populous cities and about three-fourths of the state’s population. A fifteen mile section of that line was rebuilt last November, in an area where snow storms regularly drop feet of snow throughout the winter. While not a technically challenging project, Hubbell Power Systems TowerPak ® solution was a great benefit. The hardware arrived on time, properly kitted and… nothing got lost. This is a big deal when you are working in a snowy mountain pass in Alaska in the winter. The Quartz Creek line is 90-miles long and is operated by the state’s largest electric utility—Chugach Electric Association, based in Anchorage, AK. Shawn Wendling, senior project manager, explains thesituation. “The linewasoriginallybuilt in 1962 to connect the Cooper Lake Dam to the rail-belt. In 1991, the state brought online the substantially larger Bradley Lake Hydro Project, which also uses the line. The Quartz Creek line is critical because it is the only transmission line connecting the two dams to the rail-belt and because that generation is our cheapest source of power. It is also important because we use our hydro resources to adjust for system variances, so that gas consumption at our combustion turbines stay on schedule.” The line and its structures are now over 50 years old and the cooperative keeps an eye on structure integrity. In 2007, Chugach performed a detailed helicopter survey, which revealed some deterioration of the wooden, H-frame towers. The cooperative then verified the damage with a climbing survey. “During the summer of 2008, we sent crews down the right-of-way and tested the arms and poles. About 50% of the poles surveyed showed signs of rot,” explains Wendling.

TowerPak ® solutions: Nothing Lost, Everything To Gain




Wendling points out, “As the project engineer, the first things that come to mind for any project are design, permitting, and materials delivery. I asked myself, which is going to take longer? In this case, we started the permitting early and the design wasn’t too complicated. But make no mistake, because we are on the far end of the world, supply chain logistics never fall far from our gaze.” Permitting and Recreation Overall, permitting took about a year. The State Department of Natural Resources controls a little over a third of the land. The US Forest Service controls the rest. “You could say the whole right-of-way is an environmentally sensitive area, but the main challenge was recreational use. The middle five miles of the project are in one of the prime winter recreation areas for South Central Alaska. One side of the road is used by snow machines and the other side offers exceptional, backcountry skiing. There were a lot of recreational users out there, who ‘recreated’ right where we needed to be working. So, there were a lot of stakeholders to respond to and bring into the process,” says Wendling. A large portion of the project’s success can be directly tied to Alcan Electric and Engineering, Inc. in Anchorage, AK— the company that built the line. Alcan’s communication and outreach efforts to the various recreational user groups were extremely helpful. Thoughtful Design On the positive side, the lengthy permit process provided ample time for Chugach to carefully plan and design the new towers. The cooperative worked with a local design firm Dryden & LaRue, Inc. (D&L), Anchorage, AK. Since a long-term planning study called for the transmission line to be at 230-kV instead of the existing 115-kV, the line was rebuilt and insulated for 230-kV. Also, considering recent record snow falls, some towers were significantly increased in height. “We added between eight and 20-feet, where needed, to provide increased clearance during heavy snow falls. Before construction, the average height of the structures in this section was 65 feet. It is now approximately 95 feet,” reports Wendling. To limit structure weight, about a third of the wooden structures were replaced with steel. Wendling explains, “We wanted to make sure this project could be built using helicopters, if necessary. The biggest wood poles needed could weigh as much as 9,000 or 10,000 pounds. So, we substituted steel poles. As it turned out, Alcan Electric did not use a helicopter. Because of the substantial snowfall during the winter 2012-2013, Alacan was able to build roads and drag in the materials.”

All photos provided by Chugach Electric Association

A view down the right-of-way of a 90-mile, transmission line that runs from Kenai Peninsula to Anchorage Alaska

Although in need of repair, the towers were still intact. “Interestingly, in the winter of 2011-2012, before we started working on the line, we had a very bad winter. In total, over 11 feet of snow fell in Anchorage, but, I’ve got to say, in the mountains we got more than that. We had structures bent over like a fishing rodwith a King Salmon on the end, but they held despite the deterioration. It is a testimony to the quality of wood we used back in the day— clear, good grained, old- growth wood. That winter, we lost one arm and one pole— that was it,” mentions Wendling. Careful Planning Knowing that a substantial amount of work needed to be done, the cooperative divided the project into immediate and long-term repairs. In 2008 and 2009, Chugach operations personnel addressed a list of critical jobs to ensure short- term reliability. During that same period, planning and engineering identified and prioritized the line sections that were in the worst shape.

The first goal was to replace the most critical, 15-mile section, which happened to cross through the toughest terrain. (The 90-mile line crosses a mountain range, bends around a body of water, jumps back through the Chugach Mountains, to find its way to Anchorage.) In Alaska, public funding is available at times to help mitigate the cost of rebuilding critical electrical infrastructure, but the process to obtain public funding is indeterminate. In some cases, funding is obtained in a calendar year. In this case, funding for the Quartz Creek rebuild was a two-year effort. Chugach got the money in July of 2011 and immediately began the permitting and design process. Even at this stage, the cooperative knew that the work would have to be performed during the winter months, when snow roads could be built. (Snow roads mitigate environmental impact and provide access.) It was clear from the beginning that the rebuild was going to be challenging.

Sturdy, high-profile Tower Pak ® Transmission Kits in the staging area



Chugach received 112

meter claw & safety shield

nylon thread pin Bracket

full range conductor gauge

TowerPak ® Kits – one box per

Wendling asked that all parts be put in sealedboxes thatwould hold up to the weather and be durable. In the end, Hubbell was the low bidder through their suppliers in Anchorage: Potelcom and WESCO. The cooperative placed the order in October of 2013 for delivery by the end of the year. Despite a big winter storm hitting the East Coast of the Lower 48, everything was delivered on time. “I wanted to streamline the shipping, because shipping things from anywhere to Alaska is an opportunity for something to get lost. Things get lost during shipping. Parts get sent to the wrong destination—like Alabama (AL) instead of Alaska (AK). Or the delivery misses the barge. Or, the shipper has never come this way and isn’t familiar with road conditions, permitting requirements, and clearances. If you were to ask me how many ways things can go wrong…I don’t think I have enough fingers and toes to count them,” says Wendling “So, I wanted to mitigate the shipping risk by dealing with one supplier that could really put everything together in one consolidated shipment.” This project took place in a mountain pass in the middle of winter, where storms routinely dump one to two feet of snow on the ground. “Looking for anything in a foot of snow is difficult. It is the proverbial needle in a haystack. Remember, a foot or two of snow is deep enough to hide a 2’ x 2’ cardboard box. Further, cardboard boxes get wet and fall apart and once a part is out of whatever container it came in, then you’re in trouble,” warns Wendling. TowerPak solved that problem as well. Chugach received 112 TowerPak Kits — one box per tower and a few extra. None disappeared into the snow. Then there is the snow.

tower and a few extra. None

disappeared in the snow.

Crews started, cleared and staged on November 6, 2012, and re-energized the line on April 16, 2013.

Which brings us to TowerPak ® Kits. The cooperative broke the project into four purchases: conductor, wood poles, steel poles, and line hardware. The first three were commodities and arrived in three big shipments. For example, the 168 wooden poles that arrived by rail (close to the site), were trucked to the work zone and staged along the way.

crossarm link stick

5H ball stud grounding system

low-voltage rubber gloves

The fourth purchase order was different.

“I thought it would be great if all the other parts and pieces could be delivered in one shipment, already kitted. We’re talking about specific insulators and hardware. In some cases, we are talking about hardware that was manufactured especially for the project. I wanted to find a way to get all the parts delivered conveniently and efficiently,” explains Wendling. Wendling remembered an article about TowerPak in Hubbell’s Tips and News magazine. “I dug into it a little bit more and found out that TowerPak isn’t usually applied to projects as technically simple as the one we were embarking on. There was some skepticism at the co-op as well, because we’d never done anything like it before. I wanted to make sure that I understood it, so I went out and talked to a number of suppliers and other wholesalers who do kitting. Hubbell was the only manufacturer I found that did it. Some of the wholesalers I approached didn’t think this project was big enough for them to bother with. Regardless, we put together a spec to containerize all the pieces (the insulators, hanging hardware, and the connecting hardware) we thought we would need on each structure.”

cotton liners

canvas glove bags

leather protectors

As a result, the work finished ahead of schedule, with no equipment lost.

To ThoseWho Climb ™

Special thanks to Shawn Wendling, Senior Project Manager, Chugach Electric.

Visit to see our new lineman grade products.




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ELECTRO COMPOSITES ™ SDC ® BUSHING FEATURES • SDC ® composite bushing designs up through 170kV – 650kV BIL • GSU Step-Up Transformer bushing designs up through 34.5kV – 22,000A • Solid Dielectric Capacitor (SDC) one piece capacitance graded epoxy cores (oil free) • High Temperature insulation and gaskets rated for operation up to 130°C (GSU) • GSU bushings designed for isolated-phase bus duct applications • Full copper conductor and terminals for GSU models • Vertical or Horizontal installation • Rated & tested per IEEE/ANSI, CSA or IEC • Standard models and “As Existing” dimensional replacements • Made to order with the shortest lead time in the industry SDC ® GENERATOR AND SYNCHRONOUS CONDENSER BUSHING FEATURES • Bushing designs up to 30kV and up to 30,000A • Solid Dielectric Capacitor (SDC) one piece capacitance graded epoxy cores (oil free) • High Temperature insulation and gaskets rated for operation up to 130°C

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• Designed for hydrogen cooled apparatus • Rated per IEEE/ANSI, CSA, IEC or DIN 48124 • Made to Order “As Existing” form, fit and function replacements • Generator bushing inspection, testing and repair services OTHER AVAILABLE PRODUCTS • Isolated-phase bus duct Seal-Off bushings

• Bus support insulators up to 34.5kV • Fiberglass sheet motor core insulation

PCORE ® ELECTRIC PCORE ® PRC ® BUSHING FEATURES • Bushing designs from 15kV through 69kV per IEEE/ANSI or CSA Standards • Paper-Resin Capacitor (PRC) design • Transformer-Breaker Interchangeable ‘TBI’ • Qualified to the HIGHEST level of the IEEE 693 Seismic Standard by the static pull test • Standard with high creep upper porcelain • Vertical or Horizontal installation PCORE ® POC ® BUSHING FEATURES • Bushing designs from 25kV through 500kV per IEEE/ANSI or CSA standards • Paper Oil Capacitor (POC) design • Transformer-Breaker Interchangeable ‘TBI’ • 25kV-69kV qualified to the HIGHEST level of the IEEE 693 Seismic Standard by the static pull test • 115kV-500kV qualified to the HIGHEST level of the IEEE 693 Seismic Standard by the time history shake-table test (includes qualification by group) • Standard with high creep upper porcelain • Vertical or Horizontal installation PCORE ® SET-TERMINAL FEATURES • Seismically Enhanced Test (SET) Terminals • SET-Terminal designs from 1,200A through 5,000A • Used for FASTER, SAFER & more COST EFFECTIVE dielectric testing • Rated static cantilever strength of up to 2,500 ft-lbs. • Can absorb high shock loading in excess of 500g’s OTHER AVAILABLE PCORE ® PRODUCTS & SERVICES • PRC ® and POC ® Quick–Link bushings • Bushing Testing & Repair Services of almost all manufacturer’s bushings designs up through 500kV

Electro Composites offers SDC ® solid dielectric capacitance graded composite bushings up to 170kV for transformers, circuit breakers, generators, wall/floor and other applications, and epoxy moulded components for a variety of applications. PCORE offers a wide range of bushings, including 15kV-69kVPRC ® and 25kV-500kVPOC ® , and cost- saving products such as bushing Test Terminals, Bushing Repair Services and the patented Quick Link Bushing.

With energy demand continuously increasing, adding further stress and wear on already aging power generation assets, energy providers are faced with finding reliable cost effective solutions to keep their equipment running while also being able to extend their useful life. PCORE Electric and Electro Composites offer a wide range of bushings for generators, synchronous condensers, power transformers, “GSU” step up transformers, circuit breakers and switchgear, as well as related components and services. With over 75 years of combined field experience, PCORE and Electro Composites are always available to support your operations with industry proven products and the best customer service in the market.

Product Offereing HV & LV Bushing evaluation, testing and repair | PCORE ® Bushing Test Terminals | SDC ® Replacement generator bushings SDC ® GSU transformer bushings | SDC ® & POC ® high-temperature bushings Electro Composites™ Isolated-phase bus duct bushings and insulators | SDC ® , PRC ® & POC ® seismically certified bushings

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how to solve anchor problems

During the rare time there is a problem installing power-installed screw anchors (PISA ® ), turn the bad experience into a benefit to avoid similar troubles in the future. The secret is analyzing exactly what happened when you encounter a problem. Look at tooling anchor damage caused during the installation. The damage can tell you a great deal about what went wrong, so the improper action is avoided in the future.

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specifically, the Type A fracture (Figure 3) is not necessarily indicative of brittle shaft material. In fact, we never see such a fracture that was due to brittle shaft material. It is true that for pure torsion, the Type A fracture would be typical for a brittle material while a Type B fracture (Figure 3) would be typical for a ductile material. However, without engagement problems, virtually all shafts fracture close to a helix where stress conditions in such areas include the non-axisymmetric structure (helix projecting from one side of shaft) and non-homogeneous material (shaft parent metal, weld filler metal, helix parent metal, zones of intermixing, and heat-affected zone). End restraint effects from wrench engagement and bending moments resulting from failure to maintain alignment or the anchor’s striking obstructions in the ground may also affect the stress conditions. The result is that the stress conditions causing fracture are triaxial, not torsional and Type A fractures are neither unusual nor indicative of brittle material. There are claims that a helical-end wrench, which engages the anchor shaft along the upper helix surface, increases the torsional capacity of the anchor by forcing it into a Type A fracture which naturally has a larger fracture surface area than a Type B fracture. Actually, such wrenches offer little practical advantage because most of the time they merely force anchors to fracture the way they would anyway. If you rule out wrench engagement problems, there are still a couple of possibilities left. If the anchor seems to be encountering obstructions, or the operator does not seem to maintain alignment, impact loading or excessive bending moments may cause the anchor to fracture at reduced torque. Try the same type and size anchor again but with slower rotation speed and additional operator care. If, on the other hand, the soil seems homogeneous and the alignment is maintained properly, try a smaller or higher-strength anchor. Remember that installation torque is an indication of soil strength, so if the torque is higher than expected, the soil must be stronger than expected and a smaller anchor should develop the load.

One of the most common problems, particularly with PISA ® anchors, is an anchor shaft fracture during installation. Because driving effort is transmitted from the anchor installing wrench to the anchor helix via the anchor shaft, if shaft stress exceeds the shaft’s ultimate strength, the anchor shaft will fracture. Fractures are not pleasant occurrences, but they tell you a great deal about what happened and what you need to do to prevent it from happening again. If you experience a fracture, recover at least part of the anchor shaft and observe the fracture surface. This is usually quite easily done; just withdraw the anchor rod, and you should find the top part of the anchor shaft still attached.

its hollow section, that section becomes the weak link in the system and fracture occurs well below the anchor’s rated torsional strength. To avoid a recurrence, use the same type and size anchor, but be sure to screw rods all the way into the anchor and couplings; lock the anchor assembly into the wrench with the locking dogs; and follow the anchor during installation maintaining proper down pressure at all times. Fracture problems occur with the Square Shaft (SS) anchor if the anchor shaft is not pinned into the wrench, couplings are not properly bolted up, or they are subjected to gross misalignment. A possible reason for misalignment is leading off after encountering a hard stratum at an oblique angle or obstructions in the ground. In either of the first two cases, the shaft tends to work its way out of the wrench or coupling. Once it gets far enough out that the drilled section is loaded torsionally, it breaks well below its rated strength (see Figure 2 below).

In the third case, the bending moments at the joints cause gradual “belling out” of the coupling (see Figure 2 below) again leading to torsional loading of the drilled section and rating. In all cases, the fracture surface intersects the drilled hole. In the latter two cases, failure usually occurs below the ground line and only visual inspection of the coupling shows the difference. To avoid recurrence, make sure that the coupling bolt goes through both coupling and shaft, rather than passing above the shaft end. Pin the top shaft into the wrench during installation, and avoid misalignment along the anchor shaft or between anchor and Kelly bar. If a hard stratum at an oblique angle to the anchor’s path is the problem, change the anchor batter so that the angle is closer to 90 degrees if possible, or stop down pressuring the anchor as it reaches the stratum and allow it to auger a “pocket”, which will counteract the tendency to lead off. In obstruction-laden soil, be prepared to remove the anchor, move over, and try again if the anchor starts leading off.

If the fracture surface intersects the drilled hole in the shaft (see Figure 1 below), insufficient wrench engagement was the problem.

The PISA ® anchor/wrench system is designed so the wrench, when properly engaged, bridges the hollow section of the anchor shaft, preventing it from carrying any significant torsional load. If the wrench does not engage the anchor shaft sufficiently to bridge

figure 2

figure 3

figure 1


In the absence of engagement problems, the appearance of the shaft fracture surface is not of much significance.

The fractures shown (Figure 3) are typical for solid shaft anchors like the SS (Figure 3). Contrary to common belief, there is no practical difference in these two types of fractures; more





First Foray Into Distribution Automation Sw i t c h Au t omat i o n

- by Brad Adelman, Substation Automation Engineer, and Allen Collins, Electric Standards Engineer, Vectren Energy Delivery




In the old configuration, if we lost either feeder, 750-800 customers were without power until a trouble-crew drove out to open and close the switches to isolate the outage and restore power.

The newly automated switches have mesh radios and an RTU installed in the motor operators that communicate with the master radio at the substation. The substation then forwards the information to the dispatch center via the fiber. In addition to the radio system, we installed SCADA-enabled fault current indicators (FCI) on either side of the switches. They communicate wirelessly with the RTU and provide information such as load current, voltage, and fault detection (among others). With this data, the Dispatch Operator is able to make intelligent and fast-response decisions. Distance: Since Libbert Substation is remotely located from our central office, we expect this projectwill reduce restoration time due to the reduction in driving times. Of course a crew is still needed to make repairs, but the switches can quickly minimize the size and the duration of the outage. In short, we wanted to get our feet wet before we went swimming, and Libbert was the perfect place to try new DA technology. Bigger Plan Once we knew what we wanted to achieve and decided on a location, the next step was selecting the motor operators. We used Hubbell’s AR switches for ten years and view Hubbell products at different conferences. Additionally, the Hubbell representative brought the ‘roadshow’ trailer to show us the equipment. Given this familiarity, it was practical to use an operator that we knew would work with our switches. We purchased six operators in June of 2013, through Hubbell from Cleaveland Price in Trafford, PA. We installed them in November and commissioned them in mid-December in 2013. As currently configured, the switches provide outage/load information to the dispatch center, and a Dispatch Operator makes the decision to operate the switches or not. The system intelligence is expandable so that the system can be fully automated (ie self-healing) in the future, if desired.

This was an advantage not considered. If a fault happens on certain nearby circuits, we can dispatch a trouble-man to just one location instead of two. It cuts the outage time by about 15 minutes. Overall, we are quite pleased with our first DA project. The system is definitely affordable, and we hope to recoup our costs within three years. Further, we plan to do a similar project in 2014.

We wanted the project to add immediate value, as well as provide a barometer of how other DA projects would impact our system. The chosen pilot project included automating switches on two circuits out of the newly constructed Libbert Substation. Here is why. Load and System Configuration: Libbert is a new SCADA- equipped substation serving a primarily suburban area with residential and commercial customers. Two, three-phase feeders come out of Libbert (Camelot and High Point) and each circuit serves about 750-800 customers. Both are loop feeders since they tie with circuits from other substations through normally open switches. In the old configuration, if we lost either feeder, 750-800 customers would be without power until a trouble-crew drove out to open and close the switches to isolate the outage and restore power. Portions of both circuits are vulnerable, especially to trees, and much load growth occurs in that area, making circuit capacity a concern. In fact, the substation was built to help serve the growing load. SCADA and Communications: Although only about 50% of Vectren’s 93 distribution substations have SCADA today, Libbert Substation circuits were chosen for the DA pilot because two of the three area substations are also SCADA-equipped. Using equipment at these neighboring substations, we can monitor the Libbert feeders within the pilot area. This was a major factor in our decision for selecting a pilot location. The transmission lines into Libbert were constructedwith OPGW (Optical GroundWire) which serves as the static for the lines and enables high speed communication via the fiber optics inside the cable. With this fiber back-bone, available bandwidth exceeds immediate needs. Since this was a pilot project, the probability of wanting additional monitoring points in the future was high. From a data capacity standpoint, this is not a problem.

Although our transmission system is fully automated, the electrical distribution system at Vectren Energy Delivery (based in Evansville, IN) is not. Our first foray into Distribution Automation (DA)—adding remotely operated motors to sectionalizing switches—took place in the fall of 2013, and we are already reaping unexpected benefits. Location, Location, Location Vectren is an investor-owned gas and electric utility that serves ~142,000 electric customers in southwestern Indiana. Part of our responsibility is being prudent in our use of funds, so we chose the location for our DA pilot project carefully.

Remotely operated sectionalizing switches. The switches communicate with the substation via a mesh radio system.

The system is definitely affordable, and we hope to recoup our costs within three years.

To date, we operated them once.

In January 2014, during bitterly cold weather, a cross-arm on an adjacent circuit failed. We were able to transfer load onto one of the newly automated circuits. Since the outage was not on the automated circuit, a trouble-crew was sent to isolate those customers first. Dispatch was then able to remotely close one of the new switches to transfer the load to restore power.




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