Growth is good when managed well, and this is especially true for transmission and distribution systems. United Power (Brighton, Colorado), a Touchstone Energy cooperative, brings electricity to approximately 80,000 people throughout Colorado’s front range, extending from Coal Creek Canyon to Golden Gate Canyon and northeast to Keenesburg.

United Power’s beginnings as a rural electricity provider and its rapid growth over the last 15 years—particularly through acquisitions—inform and necessitate a proactive approach to managing our T&D system. Each acquisition and territory exchange has added customers, cities and its legacy T&D assets to our own; and each expansion drives home the importance of system-wide consistency and accurate system mapping to facilitate interconnection, efficient expansion and optimal reliability.

In 1990, United Power acquired a system with two fundamental differences from our own. Our distribution voltage was 12.47 kV and wired in positive phase rotation; that is, our phasing was A, B, C. By contrast, the newly acquired system was at 13.2 kV and was wired as C, B, A. Voltage differences can be remedied with voltage regulators and, in some situations, are acceptable. The discrepancy in phasing, however, would keep us from connecting the acquired system to our own.

Overlapping Legacy Systems
Maintaining the two systems separately would mean that, in every case of a problem requiring a shift of customer load from one system to the other, United Power would be forced to perform a so-called “drop and pick.” That is, we would have to de-energize the lines, shift the customer load and then re-energize the lines, thus causing a momentary outage (less than 1 min) to the customer.

Beyond perpetuating this inconvenience to the customer, the two-system setup would become increasingly inefficient in terms of our overall T&D assets, specifically related to new line and substation builds. As United Power’s service area grew, the two systems expanded closer to each other and eventually overlapped. In fact, in some neighborhoods, the two different systems were actually strung on opposite sides of the same street. Tying these systems together would greatly increase service reliability for our customers while avoiding the expense of building miles of line to loop around the service area.

Planning for Savings, Reliability
In a meeting concerning updates to United Power’s long-range plan in February 2004, the engineering staff, including Don McDaniel, Dean Hubbuck and John Samuel, began the discussion of correcting the phase problem before summer. With the assistance of the consulting firm Electrical Systems Consultants (Fort Collins, Colorado), we updated our plan to include a recommendation to address the phase problem, presented it to senior management and won approval.

We had a strong case: By following our recommendation to reconcile the phasing on the two systems and install switches to make them parallel, United Power would save approximately $1.5 million that otherwise would be spent over the next two years on substation equipment and operations to maintain the two systems separately. Specifically, two new planned substations would each require one 12.47-kV distribution system with positive rotation and a second 13.2-kV distribution system with negative rotation. Each system would require its own transformer and bus as well. All told, accommodating both systems in this manner would represent a significant extra expenditure—and for a setup that would not provide optimal reliability and service for our customers. Reconciling the phasing would allow us instead to design each new substation with a single distribution-voltage bus.

Evaluating Options
We had considered another option, which was to install phase-shifting transformers at the open points between the two systems. These transformers, however, would have to be specially ordered for the application and, at the capacity required for our load transfer, were too large physically to be practical on our system. They also seemed more of a stop-gap measure than a permanent solution, and we felt strongly about implementing a true correction.

We chose to change the phase rotation of the acquired system to match our own. Reconciling the phasing between the two systems would require first accurately identifying the phase on each line at a connection point, verifying the transformer winding connections, determining the phasing on the distribution side and then determining the correct connection to accomplish identical phase rotation between the two systems. We had heard about phase-identification tools at various trade shows and decided to evaluate and choose between two commercially available systems as a way to significantly speed up—and most importantly be certain of—the phase identification and verification processes. We evaluated the AP-10 from Avistar Inc. (Albuquerque, New Mexico) and a competing product. The AP-10 worked reliably and was well-designed, durably constructed and easy to use. It also had fewer components and better packaging than the competing product, making it easier to handle in the field. When the competing product broke during the demonstration, we settled on the AP-10.

The AP-10 determines phase and phase angle by measuring the delay between the zero-crossings of a known phase at a substation and those at the point of interest out on the system.

The user takes the AP-10 hotstick attachment and portable field unit to the point of interest and touches the AP-10’s hotstick attachment to the energized line or test point. This triggers the field unit to report the phase and phase angle, typically in a few seconds. The field unit uses a built-in cell modem to contact its reference unit back at the substation to calculate the phase, but it also works outside of cell-service range, storing a reading for an hour so that the user can return to cell range. When the unit senses cell service, it automatically completes the call and the phase calculation with no effort on the user’s part. We liked how easy it was for one person to use, with no cables to trip over and no need for additional personnel at the reference substation.

Minimal Customer Impact
After acquiring an AP-10, United Power scheduled the project to begin in April. This enabled us to beat summer loading conditions, per our original intent to minimize the impact on our customers. We started the project by spot-checking the phasing throughout the system to verify that our system maps were accurate. The AP-10 made this a one-day task and eliminated any guesswork, which gave us great confidence in the success of the overall project.

We then verified the transformer winding and determined that to correct the phasing, we would have to swap the A phase and C phase connection on the transmission side and also on our distribution system. In this part of our system, the transmission equipment is owned and operated by Xcel Energy, so we submitted a request through our transmission and generation company, Tri-State Generation & Transmission Association, to coordinate the phase swap. With their approval, we began our construction plan for correcting the three existing substations that were connected as C, B, A. Because we were reconnecting the system, correct phase rotation was critical to ensure that, for example, any motors powered by the system would run in the correct direction rather than in reverse, which can cause tremendous problems for customers.

To guarantee correct rotation, we installed a temporary three-phase transformer in each of the three affected substations. This allowed us, prior to transferring any customers onto the newly connected system, to verify positive rotation at the transformer with a phase-rotation meter. By shifting load to other substations within the distribution system and to dual-transformer substations, we freed up half of each substation and began the phase-swapping process.

Making the Swap
The transmission company chose a remote location at which to swap the phases using a vertical structure, saving time and expense for both parties. Without a phase-identifying tool, we might have hesitated to perform the swap in a remote location; the AP-10, however, enabled us to identify the phases and made clear which phase had to move. Insulators mounted vertically on the pole at a corner allowed easy swapping of phases A and C by splicing connectors and helped avoid additional large material costs. The alternative—to perform the phase swap at the substation site—would have required the costly addition of two transmission structures.

After we completed the work and checked the rotation, we verified that both systems matched and that their phasing was correct. We could then parallel the systems. Without a phase-identification tool like the AP-10, our process would have been one of trial and error. We would have had to build a switch pole to parallel the two systems, then energize both sides of the switch. Using a phasing stick, we would have checked phasing across the switch. If the phases did not match, we would have had to de-energize the switch, swap the conductors, and then re-energize and recheck the switch, continuing this cycle until the phases matched.

Instead, using the AP-10, we were able to travel to the 12.47-kV system and take phase readings directly. As expected, the phasing matched, so we continued with the project. At this point, half the substation was configured with negative rotation and the other half positive, and all of the customers served by that substation were being fed from the negative-rotation system. Working early on Saturday mornings to minimize customer impact, we switched the load to the positive-rotation system over the course of April. With the open of a breaker on the negative system and the close of the breaker on the positive system, we transferred each feeder, and the approximately 7000 total affected customers were back on after an outage of just seconds. We then completed the phase swap on the second half of the substation and, using the AP-10, verified the phasing and restored the substation and feeder to their normal configuration.

Huge Time Savings
Without a phase-identification tool, this project would have required more manual effort and time-intensive verifications to ensure that the results matched our intent. The AP-10 gave us the ability to test phases quickly and move forward confidently with each reconnection. Finally, without such a tool we could not have completed the project by the end of April.

Based on the success of this project, we are moving ahead with a longer-term, more-ambitious effort: to open every underground-distribution cabinet in our system and test, verify and label all of the lines. This will involve many line personnel using the AP-10, but our experience thus far indicates rapid training and deployment.

Reliability, Savings and Confidence
We have high confidence in the AP-10, and we continue to find new uses for it. In fact, we have phasing issues dating as far back as the 1920s that we intend to address with this tool, along with more recently discovered issues. For example, we have had problematic phasing at a particular substation in the system for some time. We had tried repeatedly to correct the phasing and rotation using phasing sticks—and trial and error. With the AP-10, we were able to quickly and positively identify the transformer connection and now have plans to correct it.

Having the right tool for the job was a big factor in timely completion of a project that will save United Power more than $1 million, simplify maintenance as we go forward and improve system reliability for our growing customer base.

Matt Scheppers is an engineering supervisor with United Power, where he has spent two of his 12 years in the power industry following a BSEE degree from Colorado School of Mines. He has worked extensively in distribution substation design, relaying, load flows/short circuit and planning. He has been a member of IEEE for 12 years and has had his PE license for eight years.