Land developers asked El Paso Electric Co. (EPE) to reroute a portion of a radial 115-kV transmission line that feeds the town of Hatch, New Mexico, U.S., for aesthetic reasons. The old transmission line was obscuring the magnificent pinnacles of the Organ Mountains.

Rerouting the 115-kV transmission line with no customer interruptions was going to be a challenge, considering it was a radial line in a remote area with no other high-voltage sources nearby. After some resourceful brainstorming, EPE decided to source the line from the distribution system. This brought on a host of technical issues that would need to be resolved before the distribution system was ready to connect to the 115-kV line, but EPE was determined to make it work.

Fulfilling this request would allow EPE to modernize this transmission line with steel structures but presented two initial challenges. First, the remaining radial transmission line had to be fed from a distribution source for three months while rerouting took place. Second, the radial transmission line had to be reconfigured safely without customer outages.

Picking the Source Location

The remaining portion of the transmission line to Hatch passed over an urban 24-kV feeder from Arroyo Substation. Engineers initially considered placing distribution voltage (24 kV) on this transmission line to the Hatch Substation and jumper across the substation transformer directly to the feeder breaker and voltage regulators. The Hatch Substation distribution branches are extensive, feeding many rural irrigation wells. The added transmission line impedance (36 miles [58 km] of 336 ACSR) would result in low available fault current at Hatch Substation (409 A three-phase, 226 A line-to-ground) and much lower current at the end of the Hatch distribution 22 miles (35 km) away. This presented safety and operational concerns, such as the risk of protection devices reacting too slowly to faults, if they detected them at all. Analysis showed that a 100-hp, three-phase motor start would cause 3% voltage flicker at Hatch Substation. Moreover, a 25-hp, single-phase motor start would cause a 3.5% voltage sag.

To lower overall circuit impedance, the choice was made to use the Arroyo 24-kV distribution voltage to feed the transmission line at 115-kV through a portable substation. This option provided higher available fault currents (1020 A, three-phase, 890 A, line-to-ground) at Hatch Substation — 28% of the original three-phase fault current. That was more than twice the amount from using purely distribution voltage to feed Hatch Substation, allowing protection devices to be more effective.

Floating Transmission Neutral Voltage

EPE's 115-kV transmission system is normally grounded, employing 90-kV-rated (70-kV maximum continuous over voltage — MCOV) lightning arresters phase-to-ground. Temporarily stepping up distribution voltage by inserting a traditional delta/grounded-wye portable substation connection removes the transmission line grounding (due to the 115-kV delta transformer bank connection), allowing phase-to-ground voltage to float. EPE's 90-kV arresters would experience steady-state overvoltage of 115-kV if a transmission phase went to ground.

In response, EPE constructed a 115-kV structure at Hatch Substation with two stacked 90-kV lightning arresters per phase. EPE monitored transmission line phase-to-ground voltage through remote wireless technology to detect ground faults. The Telemetric TVM3-120, three-phase voltage monitor was connected to transmission-potential transformers. The TVM3-120 uses the cellular phone communications channel to transmit voltage information back to Telemetric (Boise, Idaho, U.S.). Telemetric can page, e-mail or post any voltage anomaly information on its secure website, or transmit the information to the utilities' SCADA system. (See Transmission & Distribution World, “Telemetric Project at Kansas City Power and Light Wins T&D Project of the Year,” January 2003.) SCADA is available at Arroyo Substation but not at the portable substation, nor at Hatch. For an extensive outage at Hatch, the TVM3-120 would help determine whether the portable substation or Hatch Substation breaker operated assuming proper relay coordination.

Overcurrent Relay Coordination

Determining distribution overcurrent relay coordination at three locations — Arroyo distribution feeder to the portable substation, the portable substation and Hatch Substation distribution downstream of the transmission line — was challenging. Due to the delta-wye configuration of all three substation transformers involved, it is interesting to note that phase-to-ground faults on Hatch distribution will appear as phase-to-phase faults on the 115-kV transmission line, which in turn will be converted back to a phase-to-ground fault on the Arroyo distribution feeder. Theoretically, without proper relay coordination, a distribution fault in Hatch could trip all three sets of distribution overcurrent relays. All relay, recloser and fuse curves should fit under the Arroyo Substation transformer damage curve.

Reconfiguring the Transmission

After exploring options, EPE decided to temporarily backfeed the existing 7 MVA Hatch Substation to pick up the load. Of the 37 miles (59 km) of distribution line, more than 27 miles (43 km) was small conductor (1/0 ACSR) coming out of the Picacho Substation. At one point the 1/0 ACSR continuously carried more than 263 A — exceeding its capacity under usual conditions. To achieve this, EPE decided to backfeed during the lowest load time to prevent conductor thermal damage. Fortunately, this time corresponds with the low-temperature time of the year. The line was patrolled beforehand, resulting in repairs to two oxidized connectors and broken 1/0 ACSR conductor strands.

From modeling the backfeed on Milsoft distribution analysis software, EPE installed four 1200 kVAR capacitor banks on the Hatch distribution feeder to help support voltage. Three of the capacitor banks were strategically located to work in tandem with the Hatch Substation voltage regulators. The major concern was not low voltage but voltage unbalance along the backfeeding route. Placing capacitor banks downstream of voltage regulators allowed a small quantity of VARs to be increased or diminished by adjusting phase voltage (i.e., capacitive current is controlled by the square of the phase-to-ground voltage). This small quantity of VARs notably affects voltage after 37 miles (59 km) — i.e., 100 kVAR/phase raises voltage 1.7%. Most of the backfed distribution line was originally built as subtransmission serving 4-kV substations and had some transpositions.

The window of opportunity was between January and March when irrigation pump load was low. At 1 a.m., Jan. 7, 2004, EPE engineers, substation, transmission and distribution crews gathered to start transferring Hatch load onto Picacho's distribution feeder. At 2 a.m., the distribution load transfer was complete and the transmission line to Hatch Substation was de-energized for installing isolating insulators before energizing the portable substation.

During distribution backfeeding, an unexpected phenomenon was seen at the forward-fed north voltage regulators at Hatch Substation. One Hatch voltage regulator rose several steps and stopped, and then a different phase's regulator would lower several steps and stop before the third phase's regulator would step up and stop. A minute later, the first regulator would reverse the process by stepping down several steps and stopping. Next, the second regulator started raising several steps before stopping. Then, the third regulator stepped down and stopped. Within a minute, the process would start all over again with the first regulator rising again.

This phenomenon has not fully been analyzed or explained. However, EPE suspects the interaction of three sets of voltage regulators on automatic (with 15- and 30-second delay times), the added downstream capacitance on Hatch distribution, plus mutual coupling over 37 miles, caused voltage regulator hunting over the 22-minute period. The cycling stopped when technicians turned off the voltage regulators at Hatch Substation and adjusted them manually as needed. When one phase-to-ground voltage became more than 3% lower than the other two upstream Hatch regulators, that phase's regulator was stepped up to evoke more capacitive VARs (hence, more leading current), in turn raising upstream phase-to-ground voltage.

The upstream voltage recorder was installed to monitor voltage unbalance and faults. During the Picacho backfeed the typical problem of long distribution manifested itself again. Available fault current at Hatch Substation dropped to 345 A, three-phase and to 239 A, phase-to-ground. Faults downstream may not have been detected by overcurrent devices. However, erratic voltage would indicate a problem, calling for the line to be sectionalized.

Using shunt capacitors to support voltage at the end of long distribution feeders invokes principles in the maximum-power-transfer theorem (i.e., maximum power transfer is achieved when the load impedance is a complex conjugate of the source impedance). Shunt capacitors partially offset the effect of high inductance from long overhead distribution lines. Theoretically, this allows more load current than fault current (where the shunt capacitors are ineffective at low voltage) to flow down the line.

Testing and Implementing the Tie

Everything was on schedule until the portable substation's 24-kV breaker was closed to feed the 115-kV transmission line to Hatch. The breaker opened, not from overcurrent, but from lack of oil flow through the cooling fins. Station-service transformers were now on the low side of the 24-kV breaker, due to feeding the portable substation backward from Arroyo distribution. It took several seconds before the cooling pumps could build up enough oil flow to satisfy the transformer protection system. Before flow was sufficient, the 24-kV breaker tripped, de-energizing the station-service transformers.

EPE decided to energize the 115 kV through the Hatch 24-kV breaker being backfed from Picacho 37 miles away. However, 5 MVARs of 115-kV transmission line capacitance added enough current (120 A of reactive current at 24 kV) to trip an electronic recloser on three-phase overcurrent with a minimum phase pick-up of 320 A. Fearing conductor thermal overload, EPE decided not to bypass the recloser and re-attempt energizing the 115 kV through the backfeeding distribution system. Instead, substation workers bypassed the portable substation oil flow protection by setting the 24-kV breaker to manual. This manual setting would not allow automatic reclose; therefore, station-service transformers on the source-side 24 kV were later installed to run the transformer oil cooling pumps.

A few days before switching was scheduled, EPE personnel in the Hatch office called many customers (including city hall, police, fire, schools and commercial customers with 24-hour operations), warning them of possible voltage irregularities and outages. As a result, EPE received no customer complaints or claims due to the early morning switching and brief outage.

After the 115-kV circuit was energized to Hatch Substation, phasing was confirmed across the open substation breaker. Potential difference between properly phased distribution circuits is typically near 0 V; however, modeling the backfeed showed voltage at Hatch Substation lagging voltage at Picacho Substation by 28 degrees. On 24-kV distribution, this amounts to about 6700 V between the two circuits. Proper analysis beforehand prevented engineers from being caught off guard with this seemingly high difference in phasing voltage.

The temporary Arroyo 115-kV circuit was completed before 6 a.m. when load starts its daily rise.

Three months later, the Picacho to Hatch Substation backfeed was repeated again early in the morning while the 115-kV transmission line was reconfigured for normal operation.

Conclusion

Engineering analysis and double-checking small details are vital to unusual engineering projects. In addition, level heads and good communications go a long way to solve field problems in a timely manner. But most important, teamwork among different departments is crucial — everybody is important. Engineers performing analysis, technicians testing equipment, inspectors patrolling lines, crew members installing nuts and bolts, college interns modeling distribution lines and office workers calling customers are key ingredients that made this project a success.

Acknowledgments

The author would like to thank Richard Shepan for his tireless checking of details and analysis and his valuable contributions to this article.

Steve Eckles has been a distribution engineer for 12 years and is a licensed P.E. in New Mexico and Texas. He obtained a BSEE degree from San Diego State University and an MSEE from New Mexico State University's Electrical Utility Management Program. He previously has authored technical papers in electrochemistry, photovoltaics and power quality.
seckles2@epelectric.com