Bringing reliable power to the people of Supai through solar PV and a microgrid

By Erich Keller and Frank Patton Jr., PE, Contributors

Reaching the remote Havasupai community of Supai, Arizona is not a journey for the faint of heart. Surrounded entirely by the Grand Canyon, this remote Native American reservation is either an eight-mile hike or mule trek from the closest road, or a helicopter ride to the bottom.

So, delivering reliable power to the 200 permanent residents and 20,000 tourists who visit each year, provides its own set of unique challenges. Power is vital, as it serves more than 40 households, a café, a general store, a tourist office, a lodge, a post office, a school and other commercial buildings.   

Mohave Electric Company (MEC) operates its closest substation more than 80 miles away through overhead distribution. MEC has serviced this area for decades, but keeping power flowing to critical loads has always been problematic. Extended outages were common and getting maintenance personnel and equipment down to the community was a huge undertaking.  MEC brought together their team of experts and those from G&W Electric to solve this decade’s old problem.

A micro solution to a big problem

The solution developed to address the frequency and length of outages is a microgrid system designed to supply back-up power to the village when the connection to the utility fails. The microgrid includes nine new G&W PVI-style switches and one existing switch that was retrofitted with new protection and automation control circuitry. Each switch was equipped with a SEL-451 relay for protection and control functions.

The switches consist of two load break ways that complete the main distribution loop (line L2-L9) and one or two fault interrupter ways that protect transformers. In the case of a fault on lines L2-L9, the main switch SWM will initially interrupt the fault. After the main switch (SWM) opens, the microgrid controller uses faulted circuit indicators (FCIs) on the loop ways to determine the location of the faulted sections. Once the fault is located, the controller opens the adjacent switch ways to isolate the cable. The normally open point and the tripped interrupter at the SWM can then be closed if they are not adjacent to the faulted cable.

Centralized and remote control 

Centralized control of the microgrid is overseen by a SEL-3530 Real-Time Automation Controller (RTAC) on a remote rack mounted control cabinet located on the rim of the canyon. There are several functions the RTAC monitors.  

  • Enable loop fault detection, isolation, and restoration (FDIR). This function isolates faults in the system. After SWM opens to interrupt the fault, the RTAC sends the commands necessary to isolate the faulted section. Next, the tie closes, and then the open way of SWM closes, restoring power to the unfaulted sections.
  • Utility source transfer auto/Loss of voltage (LOV). This function transfers the load to an alternate source of power if the primary source is lost.
  • Human-Machine Interface (HMI).  The HMI includes a graphical representation of the distribution system that allows visualizing and controlling the status of all system components, including switches, generation sources, and loads.
  • Load management. The controller continuously monitors the microgrid generation capacity and loading while islanded. If the generation exceeds a certain generation level, or the photovoltaic array indicates a decrease in capacity, the system will begin dropping non-essential loads according to a load matrix until the capacity stabilizes. When more generation capacity becomes available, the controller will automatically add it.  
  • Maximizing generator run time.  The system is designed to maximize the remaining fuel for the back-up diesel generator by managing generator and photovoltaic contributions to the system, which includes disconnecting all non-essential loads.

In addition to the power sourced from the utility, a significant amount of the power used in the village is co-generated by a solar PV array located next to the RTAC. At utility power, a diesel generator is activated and during daylight hours the photovoltaic array bridges the gap between demand and diesel generation.  

Automating the switch operation process offered a variety of advantages for the Supai distribution system. Greater service reliability and substantially reduced outage times were particularly valuable in Supai, given the previous difficulty of getting maintenance personnel and equipment onsite. Reduced labor costs were realized because the system eliminated the need to dispatch personnel to tie points for manual operation of switches. Connecting the equipment to a SCADA system simplified collecting accurate information about the network, which can be used to prioritize maintenance and upgrades. And, by allowing switches to be opened remotely, the system reduces potential accidents.

A microwave connection allows for communication between the RTAC centralized control system located in the control building on the canyon rim with the communication ring on the microgrid distribution system below. Each relay has dual ethernet ports that can be set to act like an unmanaged switch, which make additional ethernet switches in each control cabinet unnecessary. The controller communicates with the rest of the microgrid’s devices using Distributed Network Protocol over ethernet (DNP/IP).

Onsite troubleshooting leads to innovative solution

The microgrid control system was initially tested as part of a detailed factory acceptance test. The goals of this testing process were to verify that the manual control of the system worked properly, that the FDIR logic correctly identified and isolated faulted sections and restored power to unfaulted sections, and that the microgrid control logic transferred the system to back-up generation and managed both generation and load levels appropriately. During factory acceptance testing, the diesel generator, solar inverter and weather station were simulated with a Modbus slave emulator.

The microgrid load transfer and load management functions were tested again onsite. During the automatic transfer tests, the generator was consistently tripped offline by its self-protection routines due to excess reverse VARs. After several manual tests, it was discovered that the village load was too capacitive and the generator was absorbing too many VARs. No viable combination was found that would allow the generator to pick up for village load and avoid tripping. A reactor bank was added to counteract the capacitive VARs from the distribution system.

A second onsite test was performed after the reactor bank was installed. Although the additional reactance mitigated the VAR issue to a degree, the generator continued to trip due to reverse VAR flow.

However, during this trip, it was observed that supplying power to one half of the distribution loop while the other half was not powered did decrease the capacitive load. This led to suspicion that the initial cable runs of the loop from the main switch SWM were in the same trench and were likely capacitively coupled.

Therefore, the program was temporarily modified to segment the distribution loop and energize only the half of the loop that fed the highest priority loads until an additional reactor bank could be installed. After the second reactor was added, the transfer program was restored to its original form to feed all loads in the system.

Critical insights learned

The team learned several critical insights that can help future microgrid designs and installations.

  1. Learn the intricacies of the existing distribution system as early as possible. In this case, it was discovered that the distribution system was too capacitive for the generator to pick up only after onsite experimentation. That exploration, in turn, led to the value of adding reactor banks to manage the load impedance for the generator.
  2. Understand the proper operating range of the generator used to power the system during loss of voltage from the utility, and how to adjust the algorithms used to control it.
  3. Never underestimate the value of comprehensive factory acceptance testing and onsite testing protocols.

Possible future enhancements to the microgrid system

The microgrid control system was designed to take into account the limitations of the generation sources and distribution system. In the current system, the diesel generator must be prepared to increase or decrease its output nearly instantaneously to make up for changes in the solar array’s generation capacity. This means the diesel generator must be loaded within a narrow band while the inverter’s output must be limited in islanded mode.

The Solar array’s capacity could be utilized more fully if storage were used in conjunction with the solar and diesel generation. Although there is currently no plan to add this to the project, many other microgrid installations have used storage technologies to complement onsite generation. Flywheel technology can smooth out instantaneous changes in loads or in generation capacity of renewable sources. Battery storage could also be used to smooth out instantaneous changes in demand for power or in generation, with the added benefit of providing stored power for a longer period. These devices help to ride through short-term fluctuations in the system and allow the microgrid controller to balance energy supply and demand in the longer term.

Erich Keller is an automation engineer in distribution automation at G&W Electric Co. where he is responsible for power system automation specification, design, factory acceptance testing and site commissioning. Frank Patton Jr. is the president of N.J. Shaum & Son, Inc.

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