Distributed Energy Resource Saturation: Page 2 of 7

Engineering review. Integrating increasing amounts of DER generation is an inherently challenging project. The authors of the Electric Power Research Institute (EPRI) report “The Integrated Grid: A Benefit-Cost Framework” (see Resources), note: “The question is about the ways in which DER interacts with the power system infrastructure. The formula for this answer has multiple dimensions. Beneficial and adverse circumstances can arise at differing levels of DER saturation. The interaction is dependent on the specific characteristics of the distribution circuits (design and equipment), existing loads, time variation of loads and generation, environmental conditions, and other local factors. Benefits and costs must be characterized at the local level and the aggregated level of the overall power grid.”

With this in mind, we have to expect long interconnection time lines with large non-NEMA projects, as reliability engineers must extensively model the impact these systems have on the electric power system. However, very large PV systems can connect directly into the transmission system, bypassing the distribution system altogether. Though NEM and NEMA projects initially experienced shorter engineering review time lines, these projects are now hitting a wall in areas where IOUs deem the existing utility infrastructure inadequate to support additional DER generation.

In effect, a large portion of the electric power system is not designed for backfeeding from the distribution systems into the transmission level. The antiquated protective devices at the substation and transmission level are designed for power flowing to the distribution system, not from it. As a result, increasing numbers of relatively small DER projects fail to pass the Rule 21 fast-track interconnection review process, and then they must undergo detailed studies with significantly longer time lines.

Interconnection delays. During a recent distribution-level substation walkthrough, I had an experience that offered a microcosm of the situation we are in. The purpose of the visit was to help a client understand the IOU’s proposed upgrades related to direct transfer trip (DTT), a protection scheme that manages unintentional islanding—and that can do so faster and more reliably than the anti-islanding protections in an inverter. (Islanding refers to a situation where an inverter-based distributed generator continues to energize a power-system circuit.) The utility’s protection engineers were concerned that an additional 1 MW of distributed generation (DG) could backfeed the substation and support an unintentional island.

During this walkthrough, the person charged with managing the substation on a day-to-day basis pointed to a voltage regulator and said: “That’s going to be a problem.” This statement confused all of us until the substation manager explained that the voltage regulator had been installed 70 years ago. This meant it had analog controls, which could not accept the digital commands that utility operators need to send to a voltage regulator to enable DTT. Admittedly, I initially thought the substation manager was exaggerating the age of the equipment, but when we walked over to the voltage regulator, he pointed out the year printed on the nameplate: 1946.

Though it is just one piece of hardware, this voltage regulator is emblematic of the challenges associated with transitioning a 20th-century power system into a 21st-century infrastructure. Some of the technology that the utility employs, while perfectly functional, is antiquated. When the utility installed that voltage regulator back in 1946, nobody could have dreamed that a solar power plant would necessitate its replacement in 2016. This single voltage regulator serves hundreds, if not thousands, of customers. Taking it offline, while manageable, requires a substantial amount of coordination within the utility system to ensure no loss of service. The system operator will need to take lines out of service, reroute feeders and so forth. There is no room for error in a system where reliability is of the utmost importance. To manage these risks, the utility typically conducts these change-outs when the load is at a minimum so the potential impact is as low as possible, which in this case is between the months of November and February.

In this particular case, the IOU conducted a detailed study related to the proposed project in March 2016 per Rule 21. Since the IOU identified the need for specific substation upgrades, we requested that the utility place the project in the 2016–17 upgrade window. However, projects in the queue from the previous year had reserved all of the spots in this year’s upgrade window. As a result, the upgrades required to interconnect this project will have to wait until the 2017–18 upgrade window.

This sort of delay stacking is directly due to DER saturation, and antiquated equipment compounds the problem. Had there been enough load to offset the combined generation, the vintage voltage regulator could have gone right on functioning into perpetuity. Instead, what would normally have been an interconnection process of 3–6 months became a project of 18–24 months. It is important to keep in mind that we are not talking about a 50 MW utility-scale project, but rather a NEMA project with a generating capacity of less than 1 MW.

Article Discussion

Related Articles