Solar Impacts: Power Electronics to the Rescue
By John D. McDonald
Sharply increased penetration of solar generation is starting to have wide ramifications in some electrical distribution systems, putting stress on devices traditionally used to handle voltage variability. To address the impacts of intermittent generation effectively, the hitherto largely separate disciplines of power electronics and power system automation need to be integrated.
As residential solar photovoltaics (PV) reach high levels of penetration on the grid’s distribution system, the grid will become more susceptible to voltage variability. This issue has been documented by utilities on the frontline of this trend and they’ve begun the search for solutions, which include power electronics.
Solar PV’s intermittency, in combination with other factors, leads to voltage variability on distribution feeders, yet utilities have an obligation to maintain voltage within 114 to 126 volts all along those lines to meet ANSI standards. Voltage variability triggers the operation of electro-mechanical devices designed for voltage regulation (and that act based on voltage changes, not timers)—from load tap changers (LTCs) at the substation, to voltage regulators out on the feeder—far more frequently than intended by their original design. In turn, that higher number of operations dramatically shortens those devices’ lifecycles, without necessarily resolving the variability, leading to unanticipated costs and a search for mitigating technologies.
This domino effect of high-penetration solar PV on voltage variability and voltage regulation devices’ reduced lifecycles has been identified and is being addressed at San Diego Gas & Electric (SDG&E) in Southern California and Arizona Public Service (APS) in central Arizona. Yet there’s reason to believe these effects are also taking place at utilities that simply aren’t examining feeder voltage data in highly granular form and remain unaware of the issue.
It behooves utilities to understand and anticipate these impacts prior to addressing the symptoms, as many factors must be taken into account in the selection and application of mitigating technologies. While the effects may be generalized, the solutions and their precise applications are likely to be specific to each utility. (In Europe, where policy encourages high-penetration of solar PV, it also requires inverters that provide reactive power compensation.)
The search for mitigating technologies ranges from the conventional, such as re-sizing feeder lines and installing dynamic VAR (Volt-Ampere Reactive) devices, to the unconventional—energy storage, for example, and the application of power electronics to technologies that today rely on electro-mechanical means of operation. Working with SDG&E and APS, we have found that both the voltage variability and the effectiveness of a variety of mitigating technologies can vary based on characteristics such as the location of the PV on the feeder, as well as feeder length and conductor size.
Let’s look at SDG&E’s and APS’ approaches to quantifying the issues and field testing possible solutions. Once we set the scene, we’ll address the evolving definition of “high penetration” solar PV as it applies to these examples.
In San Diego, affluent homeowners along the coast have installed solar PV arrays in large numbers. As their breezy homes are not usually equipped with air conditioning, their service panels are often limited to 100 amps; accordingly, up to 20 homes are served by a single distribution transformer. Fog typically burns off by midday, when the PV arrays ramp to maximum output. All these factors contribute to spikes in voltage variability when PV output is high, load is low, voltage regulation is electro-mechanical and, possibly, there’s high impedance on the feeder.
Further inland, owners of an avocado farm near the end of a long feeder installed a substantial PV array to offset the operation of irrigation pumps. California requires SDG&E to accommodate that interconnection. Morning fog burns away and solar PV output rises at midday, while the pumps mainly operate in the early morning. With net metering policies in place, the farm injects substantial amounts of power onto the feeder, creating a voltage differential that results in reverse power flows. That, in turn, leads to the maximum tap, then lockout, of an upstream voltage regulator and has even affected voltage on the primary distribution line.
SDG&E has installed monitoring equipment at a variety of sites to gather data on the causes, effects and locations of the resulting voltage variability in these two cases. Currently, the 24,000 PV installations in SDG&E’s territory have a capacity of about 175 megawatts. Year-on-year growth is 30 to 40 percent, with the number of installations doubling every two years. Yet most PV systems are designed for maximum output with little regard for their effects on the grid, in particular VAR support.
Arizona Public Service’s Community Power Program in Flagstaff is an ongoing effort to anticipate how high penetration of solar PV will affect the stability of its grid and how to mitigate those impacts. The project is primarily funded by $2.7 million from the U.S. Department of Energy that includes $520,000 from the National Renewable Energy Lab (NREL) and is conducted by a consortium of partners, including APS, GE Global Research, NREL, Arizona State University and private contractors.
APS sought approval for the project from its regulator, the Arizona Corporation Commission, and received it. APS gathered baseline data on feeders in Flagstaff, where demographics suggested there would be early and enthusiastic adopters of residential solar PV. Then it installed about 1.5 megawatts of PV among volunteer homeowners and schools to measure the effect on voltage variability. GE Global Research helped APS design a data collection system parallel to the utility’s SCADA system, answering cyber security concerns.
Traditionally, high solar penetration tended to be thought of in terms of a certain percent of total power in any balancing area. At GE Global Research, the traditional definition has been superseded by one that focuses on distribution-connected solar PV on a single feeder: What percent of load is served by PV on the feeder itself during peak hours, such as a sunny day in winter, when there’s low load and the sun is shining?
SDG&E’s definition is similar. When the ratio of PV nameplate AC output to the load on the circuit reaches about 30 percent—that is, when PV output peaks and load is low—SDG&E has a concern.
At SDG&E, mitigating technologies are seen as residing on a continuum from conventional to unconventional. Perhaps unsurprisingly, costs increase from tried-and-true to less-tested solutions. Thus, SDG&E began by changing voltage regulator settings and re-sizing conductors. It soon will test a couple of mega-VAR dynamic VAR devices along selected feeders. At the high end of cost, it has field-tested energy storage at a variety of locations.
Re-sizing conductors has reduced the overall magnitude of voltage fluctuations, but not the fluctuations themselves. Storage provides a flexible solution, but the cost is high and the business case for it only pencils out when it serves multiple roles and value streams, which can be challenging to effectively coordinate.
One major, promising solution is the focus of SDG&E’s efforts to have California’s interconnection rules changed, while working with PV vendors: Dynamic VAR-equipped PV inverters, if required as they are in Europe, appear to be the least-cost solution directly addressing the source of voltage variability.
At APS, the potential for over-switching of capacitor banks and, possibly, an increase in LTC operations, has led to the study of a variety of mitigating technologies, including power electronics-assisted Static VAR Compensators or STATCOM.
Clearly, challenges and solutions are not uniform. This makes it difficult to deliver definitive statements about the specific role of power electronics.
Sharp-eyed readers, however, will have noted that SDG&E’s dynamic VAR devices are assisted by power electronics. (STATCOMs all rely on power electronics.) Major vendors are doing R&D on prototype LTCs employing power electronics. So, despite the perils of generalization, an underlying challenge is apparent and the nature of power electronics lends itself to a solution.
Some electro-mechanical devices, particularly those with a role in voltage regulation, are ill-equipped by dint of their design to address the speed and magnitude of voltage variability on feeders caused by high penetration of residential solar PV.
Power electronics have the ability to use distributed intelligence to assess many more variables in power quality on distribution feeders and to calibrate a device’s response to minimize automated, mechanical actions. Power electronics also have the ability to react in exponentially swifter timeframes than electro-mechanical devices that can shut down from over-operation in the face of rapid swings in voltage.
While the projected cost of power electronics has been an issue historically, the efficacy of this approach is likely to expand its market, bringing costs down through economies of scale. As we’ve documented, the challenge is real and likely to spread. The role of power electronics in mitigating technologies seems assured.
Today it is San Diego’s and Phoenix’s challenge; tomorrow it is likely to be Peoria’s.
This article is adapted from a somewhat longer and slightly more technical version that first appeared in Power Electronics Magazine, on August 22, 2013. It is published here courtesy of Power Electronics Magazine.
John D. McDonald is an IEEE Fellow, an IEEE Smart Grid technical expert, a past president of the IEEE Power & Energy Society (PES) and past chair of the IEEE PES Substations Committee. He is Director of Technical Strategy and Policy Development at GE Energy’s Digital Energy business. In this role, he sets and drives the vision that integrates standards participation, industry-organization participation, thought-leadership activities, regulatory/policy participation, educational programs and product/systems development into comprehensive solutions for customers. He has over 39 years of industry experience.