Yesterday’s Assumptions are Invalid for Tomorrow’s Plans; Implications for Rapid integration of DERs on the Bulk Electric System

By Jameson Thornton

In the late 90’s renewable energy generation was barely a blip on the map for utility companies. 10 years ago in the mid to late 2000’s renewable energy was a footnote to remember for utility companies. In some areas, particularly California, there has been a significant focus on renewable resources and their rapid growth and adoption, causing utility companies to stand and take notice. California has a state legislated mandate to meet at least 50% of energy procurement from renewable-eligible resources by 2030. In light of this, utilities in California are looking for the optimal route to meet a balance among goals for a reliable, affordable, and clean energy portfolio. In the last 5 years wind and solar PV have been the major players in the renewable space. Recently though we have seen how much of an impact DERs have in our transmission planning models.

Distributed Energy Resources (DERs) (specifically, rooftop solar) have gathered significant attention. Pacific Gas and Electric Company (PG&E), an investor owned utility company serving 15 million people in northern California has roughly 25% of all installed rooftop solar in the nation, over 250,000 individual customer installations. PG&E customers are installing around 50 MW of rooftop solar each month. In 2017, PG&E had over 3,000 MW of installed rooftop solar capacity, which is over 15% of PG&E’s peak demand (roughly 20,000 MW) and about equal to the total installed capacity of utility-scale solar interconnected to both the transmission and distribution systems. DERs can no longer be ignored at the transmission level. The North-American Electric Reliability Corporation (NERC), which develops national standards for electric utilities, with active input from the Western Electric Coordinating Council (WECC), which enforces the NERC standard, and western utilities, has given guidance on how transmission planners should handle DERs. When DERs are a tiny fraction of the overall loading or generation mix it would be reasonable to model them as a negative load or simply model the lower net effective load as observed by the utility. NERC suggests that at “sufficient” levels of DERs utilities should consider more explicit modeling of them. With improved modeling and computing power, it is now feasible to account for virtually every kW connected to our systems. According to the views of this article, it is suggested that we model every kW we can for two reasons: 1) implementation of DERs will affect load forecast, shapes, and the periods and scenarios of system stress, and 2) asynchronous inverter based generation will have impacts on system performance, including voltage control and dynamic stability.

PG&E utilizes the California Energy Commission (CEC) forecast for its Transmission Planning Process (TPP) with the California Independent System Operator (CAISO), in addition to forecasts developed internally for other purposes. In 2012 the annual load growth rate forecast by the CEC was 1.5%. In 2017 the load growth rate forecasted by the CEC is net negative, about -0.25%. The two main drivers for the negative load growth are energy efficiency and DER adoption. Perhaps even more urgent than the changing forecast for peak demand is the underlying behavior of the load, and how the shape, and times of high and low demand are changing. We all know solar peak occurs mid day; when it is behind the meter it alters the net loading observed from the utility. This will require a change in assumption on when the system is at its greatest stress for analysis. It used to be as simple as the time of the peak observed loading, but it is strongly recommend that we shed that old assumption and look deeper into various times of system stress with both high and low solar output. Beyond the adoption of DERs, changes to rate structures and time of use (TOU) rate changes will also affect end-user load behavior in ways it is not easy or straight-forward to speculate.

Changes in load behavior will result in changes in MW flow, but they will also alter the voltage profiles we see on the system. Reduction in load will cause increased system voltages. There will be less voltage drop in the system, due to less copper losses and lines will produce VARs, which will exacerbate high system voltage issues. Long, high capacity lines will be affected sooner and more dramatically as the adoption of DERs increases. Excessively high voltages for prolonged periods of time can damage equipment, saturate transformers, and potentially cause flashovers and pose other significant safety concerns. PG&E has observed increasing system voltages, possibly due to DERs, and is exploring tools to help with voltage control. Five years ago the focus was on correcting low voltage problems, now the focus is on pulling voltages down. While load reduction is one challenge DERs present, further adoption of DERs can lead to load buses become net resources. Each node on the transmission system could be a potential point for injection or consumption of MW and MVARs as the system continues to change in ways we have not seen before.

Related to point 2 above about inverters impacting system performance, the replacement of traditional synchronous machines with inverter based generation has the challenge of reduced voltage support and the potential to result in decreased frequency response. This may, in turn, lead to weaker system performance. These impacts are not unique to DERs, but are being actively investigated by many stakeholders in the west.

Another challenge at PG&E is the need to reevaluate our transmission projects developed and approved in prior planning studies. In the last year PG&E has spent significant extra effort to re-scope and right-size these projects because of changes in projected load growth. TPP must consider the continuous changes in load forecast in how to analyze the grid. For example, today system peak load may appear to be declining with a peak at 6pm, but next year it may increase slightly due to Electric Vehicles (EVs), with a system peak at 9pm (when vehicles are charging and the sun has set). Rules of thumb developed ten years ago no longer apply. Assumptions used two years ago are no longer valid. Assumptions used today must be changed tomorrow.

Progress and advancements do not occur uniformly everywhere. In California the future started yesterday, how will we keep up?

For a downloadable copy of the September 2017 eNewsletterwhich includes this article, please visit the IEEE Smart Grid Resource Center

Contributors 

 

jameson

Jameson Thornton has over six years of experience in PG&E’s transmission planning department where he is currently supervisor of a team of four engineers. Jameson and team are currently responsible for load forecast and modeling and analyzing the PG&E transmission bulk electric system to determine reliability impacts and needs for upgrades. As part of his responsibilities, Jameson is a member of the WECC Reliability Assessment Committee - Studies Subcommittee (RAC - StS) which looks to coordinate reliability studies and issues across the western interconnection. Jameson received both his bachelor’s and master’s degrees in electrical engineering from Cal Poly Statue University, SLO and is a registered professional engineer in the state of California.


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