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Grid Modernization Needs a New Crystal Ball

image credit: © Andrey Popov | Dreamstime.com

By Mike Smith and Mark Konya

Remember the good ol’ days at the utility? The routines for managing generation operations and maintenance were well established and followed a cyclical pattern around load growth and planned outages. The T & D system was managed by operators using SCADA (Supervisory Control and Data Acquisition) and EMS (Energy Management System) that were forklifted out every nine to eleven years with the latest technology. The customer relationship was defined by the monthly bill and inserts. Forecasting was relatively simple and produced results which could be accommodated by planners within allowable capital budgets.

While some of us long for those good ol’ days, there is a growing chorus of utility professionals who are diving head-first into the “new normal” that has turned all of the old assumptions on their head. The generation mix evolves literally hour-to hour, managing the grid is more complex than ever, and customer relationships are changing. Embracing these challenges is not simply a matter of working with the latest “big thing”; rather, the very survival of the utility as a viable business depends on utility leaders and professionals understanding these challenges and building the organizations, systems, and processes that will meet the demands of this new energy environment.

At the core of these challenges is “grid modernization.” While this term takes on slightly different meanings in different circles (an Internet search on this term yields a multitude of different definitions, depending on the perspective of the stakeholder), the common thread is that the changes in utility operations, driven by the growth of distributed energy resources (DERs), aging infrastructure, safety, and new customer expectations demands a new approach to how utilities are managing their energy delivery infrastructure. Notably “energy delivery” includes the development and implementation of new systems that can account for and manage DERs in utility operations as their penetration grows.  This is especially true when resources are connected to distribution systems as when PVs (Photo Voltaics/rooftop solar) or EVs (Electric Vehicles) provide power to a system originally designed to accommodate power flow from central station generators to end-use customers.  Controlling these sources to ensure power quality while avoiding system protection and design limit violations is paramount if utilities are to meet their fundamental obligations to serve. Figure 1 below provides an example of how the grid has changed and why the forecasting process needs to change for a utility to maintain reliability and meet the new challenges in a DER-rich environment.

Figure 1. The Grid and Forecasting Requirements in the New Energy Environment. Image Credit: Mike Smith

So, in the realm of grid modernization what are the foundational pieces that utility leaders should be looking at and implementing ASAP? The answer to this question will likely vary to some degree from utility to utility based on their regional differences and the imperatives that are thrown down by their state regulators, but there are some common themes that utility leadership should be acting on.

One of the most important themes is to transition the traditional load forecasting process from  “top down”  to  “bottom up” in order to predict very short term to very long term load profiles anywhere on a distribution circuit. Here are some examples of why we believe this “forecast-first” approach is the path for a utility entering into the grid modernization space:

  • Reliability: Job One for a utility is reliability, and this has proven to be a cornerstone in helping the world navigate the recent challenges associated with the coronavirus. Ensuring that these high levels of reliability are maintained, a utility cannot let the major shifts in their business model (growth in rooftop solar, changing customer patterns, and EV growth, for example) get ahead of how they operate and maintain their infrastructure. This requires a granular forecast that will enable them to be prepared for these changes as they appear.
  • Bottom-Up Load Flow Analysis: More accurate, granular forecasts of customer behavior at the edge can be aggregated to generate load flow models which predict the impact of DERs and other changes occurring behind the meter.  This is a “big analytics” task which requires analytics software, computing infrastructure, and governance processes capable of utilize-size scaling.  Robust forecasting in this environment also provides the means for more accurate cost-of-service determinations, rate designs, and integrated resource plans – all of high interest to state regulators.
  • Asset Management: At a tactical level, managing assets on the grid will continue to evolve. Strategically, however, the changes in how the grid is operating should be a key consideration in asset planning processes; as with distribution planning this rests squarely on the forecast.
  • Capital Planning: Finally, we see capital planning entering a new era, as well. With a detailed understanding of distribution system challenges derived from accurate load forecasts and circuit analysis it’s possible to identify challenges to design and protection limits which must be addressed within the forecast horizon.  Some of these challenges will require physical modifications, while others can be addressed with non-wire alternatives.  Identifying the optimum remediation projects based on factors such as avoided costs, outage risk mitigation, and locational benefits will be important considerations in the future.

Utilities are in need of a crystal ball - one that is capable of utility-scale production, can be adapted to serve a variety of consumers, and supports solid, transparent communication with state regulators and their staffs.  Robust forecasting organizations, processes, and technology will enable utilities to meet these objectives and ultimately serve the best interests of their customers.

Note: Mike Smith is an Industry Principal and Mark Konya is an Advisory Industry Consultant at SAS. They can be reached at mikef.smith@sas.com and mark.konya@sas.com.

Mike Smith's picture

Thank Mike for the Post!

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Discussions

Matt Chester's picture
Matt Chester on Jun 23, 2020 11:44 am GMT

Many of these forecasting needs seem focused on forecasting the state of the grid's assets themselves, but what about the forecasting needs regarding demand-- how weather, changing customer needs, customer-owned assets, etc. will affect what a utility is expected to handle? And how much are these forecasts a moving target that are consistently being refreshed-- should utilities be reevaluating these each year? Month? More?

Mike Smith's picture
Mike Smith on Jun 23, 2020 4:40 pm GMT

Thanks for chiming in, Matt. Good questions. Space limitatins kind of limited what we focus on for the article, but: the forecasting work that we reference in this article is based on work at a large IOU and actually does include the inputs that you suggest, including weather and data from over 2 million endpoints. And as to the moving target piece of this, yes, every day we are producing a 10-year hourly forecast. We think that the work we have done here is potentially game chamging in its scope. Thanks again/take care,  --Mike

Howard Smith's picture
Howard Smith on Jun 26, 2020 5:20 am GMT

The forecasting for distribution planning will need to be a 8760 based forecast that looks behind the meter and determines individual firm loadshapes, any "controllable resources" (solar, storage, DSM, dispatchable loads, etc.) and not the net of these.  Also, for the "controllable resources" their will be a need to know who has the control, when they are likely to be controlled and in what time periods, and are they dedicated for customer, retail or wholesale use.  In other words, they will have to be scenarios of load forecasts instead of the traditional single point or in some cases seasonal single point net load forecasts that have been used in the models.

Vijay Rajsekar's picture
Vijay Rajsekar on Jul 3, 2020 12:00 am GMT

Good article. You are right to point out that "forecast-first" approach is the path to take, especially the "Bottom-Up Load Flow Analysis". A well-defined Grid Modernization strategy must include an Advanced Distribution Management System (ADMS) which will greatly help utilities in maintaining high reliability, improved situational awareness of grid and efficiently managing DERs. Most of the traditional SCADA/ EMS vendors now offer a full suite of ADMS functions - a three phase unbalanced load flow analysis is one of the core functions. A casual review of Grid Modernization plans submitted to many state regulators/ PUCs contain an ADMS component combined with DER Management System (DERMS).

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