T&D World - January 2024

Distributed Energy Resources 24 | Electrification 30 | Grid Resilience 34

JANUARY 2024

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IN THIS ISSUE

Vol. 76 | No. 1

34 DEPARTMENTS

6 Global Viewpoint

My Top Three Predictions for 2024 Trends

By TERESA HANSEN, VP of Content

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The Grid’s Tech-Toolbox Is Growing

By GENE WOLF, Technical Writer

14 AES Accelerates with AI

12 Quick Clips

Commissioners Make Compromise Call on PG&E Undergrounding Plan

DATA ANALYTICS

By ALEXINA JACKSON, The AES Corp.

By T&D WORLD Staff

FEATURES 24 A Guiding Light for Microgrids

42 Solutions Center

Virtual Substation Protection, Control and Automation

DISTRIBUTED ENERGY RESOURCES

By KEYUR KACHHIAPATEL and FINNY THOMAS, Commonwealth Edison Co., and KATE M. CUMMINGS and ERICH KELLER, G&W Electric

By HENRY NIVERI, ABB Distribution Solutions

30 Right-Sizing Residential Transformers for EVs ELECTRIFICATION

By JODIE LUPTON, POWER Engineers

8 Charging Ahead

45 Focus: A Lineworker’s View Meet Wes Jones

By AMY FISCHBACH, Field Editor

34 Getting a GRIP on Grid Upgrades GRID RESILIENCE

By RYAN BAKER, Associate Editor

38 Microgrid Fuels Nebraska Capital in Public Power Tradition

PUBLIC POWER

By SCOTT BENSON and KELLEY PORTER, Lincoln Electric System

46 Social Media Hub 47 Advertising Index 48 Straight Talk

Is There a Formula for Successful GRIP Applications?

By DAVID WALLS and JEFF PLEWES, CRA’s Energy Practice

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GLOBAL VIEWPOINT BY TERESA HANSEN, VICE PRESIDENT OF CONTENT

My Top Three Predictions for 2024 Trends

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t’s become customary for me to share my predictions about trending topics for the upcoming year each January. For 2024, I’m presenting three predictions.

1. Electric Utilities Artificial

Intelligence Adoption Grows

My recent column highlighted the potential and adoption of AI by electric utilities. I firmly believe that AI adoption within utilities will increase in 2024. If your company hasn’t initiated plans for AI integration, it’s already lagging. The Boston Consulting Group’s report, titled “How AI Can Speed Climate Action,” released in November 2023, predicts that through scaling proven applications and technology, AI could potentially mitigate 5% to 10% of greenhouse gas emissions (GHG) by 2030. Additionally, AI can aid in enhancing resilience against black-sky hazards by enabling better data sharing and analytics. Moreover, it can facilitate the integration of intermittent renewable energy, optimize grid balancing, and enhance the efficiency of existing fossil-fueled plants, leading to increased capacity without increasing emissions.

The impact of AI on the electric utility industry is hard to comprehend, but AI will undoubtedly increase with time.

However, AI adoption poses challenges and concerns, particularly regarding oversight and cybersecurity. Furthermore, the technology will require additional and larger data centers, prompting utilities to invest more in new generating capacity and transmission & distribution (T&D) infrastructure. These data centers might contribute to climate change by escalating GHG emissions, water usage, environmental warming, and electronic waste. The road ahead with AI is filled with challenges and uncertainties, yet its rapid growth seems inevitable.

2. Electric Vehicle (EV) Growth Continues, but Growth Rate Slows

Grid owners/operators are affected not only by EV adoption rates but also by the pace at which EVs are accepted. While final EV sales figures for 2023 are unavailable at the time of this writing, they’re expected to reach record highs. However, I anticipate that the adoption rate will decrease in 2024. Despite the steady climb in EV sales, statistics reveal that electric vehicles are spending more time on dealers’ lots compared to earlier in the year. An article by Cox Automotive highlighted that it took almost twice as long to sell an EV in the U.S. in August 2023 compared to January 2023, whereas gas-burning vehicle sales remained brisk in August. Some EV manufacturers, like Tesla, have reduced prices and introduced additional incentives to boost sales. Ford, known for offering the popular F-150 Lightning pickup along with a few other all-electric 6

and hybrid vehicles, reported a 43% increase in its November 2023 EV sales compared to November 2022. However, Ford announced a plan to halve its 2024 production of the F-150 Lightning last month.

Many experts attribute concerns about inadequate charging infrastructure as a hindrance to EV adoption. In addition, with crude oil prices dipping below $70 a barrel recently, resulting in lower gas prices, it’s likely to impact EV sales. While environmental concerns are important to many, economic considerations often outweigh them, leading to potential delays in EV purchases. I’m not predicting a loss for EVs in the long run, but for the coming years, gas-fired vehicles will continue to dominate new car sales.

3. Customer Education and Collaboration is Crucial This year, numerous experts have stressed that utilities must engage their customers to achieve their decarbonization goals. Initially, progress toward net-zero carbon largely stemmed from replacing older, inefficient coal-fired power plants with cleaner and more efficient gas-fired combined cycle plants — a phase often referred to as low-hanging fruit.

However, this straightforward phase is over. Moving forward, costs will pose a significant hurdle. Many regions in the U.S. and globally urgently need new infrastructure to replace aging, or new lines to deliver added clean, renewable power necessary for decarbonization and electrification. This endeavor will be incredibly expensive. BloombergNEF’s 2020 study estimated the grid overhaul cost from 2020 to 2050 at $14 trillion. Due to inflation, labor shortages, and supply chain issues, Bloomberg revised this figure to a staggering $21 trillion in mid-2023. Historically, utilities have recuperated such costs from their customers.

However, gaining agreement from customers, consumer groups, politicians, and regulators for the same repayment structure seems unlikely. Years ago, the term ‘negawatt’ was commonplace, and I believe it should be revived. The most cost-effective strategy for both utilities and their customers is to minimize electricity usage whenever possible. This approach saves money and adds no GHG emissions. While this strategy seems obvious for the future, it requires departure from the century-old utility business model. More crucially, it requires utilities to educate customers, earn their trust, and provide financial incentives for reducing electricity consumption during critical periods. Despite years of discussion within the industry, few electricity consumers, especially residential ones, have been offered such programs.

Integrating customers into long-term planning has been overlooked for far too long. I expect that in 2024 and beyond, more utilities will involve customers in their decarbonization plans. Although this strategy won’t eliminate the necessity for a grid overhaul, it can alleviate some of the demands.

T&D World | January 2024

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CHARGING AHEAD

NEW TECHNOLOGIES & NEW OPPORTUNITIES FOR UTILITIES

BY GENE WOLF, TECHNICAL WRITER

The Grid’s Tech-Toolbox Is Growing

E

ver heard of generative artificial intelligence (GenAI)? It has been making lots of attention grabbing headlines. It’s a content creation system, best known for ChatGPT, (i.e., term paper writing). Let’s not go there.

GenAI does so much more. Sticking with the technology, GenAI is part of the machine learning cluster. It utilizes sophisticated AI-based algorithms to generate content (e.g., text, imagery, video, and audio clips). I must confess I’m using GenAI. I have been experimenting with a GenAI application associated with imaging. I’m using it for restoring old photos of ancestors dating back well over a hundred years. Previously, I had to do this process manually. I’d make adjustments with slide controls and watch the effects they had on the faded images. It was a very slow process that took hours per photo.

Last year my digital photo processing suite was updated with GenAI features.

The restoration process took a quantum leap in its abilities for retouching, colorizing, and other corrections to the old photos. If the damage to the photo is extensive, however, it still needs the human touch. Overall, the GenAI infusion helps. Minor restoration techniques are fast, and the automatic features are the way to go. For major repairs it needs me interacting with the program. The GenAI addition is a big plus and I’m not going back to that old system! GenAI tools are also getting attention on the power grid.

A Ticking Time Bomb Have you ever heard of the COBOL (Common Business Oriented Language, circa 1959) computer language? It was all the rage 60 years ago, and amazingly it’s still alive and well today.

COBOL has been dubbed a ticking timebomb by a lot of experts, which has resulted in an uptick in interest. According to

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specialists, COBOL is actively driving many critical systems for business, finance, and administration globally. It’s estimated that roughly 70% of today’s businesses employ COBOL. They didn’t breakdown the business categories, but it’s reasonable to expect that the power delivery industry is part of that 70%, since they too utilize massive billing systems, customer records, and other enterprise-grade applications. It’s an issue because there are only a small number of COBOL experts around the world capable of working with the quirky programming, and no one wants to do a rewrite!

In short, modern systems are cloud oriented and COBOL isn’t, and they don’t play nicely together. So why not replace COBOL and be done with it? Well, that is easier said than done. One anecdote quoted by the experts features a bank in Australia forced by a buyout to replace its COBOL platform at a cost over US$700 million and it took five years. That is where the GenAI technology comes in.

What’s Next Companies such as IBM, Google, Microsoft, and others are developing GenAI translators that can quickly convert legacy COBOL into newer languages like Java.

Experts are predicting these GenAI translators will reduce replacement times from years to months, with significant cost savings. These translators still require human interaction to review and test what they produce, so it’s not total sorcery on GenAI’s part yet.

This is just the tip of the iceberg as far as the global trending of GenAI is concerned. The application is getting a lot of interest. Fortune Business Insights reports, “The global generative AI market size was valued at US$ 29.0 billion in 2022. The market is projected to grow from US$ 43.87 billion in 2023 to US$ 667.96 billion by 2030, exhibiting a CAGR (compound annual growth rate) of 47.5% during the forecast period.”

“Charging Ahead” has featured the integration of AI into systems such as asset management, demand forecasting, renewable energy forecasting, and many other applications.

It has been incorporated into just about every aspect of the smart grid technology. It would probably easier to list what hasn’t been combined with AI than what has been. All of these cases have one thing in common and that’s the big-data used to generate the models used for pattern recognition, forecasting and optimization.

GenAI’s ability to create new content based on those models and to improve the performance of the models is going to be utilized in ways that haven’t been anticipated before. This GenAI transition into digital technologies has happen much faster than anyone expected and it’s giving those who use it a big edge over those not taking advantage. It’s an ambitious undertaking, but it’s definitely not going to be boring!

T&D World | January 2024

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CHARGING AHEAD

BY GENE WOLF, TECHNICAL WRITER

A Stable Future Grid Hybridizing grid-enhancing technologies increases their effectiveness.

I

t should be simple to decarbonize the power grid, so why isn’t it? It turns out there are always speedbumps in every endeavor that were not fully anticipated and the transition to clean power has several. One that has been catching attention is associated with the pace of renewable generation deployment. Another is the speediness of fossil-fuel power plants retirement. Both of these events set in motion another snag, the significant decline in system inertia.

Inertia is the kinetic energy produced by a rotating mass like the armature of a generator. This spinning mass resists change and acts like a buffer. Power engineers refer to it as grid inertia, which allows the grid to ride through disturbances. Think of those times when a momentary loss of power causes the lights to blink. Without inertia those lights will stay off.

If it’s that important why not leave well enough alone as the old saying goes? Once again, it’s not that simple. The energy sector is responsible for 31% of CO2 emissions produced in the U.S. according to the U.S. Energy Information Administration (EIA), These are greenhouse gasses. They are directly linked to global climate change and all the extreme weather events that have been playing havoc with the power system.

Fossil Fuel and Climate Change The biggest producers of those CO2 emissions in the energy sector are fossil-fueled power plants. That brings us back

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to the decarbonization of the power grid with clean energy sources, and transitioning away from fossil-fuel. Worldwide, it’s a mixed bag as far as who is retiring what and when. In the U.S., however, coal-fired generation retirement has really been accelerating with the influence of the Inflation Reduction Act. Based on the latest available data, the Institute for Energy Economics and Financial Analysis (IEEFA) is projecting the U.S. will have cut its peak coal use from 318 gigawatts (GWs) in 2011 to roughly 159 GWs, about 50%, by 2026.

IEEFA estimates U.S. total coal-fired generation will drop to around 116 GWs by 2030 if all of the announced retirements and conversions take place. That’s about 36% of the 2011 peak capacity.

Getting back to inertia, the fossil-fuel generation is being replaced by inverter-based devices (e.g., wind, solar, batteries, etc.), which adds to the complexity. Inverter-based devices use grid-following and grid-forming technologies to turn their direct current outputs into alternating current for use on the power grid. Grid-following inverters are well established, but they tend to trip during any grid disturbance and cannot be reconnect to an unstable grid. On the other hand, grid-forming inverters can address these stability issues by adding what is called virtual inertia, but the technology has its limitations.

Despite being introduced in the early 2000s, they are still considered an emerging technology, and their use is not as widespread as grid-following inverters.

DOE (Department of Energy) says it best, “As wind and solar account for increasing shares of overall electricity supply, it’s becoming impractical to depend on the rest of the grid to manage disturbances.”

One solution would be to replace all the grid-following inverters, but that is unacceptable due to the costs involved. Once again, there is a technology that addresses the issue: the synchronous condenser.

Keeping it simple, a synchronous condenser is a synchronous generator that can be coupled with a flywheel to add extra capacity. It’s powered by a variable-speed motor and connected to the transmission grid through a step-up transformer. When the rotating mass reaches synchronous speed (grid frequency), it’s synchronized with the transmission system. At

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CHARGING AHEAD that point, the synchronous condenser provides inertia along with short-current power, voltage support, and generating/ absorbing reactive power.

Hybridizing Stabilization Synchronous condensers aren’t new, but their abilities took a quantum leap when modern digital controls and sophisticated software were integrated into them. There has also been the development of the hybrid synchronous condenser application. This modernization makes synchronous condensers a valuable addition to the FACTS (flexible AC transmission systems) controller family, and this is where it gets a little complicated so it’s time to speak with an expert.

“Charging Ahead” contacted Ralph Morgenstern, senior sales manager FACTS at Siemens Energy to talk about synchronous condensers and some unique applications Siemens Energy is taking part in. Mr. Morgenstern began saying, “System inertia has been steadily declining on the world’s electric power grids as large-scale, centralized fossil-fuel based power plants are being phased out in favor of renewables. A good example of this is taking place in Ireland, where coal-fired power generation is being phased out and replaced by a lot of wind energy. To make matters more complicated, Ireland is physically and electrically an island.”

Morgenstern continued, “Until now Ireland has had two HVDC interconnections to Great Britain: the East West interconnection and the Moyle interconnection. Currently two more HVDC interconnections are being built; the Greenlink interconnector to Great Britian and the Celtic interconnector to France and that helps. Additionally, Ireland’s ESB (Electric Supply Board) energy company is repurposing their Moneypoint coal-fired power station on the Irish Mid-West coast into Ireland’s first green energy production hub. That’s why inertia is important. The first step before retiring the Moneypoint power plant was the installation of a state-of-the-art synchronous condenser connected to the world’s largest flywheel.

The flywheel rotor weighs over 130 tons and the synchronous condenser’s rotor weighs over 66 tons. Together they deliver around 4,000 megawatt-seconds of inertia capability.

The large flywheel has increased the inertia capability of the synchronous condenser at Moneypoint, but there is more to this story.”

Morgenstern explained, “Siemens Energy has developed a hybrid grid stabilization system utilizing the proven synchronous condenser plus large flywheel technology combined with a large-scale BESS technology. The hybrid grid stabilization system will be installed in the Irish grid at Shannonbridge in County Offaly, Ireland. The Shannonbridge’s hybrid project provides 4,000 megawatt-seconds of inertia capability combined with the 160 megawatt-hour battery energy storage system (BESS). Completing the package are energy conversion systems, a control system, and the necessary medium voltage equipment. The Shannonbridge installation is the first time these technologies have been connected to the transmission grid in a single connection and work has already begun at the site.”

According to Mr. Morgenstern, “Ireland also has market mechanisms in place that allows operators to sell services such as inertia, short-circuit power and reactive power as provided by the synchronous condenser technology. Siemens Energy supports this by providing an energy management system that allows the owner to respond to market demands and power needs in real-time.”

Applying Inertia to the Grid The synchronous condenser has definitely moved from a specialty item to being a feature player for adding renewables to the grid. Global Market Insights reports, “The increasing demand for a reliable and consistent power supply has led to the recognition of synchronous condensers as the preferred solution for grid resilience.” They also noted that the global synchronous condenser market exceeded US$ 1.3 billion in 2022, and estimates the market will continue at a 4.8% CAGR (compound annual growth rate) through 2032.

In 2023, ERCOT (Electric Reliability Council of Texas) finalized their study, “Assessment of Synchronous Condensers to Strength West Texas System.” ERCOT projected the total capacity of inverter-based resources (wind, solar, and energy storage) in West Texas will exceed 42 GWs by 2025.

The study also revealed there were significant stability risks due to system disturbances. ERCOT identified the West Texas system needed six new 350 MVAr (megavolt amperes reactive) synchronous condensers on the 345 kilovolt system.

Each installation will have a total inertia capacity of approximately 2,000 megawatt-seconds, which means a possibility of using a flywheel coupled option. The in-service date would be late 2027.

Also, Estonia, Latvia, and Lithuania are leaving the Russian electric system and will be connecting their transmission systems to Continental Europe’s network by 2025. Studies indicate that synchronous condensers are needed to make this happen. These Baltic countries have formed the Baltic power grid synchronization project, which will install three synchronous condensers in each country. The first synchronous condenser in the series was commissioned by Elering, the Estonian system operator, last year in Püssi, Estonia.

These synchronous condensers will supply inertia to regulate the frequency of the network. They will also provide sufficient short-circuit current for proper protection and automatic operation. These are a few examples of the projects utilizing synchronous condensers on transmission systems around the world. The global market for these applications is expanding and it’s not just taking place on the utility’s side of the meter.

Industry found them valuable for power factor correction and VAR compensation to name a few applications, but the real value comes from the decline of large fossil-fuel fired power plants. This lost inertia is critical to the grid’s stability and resilience. Adding technologies like flywheels, large-scale BESS, and energy management systems increases their effectiveness beyond traditional synchronous condensers. Hybrid synchronous condensers offer the flexibility needed for grid stability and the buffer needed for the rapid shift to renewables!

January 2024 | T&D World

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QUICK CLIPS

BY T&D WORLD STAFF

COMMISSIONERS MAKE COMPROMISE CALL ON PG&E UNDERGROUNDING PLAN California regulators in November adopted “a hybrid approach” to Pacific Gas and Electric Co.’s 2023 general rate case, approving a plan that funds about 60% of the utility’s proposed undergrounding projects in coming years.

The California Public Utilities Commission’s decision Nov. 16 sets PG&E’s 2023 revenue requirement at $13.5 billion, well below the $15.4 billion PG&E executives had requested and a nearly 11% increase from the company’s 2022 authorized revenue requirement. (That $13.5 billion figure will grow to more than $14.8 billion in 2026.) Commissioner John Reynolds, who crafted the compromise that was adopted, said the decision shows the regulatory body’s “commitment to finding a reasonable balance in the face of incredibly challenging circumstances and competing objectives.”

The most-watched element of PG&E’s plan was the proposed burial of roughly 2,100 miles of power lines in high-firerisk areas through the end of 2026, about 350 miles of which are on track to be completed this year. Patti Poppe, CEO of PG&E’s parent company, and her team had requested $6.4 billion for hardening work, $5.9 billion of which would go to undergrounding, which forecast that the miles of lines to be buried would climb to 450 next year before growing to 550 in 2025 and 750 in 2026.

Several stakeholders, led by consumer advocacy groups, had argued that that plan was too expensive and ambitious and called for relying more on covered conductors to reduce fire risk, albeit to a lesser extent.

Commissioners noted the merits of both sides’ arguments in making their hybrid-plan ruling, which approves a little more than $4.7 billion to bury 1,230 miles of lines and cover another 778 miles through 2026. While not close to PG&E’s request, the 1,230 miles is a notable step up from previously proposed decisions that would have allowed just 200 miles and 973 miles, respectively, of undergrounding work.

A big factor in the CPUC not approving the full 2,100-mile request: PG&E’s plan is by far the largest of its kind and is seen as a test case for the economics and construction pace of

large-scale undergrounding, which is today costing the company more than $3 million per mile on average. Commissioners wrote last week that PG&E’s projections it can trim that figure to about $2.8 million by 2026 are “reasonable” and, if achieved, should bolster the company’s standing in future rate requests.

The $4.7 billion decision, commissioners wrote, “provides PG&E an opportunity to demonstrate its capabilities to achieve its forecasted decreasing unit costs, to achieve sufficient risk reduction, and to complete its undergrounding work on the timeline forecast.”

Poppe, who last month said that the previously proposed decisions would have traded “safety and reliability for short-term cost considerations,” struck a more conciliatory tone after the CPUC’s ruling.

“We appreciate the Commission for recognizing the important safety and reliability investments we are making on behalf of our customers, including undergrounding powerlines to permanently reduce wildfire risk,” Poppe said in a statement.

“Undergrounding is the best tool in the highest fire-risk areas to protect our customers and hometowns and improve reliability year-round at the lowest cost to our customers.”

Shares of PG&E (Ticker: PCG) finished trading Nov. 17 at $17.92, roughly 7% higher than their closing price of the previous Friday. The move pushed the company’s market capitalization back above $45 billion. —Geert de Lombaerde

REPORT: U.S. ENERGY SECTOR REACHES TURNING POINT ON TRANSMISSION The stars may finally be aligning to enable the build-out of significant new transmission capacity in the U.S. energy market, according to the latest industry insight report from law firm Troutman Pepper.

The report, Unlocking U.S. Transmission Upgrades – Are We on The Cusp of Real Progress? discusses the views of a range of stakeholders seeking to plan, build or benefit from new transmission infrastructure. It claims that recent legislative reforms, funding opportunities, and improved state-federal coordination have created an opportunity for energy companies and regulators to converge on solutions and remove long-standing roadblocks to new transmission.

“The traditional gap between federal planning standards and state siting and permitting processes has unquestionably impeded

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QUICK CLIPS efforts to upgrade U.S. transmission infrastructure,” said Chris regulators, most notably through the ‘Joint Federal-State Task Jones, partner at Troutman Pepper. “But there are signs these Force on Electric Transmission.’ previously divergent processes can begin pulling in the same Bridging the traditional gap between planning and permitting direction. If the energy sector and its regulators are able to seize holds the key to unlocking U.S. transmission upgrades. Having the moment, we could see a step change in building out the low found this to be well underway, the report concludes that, with a carbon grid the U.S. so urgently needs.” continued commitment to coordination from all parties, the Based on interviews with transmission experts tasked with prospects for a low carbon U.S. grid may never have been higher. delivering transmission upgrades, as well as energy companies dependent upon their success, the report finds four major obstacles to progress: Planning: The unpredictability of interconnection queues remains a severe headache for project developers. But transmission planners also suffer from the uncertainty created by speculative generation projects.

Permitting: Without a major streamlining of processes across state and federal jurisdictions, grid upgrades simply take too long to permit.

Practicalities: A shortage of skilled people and essential equipment threaten to present future pinch points unless addressed today.

Paying for upgrades: The buildout of new transmission capacity is capital-intensive and the industry will need to clearly communicate the benefits while passing a fair proportion of cost to consumer bills.

Save time and money with Despite these obstacles, the report finds that recent and ongoing regulatory reforms paint a compelling case for optimism: The Federal Energy Regulatory • Battery Tools • Stringing Blocks & Attachments Commission is seeking to increase • Hydraulic Pole Pullers • Grounded Stringing Blocks certainty for transmission planners, • Traveling Grounds • Helicopter Stringing Blocks most notably through its recent rule, • Groundsets & Jumpersets • Fiberglass Hot Arms Order No.2023.

• And much more!

• Chain Hoists The federal government is looking • Compression Tools & Dies to boost FERC’s leadership role, with • Cutting Tools the notion of one agency in overall • Impact Wrenches charge being well supported on • Magnetic Drill Presses Capitol Hill.

The Infrastructure Investment and Jobs Act and the Inflation Reduction Act have both provided legislative vehicles to stimulate multi-agency coordination, backed up by a raft of new programs, initiatives, and 877-860-5666 grants from DOE. tallmanequipment.com/rentals FERC has begun to engage with state policymakers and

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AES Accelerates with AI The company has taken significant steps to harness the value of data through artificial intelligence and machine learning.

By ALEXINA JACKSON, The AES Corporation

Utilities must be able to make sense of the huge amounts of data produced by some of the new grid monitoring systems in use. Photo courtesy of AES Corp.

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AES is pioneering new technologies and programs with AI/ML to create data-driven methods that advance its green transition while maintaining grid reliability and providing new value to customers.

AES uses AI/ML advancements to analyze massive amounts of data and more accurately predict transmission line capacity and tree trimming needs, enabling the company to make fuller use of grid assets and perform preventative maintenance Photo courtesy of AES Corp.

T

he transition to a decarbonized, clean energy future requires the electric utility industry to manage two exacting challenges successfully in the years ahead: Utilities around the world will need to accelerate the deployment of gridconnected renewable energy resources substantially while delivering reliable and affordable energy. Achieving both these outcomes will be far from easy.

According to energy policy simulator modeling by Energy Innovation Policy & Technology LLC in 2021, the world will need nearly quadruple the amount of renewable energy currently connected to the grid by 2030 to achieve the ambitious goals set by the Paris Agreement and limit global warming to 1.5°C (2.7°F). In the U.S., this calls for investing in new clean energy solutions and technologies that will reduce dependence on fossil fuels, grow renewable capacity, and improve grid performance to reliably power homes, businesses and transportation for years to come.

Artificial intelligence and machine learning (AI/ML) will be critical to this process.

These technologies can enable utilities — like The AES Corporation — to supercharge their data usage to identify grid patterns, inefficiencies and other valuable insights, helping grid owners and operators to support an efficient and repsonsible clean energy transition for grid customers while optimizing their businesses.

AES is pioneering new technologies and programs with AI/ML to create data-driven methods that advance its green transition while maintaining grid reliability and providing new value to customers. The utility’s deep commitment to innovation drives these advancements forward every day as it embraces a dynamic, forward-thinking approach — investing in technology that is scalable now, in the near future and years from now — to accelerate the future of energy.

AI For VM Today, vegetation is a leading cause of unplanned electric service outages, according to the Federal Energy Regulatory Commission (FERC). In 2021, Accenture analysts estimated U.S. utilities spend up to $8 billion on vegetation management each year.

Effectively managing the growth of trees, shrubs, and vegetation near power lines 16 T&D World | January 2024

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DATA ANALYTICS

Cycle-based trimming

Risk-based trimming

Months since last trim

Lower risk

Higher risk

The map above shows AES Indiana’s previous cycle-based trim schedule, which is widely used by utilities.

Using AI tools, AES Indiana’s service area can be clustered based on vegetation risk. We now use a risk-based strategy to trim trees for improved reliability and efficiency.

Map of AES Indiana Service Territory

Around 20% of sections comprise 80% of the risk.

From cycle-based trimming to risk-based trimming.

and other vital parts of the grid is crucial to maintaining grid reliability and safety, minimizing power outages and reducing costs. And, as climate change progressively leads to more severe weather events, outage risk will increase unless grid operators proactively and intelligently manage vegetation in their service territories.

AI/ML advancements enable grid operators to identify areas most in need of tree trimming instead of using the traditional cycle-based approach to vegetation management. By analyzing historical trimming data, tree-related outage data, utility-owned and publicly sourced imagery, weather patterns and financial information, utilities can prioritize specific locations for

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DATA ANALYTICS

AI Asset Optimization Connecting renewables to the grid more quickly while providing affordable, reliable energy to customers requires finding new ways to optimize existing assets, so clean energy can be provided when and where it is needed. AI/ML technologies can make this possible by identifying irregularities and trends in asset performance that indicate potential system failures, helping to prevent service disruptions, protect equipment, shorten downtime and even extend the lifetime of assets.

AES uses AI/ML advancements to analyze massive amounts of data and predict when assets may fail, enabling the utility to perform preventive maintenance rather than being reactive and waiting for an issue to occur. This practice keeps the utility’s systems up and running, so it can provide reliable energy to customers. AI/ML advancements also make it possible for utilities to optimize energy production and asset operation An AES solar farm. The AI/ML applications used by AES optimize the use of renewable energy based on market and system conditions, making facilities by anticipating weather patterns. Photo courtesy of AES Corp. energy costs more affordable. trimming with the greatest expected impact on grid reliability.

Furthermore, AI/ML tools can help utilities to be better These AI/ML innovations are already at work every day at prepared for weather-related challenges by understanding the AES. The utility uses data insights to deploy resources to areas at amount of energy that will be needed in various conditions and higher risk for an outage, deprioritizing areas that do not have the corresponding amount that can be generated and delivered. an immediate need. The results have been improved reliability Weather heavily influences both electricity demand and supply. and lower maintenance costs. AES Indiana, in particular, has For example, when it is hot, air conditioning use and demand reduced vegetation-related interruptions by 3.5% in less than two for energy surges, but so can the production of solar-generated years, a meaningful improvement for customers. AES continues electricity. Weather conditions like severe storms — which are to build on this progress by improving its vegetation analytics becoming more common — can directly affect the output of model with satellite imagery. wind and solar facilities and a utility’s ability to deliver energy What is more, the utility has found that when it is more tar- where and when it is needed most. geted and strategic with its resources — money, people and With AI/ML, grid operators can anticipate weather patterns, time — it can smartly and efficiently meet customer needs while so they can more efficiently dispatch energy to load centers accelerating grid modernization. while supporting grid reliability and emergency response. Asset owners also can use AI/ML to co-optimize storage and plant output to improve production and operations. AES uses advanced data analytics and ML to translate weather forecasts into generation forecasts. These more precise predictions make it possible to operate physical assets more efficiently. Initial field-testing of its next-generation wind forecasting model at its Valcour Wind sites in New York showed an initial 15% gain in wind forecasting accuracy over current industry tools.

An Eye on the Line

The Mountain View Wind Energy Facility in California. Initial field-testing of its next-generation wind forecasting model at its Valcour Wind sites in New York showed an initial 15% gain in wind forecasting accuracy over current industry tools. Photo courtesy of AES Corp.

AES also is deploying dynamic line rating — a technology that enables high-fidelity calculations of how much energy can be moved through a power line at a specific time based on ambient and line conditions. Air temperature, solar radiation, and wind speed and direction all affect power line performance and capacity. For example, wind traveling across a power line can increase the amount of energy that can be carried through the line.

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DATA ANALYTICS

AES Corp.’s Alamitos Battery Energy Storage System. Energy storage will be an instrumental technology for achieving sustainability and reliability goals. Photo courtesy of AES Corp.

Historically, grid operators did not have access to the data nor the computational power to consider detailed situational information when determining how much energy can be moved through the grid. Instead, operators have relied on conservatively set static line ratings based on worst-case scenarios and best estimates. This made sense in the 20th century when the standards were first set and tools were limited. Now, as demands on the grid grow, antiquated practices often lead to under-delivery of energy across the grid and further delay the decarbonization of the energy system.

The value of this untapped grid capacity is well recognized, including by FERC, which will soon require grid operators

to start applying hourly (or better) calculations to near-term transmission operations, to maximize the transfer capacity of each line. However, even this approach leaves some untapped line capacity.

By adding wind speed and direction to ambient line rating and installing sensors in key locations on the grid, grid owners and operators will have a more accurate and dynamic understanding of the amount of energy that can flow through a line. As weather changes throughout the day, so does production and consumption of energy, and having a granular, accurate view of line carrying capacity will help to make the system more efficient.

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DATA ANALYTICS The ability to optimally use the electrical grid will be fully realized when asset owners and grid operators use robust operational data — contextualized by AI — to bridge the gap between planning and operations with dynamic, high-fidelity knowledge.

A Digital Grid

Installation of dynamic line rating equipment. DLR is a technology that enables high-fidelity calculations of how much energy can be moved through a power line at a specific time based on ambient temperature and line conditions. The ability to optimally use the electrical grid will be fully realized when asset owners and grid operators use robust operational data — contextualized by AI — to bridge the gap between planning and operations with dynamic, high-fidelity knowledge. Photo courtesy of AES Corp.

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To meet the U.S. goal of creating a clean and efficient grid by 2035 while maintaining affordability and reliability, utilities must think beyond incremental deployments of marketready technologies and think instead about modernizing the grid at scale and speed. According to the National Renewable Energy Laboratory in its study Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035, this will require a massive buildout of renewables at up to six times the current rate and a tripling of current transmission capacity. To do this, the energy industry must integrate new grid-enhancing technologies (GETs) that maximize capacity along new and existing transmission lines.

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DATA ANALYTICS wide variety of resources on the grid.

Inaccurate representation of grid asArtificial Intelligence Faster reliable interconnection sets makes the system less reliable and Current process improved by a shared, accurate model capable of quick results more expensive to operate, accordModels ing to Queued Up: Characteristics of Operations and planning converge Power Plants Seeking Transmission Data High fidelity data from operations allow continuous evaluation of current and future grid Interconnection as of the End of 2020, needs a study by Lawrence Berkeley National Compute Laboratory. Berkeley Lab published Fluid, open, optimal grid Insights from data and models drive optimization a series of briefs in 2023 analyzing of flexible resources and demand across the grid Standards and Protocols interconnection cost trends across five U.S. wholesale electricity markets that Better data and models enable orderly, reliable change. found incomplete modeling of grid GETs — like dynamic line rating — are largely software solu- carrying capacity results in grid underutilization and network tions that produce the data-rich insights needed to reach de- upgrade costs reflecting 20% to 40% of new-generation-project carbonization goals. As more digital assets are installed on the capital expenditures. grid, owners, operators and utilities will receive more precise The digitalization of the grid also enables the application of a and timely information about how their energy system works system of protocols and standards to help ensure grid reliability under a variety of conditions. Especially when coupled with and control, not unlike how the U.S. provides predictable and AI-assist tools, this data will enable smarter predictive and real- coordinated internet service. Beyond reliability benefits, digitatime decision-making and help the industry build a holistic lization can help to identify optimal locations for energy storage end-to-end view of the grid. across the grid, so owners and operators can create electron Such a reality may seem complex, but it is achievable in a warehouses — or energy buffers — for on-demand access by digital system with increasingly accurate data, flexible and customers in a reliable, resilient and affordable way. This bufresponsive assets, and advanced computational capabilities. fer is also valuable because it can help to solve the increasing Investing in these improvements is critical because existing number and complexity of resources in the distribution system models, built for analog fossil fuel systems and one-way power as well as responsively and flexibly address the dynamic needs flows, struggle to accurately represent the potential of the of the transmission system.

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DATA ANALYTICS

Virtual Power Plants

Underlying the transition to a digital grid are AI/ML. The data collected, modeled and analyzed using AI/ML creates a virtuous circle of continuous refinement and improvement.

By allowing trained AI to engage in problemsolving conversations with engineers, the tedious and manual problem of grid modeling for planning and interconnection can be improved significantly. The planning process can be enhanced even further by high-quality data streams from digital resources and advances in computing efficiency, speeding up modeling and optimizing the incorporation of new assets. These advancements in AI-assist, high-quality data and computation help to bring T&D together into a fully integrated, holistic grid-planning process with an interconnected workforce that now has bandwidth and data-driven insights to identify and solve future grid, customer and decarbonization needs in a coordinated way across all levels of the grid.

A workforce so equipped can leverage AI/ ML to optimize active participation of distributed energy resources (DERs), including virtual power plants (VPPs), to solve local grid needs in a more delegated and distributed manner. Studying and modeling weather patterns has become an even more important part of running a By aggregating a collection of smaller energy reliable power grid as climate impacts grow and weather becomes less predictable. Photo by NASA. resources (for example, smart thermostats, electric vehicles, households and businesses. GETs are being strategically adopted batteries, distributed solar and other smart devices), VPPs can by major utilities. AES Indiana and Ohio’s 2023 deployment of provide generation resources, reliability and economic value the first large-scale dynamic line rating system in the U.S. is a to the grid — much like traditional power plants. When these great example. The energy system will continue to see more assets are optimized and coordinated intelligently, they provide inverter-based generation that is inherently digital, flexible, and cost-effective electrification, a locally resilient energy supply and capable of being turned off and on to address demand peaks and troughs, as well as dynamic system conditions. grid services while reducing T&D bottlenecks.

AES is committed to advancing a responsible transition As a next-generation utility, AES is at the cutting edge of exploring new technologies to build a digital grid that is not and driving innovation in the renewables sector, utility oponly capable of greater flexibility and reliability but optimized erations and energy markets — but this must be a collective to handle and integrate the renewable assets that will be needed effort. It is critical for all players in the energy ecosystem to to decarbonize the energy system. adopt an innovative mindset and invest in advanced digital technologies to build a more resilient and sustainable Where To Go From Here energy future.

By embracing intelligent digitalization, exploring innovative The industry must move quickly to bring more renewables solutions and utilizing data — which compounds in value over online while improving grid reliability and energy affordability, time — grid owners, operators and energy producers can build and AI/ML will help to achieve these goals. Fortunately, the work a more dynamic and resilient grid that reliably delivers clean, the industry is doing today will pay additional dividends in the affordable energy. AES is already leveraging AI to assist in veg- future. The more data that is collected, the better insights the etation management, weather forecasting and asset optimiza- industry can glean and apply proactive steps to build a strontion, and it has started using AI to analyze transmission system ger, more dynamic and inclusive grid that runs increasingly on data to enable dynamic line ratings. Embracing a digital future renewable energy resources. powered, in part, by AI/ML will enable utilities to reach their clean energy goals more quickly.

ALEXINA JACKSON is vice president of strategic development at The AES CorporaAnd, a digital system might be closer than the industry thinks. tion. In this role, Jackson is responsible for developing AES’ vision for the electric grid An increase in DER capacity is forecasted to align with grid- of the future and an ecosystem to drive toward this shared vision. Previously at AES, scale capacity additions through 2027, according to a May 2023 Jackson worked in a customer innovation leadership role. Before joining the company, report, Real Reliability: The Value of Virtual Power, from The she worked as an attorney with Crowell & Moring LLP and as a strategy consultant in Brattle Group. Digital energy devices are a growing part of the United States, Brazil, Spain and France.

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DISTRIBUTED ENERGY RESOURCES

The 2 MW rooftop solar array included in the project. ComEd and G&W Electric worked in lockstep to define the scope of the project and determine how to integrate the communication between the utility’s equipment and microgrid using a proprietary peer-to-peer protocol ComEd had not previously deployed for this type of project. Photos courtesy of G&W Electric.

A Guiding Light for Microgrids ComEd shares six key steps and several lessons learned when partnering with G&W Electric to bring a microgrid on-line.

By KEYUR KACHHIAPATEL and FINNY THOMAS, Commonwealth Edison Co., and KATE M. CUMMINGS and ERICH KELLER, G&W Electric

M

icrogrid projects are gaining traction rapidly as a growing number of industries work with utilities to enhance grid resilience and integrate renewable energy sources. For instance, when G&W Electric, a power equipment manufacturer, decided to implement its own microgrid, the first call it made was to its local utility, Commonwealth Edison Co. (ComEd). This pioneering collaboration not only sheds light on the intricacies of deploying microgrids but also offers valuable insights for any utility considering similar projects.

G&W Electric started down the microgrid path after experiencing a glitch in its power system in 2017, which caused significant downtime in its molding facility, leading to tens of thousands of dollars in lost production, added maintenance and discarded materials. By working closely with ComEd to install a microgrid

on its campus, G&W Electric sought to provide uninterrupted, premium power and shield against the potential havoc of external grid failures. The endeavor provided a unique scenario because it was the first microgrid project of its kind for both the utility and manufacturer.

The project ultimately included a 2-MW rooftop solar array; battery storage system with four 500-kW blocks; 2-MW diesel generator for prolonged outages; flywheel that detects outages in one-fourth of a cycle and dispenses backup power while the battery or diesel generator come on-line; medium-voltage switchgear; and pole-mounted reclosers that enable a rapid transfer to an alternate power source within 10 seconds of a primary feeder failure.

ComEd’s proactive involvement and guidance proved critical to this complex project’s success. The utility took six key steps

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DISTRIBUTED ENERGY RESOURCES with its partner to ensure implementation success and learned several lessons along the way.

Step 1: Assemble the Team The journey toward microgrid implementation began with assembling a dedicated project team of engineers, project managers and other members from ComEd and G&W Electric.

Fostering close collaboration between the equipment manufacturer and utility from the outset laid a solid foundation for project success.

The ComEd team was on-site in G&W Electric’s labs on a regular basis to understand the microgrid components and how they would commu- The 2 MW rooftop solar array included in the project. ComEd evaluated the impact of integrating renewable energy sources, such as solar and batteries, into the external grid. nicate with the utility’s equipment.

From there, the utility could create prototypes, perform test- Electric provided input on the assets that would be part of the ing and validate its findings before linking the microgrid to microgrid, and ComEd conducted studies to assess the impact of the external grid. the microgrid on its system. This collaborative approach ensured the microgrid seamlessly integrated into ComEd’s infrastructure.

Step 2: Set Scope And Agreement While the specifics may vary, such studies are indispensable for Defining the project scope and securing an interconnection microgrid projects. And since the interconnection agreement agreement were critical milestones in the project road map. must be submitted, reviewed and approved before construction ComEd spearheaded feasibility and system impact studies, crucial starts, it is important to have all the proper documentation precursors to drafting the interconnection agreement. G&W in place beforehand.

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DISTRIBUTED ENERGY RESOURCES critical for maintaining grid integrity and protecting microgrid assets. Understanding the nuances of these studies is essential for utilities contemplating similar projects.

The bottom line for other utilities setting out to link to and support industrial microgrid projects: Be prepared to conduct studies, learn iteratively and then do the study again until all outstanding questions are addressed. Even more than with most projects, measuring twice and cutting once during microgrid planning will head off frustrating implementation delays.

Step 4: Overcommunicate Clear, effective communication and role definition were paramount to the success of this collaboration. In fact, the importance of clearly communicating the plan, roles and responsibilities of all stakeholders cannot be overstated.

Clearly defined roles and responsibilities will mitigate confusion and help team members to execute their assigned duties.

Bring the grid operators into the fold early in the project.

Even though they will not be implementing the microgrid itself, they are the ones who see the alarms and need to understand how to effectively work with the utility when issues arise. For this project, ComEd created detailed presentations for grid operators, outlining alarm protocols and response procedures.

This ensured the operators were well-versed in their roles and responsibilities across various scenarios.

Meanwhile, ComEd focused on the question of how best to manage communication with a customer-owned device when challenges arise. How should the response actions be divided up?

Who should own what? It was an ongoing discussion and learning process. When a project integrates utility-owned and customerowned equipment, it melds together, requiring both parties to understand clearly what steps each will take to resolve problems together.

ComEd’s project included a 2-MW rooftop solar array; battery storage system with four 500-kW blocks and a 2-MW diesel generator for prolonged outages, among other technologies.

ComEd and G&W Electric worked in lockstep to define the scope of the project and determine how to integrate the communication between the utility’s equipment and microgrid using a proprietary peer-to-peer protocol ComEd had not previously deployed for this type of project.

Creating a prototype was essential to providing an understanding of how the scheme would work. Before performing any of the scheme changes on the line that served G&W Electric, ComEd conducted a significant amount of lab work to validate the project was operationally sound.

Step 3: Conduct Studies ComEd and G&W Electric conducted studies focusing on distinct aspects of the project. The utility evaluated the impact of integrating renewable energy sources, such as solar and batteries, into the external grid. G&W Electric’s studies revolved around fault detection and isolation within the microgrid,

Step 5: Test, Test, Test

The system includes a flywheel system that detects outages in one-fourth of a cycle and dispenses backup power while the battery or diesel generator comes online.

Rigorous testing of the equipment’s connectivity and communication protocols constituted a substantial portion of the microgrid implementation process. Multiple rounds of testing occurred both at ComEd’s labs and on-site. The objective was to validate the communication and protection schemes. This phase uncovered its fair share of challenges, underscoring the importance of thorough testing in microgrid projects.

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DISTRIBUTED ENERGY RESOURCES In preparation for the go-live date, ComEd set up a testing protocol of all the major scenarios the utility had to run through and validate before it could approve bringing the system on-line. As part of the process, ComEd created a detailed checklist to ensure all required testing was covered.

Once again, communication was key to ensuring the utility accomplished everything it needed to do on the golive day. It was not a scenario where the parties could call off the project and come back the next day. Collaboration was vital.

Step 6: Transition To Live On the day the microgrid was scheduled to energize, ComEd was on hand to test and ensure the reliability and safety of the grid. ComEd and G&W Electric had a limited time frame to perform final testing on the go-live date.

While the G&W Electric facility was off A Viper ST recloser. The project partners updated the firmware in the reclosers for this project. the grid and self-islanding on generators before the launch, ComEd ran through all the possible opera- a fault condition was occurring. That allowed ComEd to validate tions and scenarios. Using multiple relay test sets enabled the the microgrid was completing the sequence of operations reutility to inject voltage and current to make the equipment think quired when it sees fault conditions, including communicating

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DISTRIBUTED ENERGY RESOURCES the correct information to the G&W Electric gear, which was confirmed to properly act on that information.

Critical findings included making sure the customer solar inverters would shut down when grid power is lost. When grid power is shut off, ComEd linemen cannot start troubleshooting until they test the line to ensure it is dead. If a solar facility starts generating power onto what is thought to be a deenergized line while linemen are working on it, the results would be catastrophic.

This step required additional testing protocols to account for the fact the microgrid was communicating to two automation devices, G&W Electric Viper reclosers. Testing ensured that if one Viper recloser sees a certain condition, it communicates the status to the other Viper recloser as well as the G&W Electric Trident gear — and that those devices then respond accordingly.

Once those tests were completed, ComEd validated the devices responded appropriately to the simulated conditions and operated correctly. The utility further confirmed G&W Electric’s microgrid operators were receiving correct statuses through their supervisory control and data acquisition (SCADA) monitoring interface and could control the devices properly.

Challenges Faced The project was successfully brought on-line despite the tight time frame and steep learning curves. To be sure, throughout the project challenges emerged that can offer valuable insights for other utilities and their partners on future microgrid initiatives.

The project encountered communication challenges that necessitated on-the-fly adjustments to fiber connectors. The main challenge was that ComEd’s automation system communicates on a radio network, as the utility is still in the process of transitioning to a fiber network for faster communication.

However, it worked with a fiber contractor to run the fiber line needed for this project. These modifications were crucial to ensuring proper functioning of the proprietary peer-to-peer communication protocol. This experience underscores the need for adaptability during microgrid implementation, where unforeseen issues may arise and require swift solutions.

Outdated firmware and software also presented hurdles during the project. These issues were resolved through a twofold approach: updating the firmware for the Viper reclosers in the field and employing modified versions of older software.

Staying current with technology emerged as a crucial factor in the ever-evolving landscape of microgrid development.

In addition, despite rigorous testing at the ComEd lab and G&W Electric facility, teams on both sides decided to conduct synchronized testing of the relay during commissioning to ensure successful execution of the final configuration. This required different test kits for each of three remote switches connected to one master test setup, simulating multiple synchronized fault scenarios. To enable communication with different test kits, Ethernet cables were routed between all three remote test kits to the master test setup, which served as the final operation check of protection settings and communication between the equipment and utility’s SCADA system.

Key Takeaways ComEd’s work on G&W Electric’s microgrid provides several useful takeaways for utilities venturing into similar projects: • Partner early — Collaboration is key. ComEd’s commitment to work closely with G&W Electric starting in the preplanning phase paved the way for project success. By establishing close communications and coordination at the outset, it was easier to address issues that popped up later in the project. Both of these also helped to foster collaborative problem solving throughout the project’s life cycle.

• Know the limitations — The utility should understand and clearly communicate to the microgrid partner any feeder capacity limits to keep a project in proper scale.

Feasibility studies are a must.

• Test and validate — Safety and project viability are critical. Establish shared protocols and stick to them.

• Be nimble — Microgrid interconnects are new terrain for companies and utilities alike. For a successful implementation, utilities and their partners must demonstrate the adaptability to pivot when needed.

Every microgrid solution requires a holistic, customized approach to meet the needs of both the utility and implementing organization. The lessons shared here can help to prepare utilities for their own successful microgrid projects no matter how unique the implementation turns out to be.

KEYUR KACHHIAPATEL (Keyur.Kachhiapatel@ComEd.com) is a senior engineer on the distribution automation engineering team at ComEd. He started at ComEd by designing relay protection schemes for high-voltage transmission lines and has since transitioned to advanced protection schemes for distribution lines. Some of the pilots Kachhiapatel has contributed to include protection strategies for three-phase to one-phase lateral lines and microgrid protection. He holds a BSEE degree from the University of Illinois, Chicago.

FINNY THOMAS (Finny.Thomas@ComEd.com) is a field engineer on the distribution automation engineering team at ComEd. Thomas has worked on a variety of projects at ComEd, including generic object-oriented substation event testing to enable advanced distribution protection schemes in northern Illinois and ComEd’s REACTs project to test fiber communication throughout the grid. Thomas holds a BSME degree from the Milwaukee School of Engineering.

KATE M. CUMMINGS (kcummings@gwelec.com ) manages distribution automation for switchgear at G&W Electric. She received a BSEE from the University of Illinois at Chicago and has more than 15 years of experience in the power industry at G&W Electric, Ohmite Manufacturing and Maplechase. Cummings is actively involved in several professional organizations, including IEEE, IEEE PES and NEMA. Along with being key in developing and implementing G&W Electric’s microgrid, she also helped to design the Trident-SR controls installed at Lambeau Field in Green Bay, Wisconsin.

ERICH KELLER (ekeller@gwelec.com) is an engineering manager of power grid automation at G&W Electric. He is responsible for managing power system automation specification, design, factory acceptance testing and site commissioning. Most recently, he acted as chief engineer for integration of G&W Electric’s microgrid at headquarters. Before joining G&W Electric in 2011, Keller was employed at ZIV USA in Des Plaines, Illinois. He received a BSEE degree from Valparaiso University and an MSEE degree from the Illinois Institute of Technology.

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ELECTRIFICATION

With utilities currently focused on developing plans to accommodate increasing EV loads, evaluating the way transformers are currently being sized for new construction and routine maintenance could reduce costs and waste. Photo by POWER Engineers.

Right-Sizing Residential Transformers for EVs Electric vehicle charger demand can overload transformers, wearing them down early, but careful planning can mitigate these harmful effects.

By JODIE LUPTON, POWER Engineers

E

xactly how quickly the electrification of transportation is ramping up is still an open question. Electric vehicle (EV) adoption projections vary widely, with sources suggesting EV sales’ market share could reach anywhere between 35% and 50% by 2030. According to the automotive research and intelligence firm Wards Intelligence, EVs already represented 11% of light-duty vehicle sales in the United States in 2021.

Though aligned with aggressive decarbonization and electrification goals, these uptake rates pose a challenge for utilities. As EVs gain market share and lawmakers deploy EV-friendly policy to accelerate adoption, utilities must prepare for unknown increases in residential loads due to EV charging. Accommodating the added load could entail changes to established design parameters.

To better understand the impact of increasing EV loads on residential transformers — essential for stepping distribution voltages down for residential end use — our team at POWER Engineers used CYME 9.0 to perform quasi-static time series analysis on a realistic distribution model from the National Renewable Energy Laboratory (NREL). That, in turn, demanded

developing a method for forecasting and creating residential EV charging time series profiles for use in the analysis.

Using these tools, we evaluated changes in diversity factor, load factor and average residential load associated with EV charging.

We also identified likely transformer upgrades needed to safely incorporate EV loads into established residential distribution systems. This supports a wider consideration of current transformer sizing procedures with respect to EV loading growth.

Assets like transformers are expected to last 20 to 30 years or more. With EV market share growing year after year, understanding the impact of the associated load changes — and the methodological improvements or technological upgrades needed to accommodate them — is of critical concern for utilities and stakeholders.

Together with record transformer demand and ongoing supply chain bottlenecks, these changes in consumer habits put a premium on accurate, cost- and resource-conscious transformer sizing for current and future deployment. This analysis of NREL’s model facilitated a more precise understanding of the impact

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ELECTRIFICATION Table 1: Percentage of EV adoption per customer for each simulation case.

Case

Percentage of loads selected for first EV

Percentage of loads selected for second EV 0%

Low

5%

Medium

30%

0%

High

60%

15%

TOU

30% with 50% adoption of TOU rate plan

of EV loads on residential transformers, which will allow planners to develop more robust design practices to guide pivotal upgrade decisions with EV adoption growth in mind.

Study Assumptions Developing realistic charging profiles is difficult. To date, studies aimed at building realistic EV load profiles often rely on small sample sizes from a handful of cities. Though foundational first steps, these studies afford limited insight for variable, evolving habits across regions and demographics. A scarcity of reliable data also complicates modelling. Public chargers often collect data on car type and charging duration, but these are likely not the primary charging port for most EV consumers.

For example, EPRI reports that 80% of charging occurs at home, where 240 V outlets often do not collect data. Most home charging data comes from smart meters provided by entities with private agreements with their customers. This information can be used to model specific locations, but may not support realistic, reliable conclusions for utilities that want to understand EV charging in other areas.

Compensating for these challenges demanded assumptions.

For the purposes of our study, residential loads were identified as EV charging locations based on low, medium, high, and medium time-of-use adoption cases, with 70% of charging locations assigned a battery electric vehicle with a 68.4 kWh capacity and 30% assigned a plugin hybrid electric vehicle with a 13.5 kWh capacity.

Level 2 chargers with a 7.2 kW charging rate supplied the EVs. To figure out what time of day a customer begins charging their vehicle, we used probability density functions from both the BEV and PHEV. This gave us the probability a customer would start charging their EV based on their current battery level or state of charge (SoC). Once a customer began charging based on their SoC, the second probability function was used to assign them a charging start time within the model.

Based on the average kWh/mile rating of two common EV models (Tesla Model X and Chevy Volt), we assigned BEVs an average discharge rate of 9.4 kWh/day (ơ=10.25 kWh/day) and PHEVs an average discharge rate of 0 kWh/day (ơ=7.3 kWh/day).

A pole mounted distribution transformer delivering electricity to multiple residential loads.

medium (30% per customer) and high (60% per customer).

Each customer received a PHEV, BEV or no EV based on the outlined adoption rates (low, medium, high). 365 days of loading was simulated with a unique 15-minute resolution loading profile for each customer. The SoC-based probability density functions discussed above were used to decide customer charging habits. If a customer charged their EV on a given day, we used the probability density function to create normalized weekday and weekend time profiles to determine when the vehicle starts charging. Shifting the weekday probability of charging start time to peak at 23:00 without modifying the weekend charging profile allowed us to also evaluate a TOU plan.

To see the impacts of EV loads on residential transformers, we used the feeder topology. JSON placement files provided with the NREL data defined distinct levels of adoption and EV load placement. The high adoption rate case includes a possible second EV at some residences. The models defined residential customer time-series load data as a percentage of total possible load in 15-minute intervals over 365 days, with the EV charging

Testing To assess the likely impacts of increasing EV adoption and associated charging loads on residential transformers, datasets from NREL supplied a test bed to implement residential EV loads in a realistic but synthetic distribution model. We performed quasi-static time series (QSTS) analysis of residential EV charging time-series data created in Python 3 for three levels of EV adoption — low (5% EV adoption per customer),

Simplified representation of feeder topology used for simulation.

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ELECTRIFICATION Change in Diversity Factor for Transformers with EV Loads 240

Low

220

Medium High

Frequency of occurances

200

TOU

180 160 140 120 100 80 60 40 20

0.44-0.46

0.4-0.44

0.36-0.4

0.32-0.36

0.28-0.32

0.24-0.28

0.2-0.24

0.16-0.2

0.12-0.16

0.08-0.12

0.04-0.08

0-0.04

-0.04-0

-0.08--0.04

-0.12--0.08

-0.16--0.12

-0.2--0.16

-0.24--0.2

-0.28--0.24

-0.32--0.28

-0.36--0.32

0

Change in diversity factor

Change in diversity factor for transformers with EV loads.

load profiles added where EVs were assigned. A Python script compared customer time-series load profiles with the total load seen on the transformer high side and supplied the diversity factor for each transformer over the entire 365-day period.

To relate the change in diversity factor to transformer loading, we calculated the seasonal (summer and winter) load factor for each transformer. To fully understand the effects of the increase in EV loads on overall residential transformers loading, we developed a function to determine transformer damage likelihoods based on percentage of loading over nameplate rating and the amount of time at that rating (defined based on criteria set out by Eaton for single-phase, dry type transformers, as required by ANSI).

Transformer loadings, integrated over 12 hours, which surpassed this function were considered indicative of potential damage. Though the criteria used to develop this function do Transformer Upgrades by Rating 60 49

Number of Occurances

50

47

40 30

25 20

20 10

10

8 3

2

5 0

4 0

0 15

25 37.5 50 Low

15

25 37.5 50 Medium

15

25 37.5 50 High

Number of transformer upgrades to mitigate potential overloads by KVA rating.

Table 2. Increase in potential transformer damage per adoption case Low

19

Medium

157

High

415

Medium TOU

136

not account for all relevant variables, it nonetheless provides an informative — if simplified — view of potential transformer damage based on EV load.

Results In all adoption cases, the vast majority of transformers saw an increase in diversity factor. Broadly, more EV loads lead to higher diversity factors. With a high rate of EV adoption, 60% of transformers experience a diversity factor increase while 21% see no change. Current transformer design practices that size transformers based on a set diversity factor should be adequate in over 81% of cases, requiring no change up to a high EV adoption percent36 age. Indeed, in 60% of cases these practices could even be conservative, leading to underused transformers.

The transformer failure function discussed above determined the 7 number of transformers that might 2 0 be damaged by increased EV loads.

15 25 37.5 50 The function does not guarantee failure, but does indicate that damage TOU has likely occurred, increasing the chance of future failures.

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ELECTRIFICATION

150

Change in load factor

0.04-0.06

0.02-0.04

0-0.02

0.04-0.06

0.02-0.04

0-0.02

-0.02-0

-0.04--0.02

-0.06--0.04

-0.1--0.08

-0.08--0.06

0

-0.12--0.1

0 -0.14--0.12

50 -0.16--0.14

50

-0.02-0

100

-0.04--0.02

100

200

-0.06--0.04

150

250

-0.08--0.06

200

300

-0.1--0.08

250

350

-0.12--0.1

300

Low Medium High TOU

400

-0.14--0.12

350

Change in Summer Load Factor for Transformers with EV Loads

-0.16--0.14

400 Frequency of occurances

450

Low Medium High TOU

Frequency of occurances

450

Change in Winder Load Factor for Transformers with EV Loads

Change in load factor

Change in load factor for transformers with EV load.

Table 3. Average increase in residential peak load Low

0.174 kW

Medium

1.10 kW

High

2.74 kW

Medium TOU

0.95 kW

To mitigate the potential for damage, we also assessed transformer upgrades. The medium and TOU adoption cases respectively required 50 and 45 upgrades across 688 studied transformers to remove failures that exceeded the transformer failure function. The high adoption case took 110 upgrades to mitigate all potential damage, representing 16% of studied transformers.

Under the high adoption scenario, we found a 2.74 kW, 19% increase in peak load compared to the base case. The medium adoption case saw a 7.6% increase in peak load over the base case. While the TOU adoption case required fewer transformer upgrades, there was little difference in residential load increases between it and the medium case. A 0.95 kW increase in the former and a 1.10 kW in the latter signals that TOU rates might not effectively reduce residential loads at higher adoption levels.

These peak load increases are observable, but produce only minor changes in load factor across all adoption cases. Load factor decreased more sharply in summer than winter across all cases, likely due to increased peak loads.

Conclusions With utilities currently focused on developing plans to accommodate increasing EV loads, evaluating the way transformers are currently being sized for new construction and routine maintenance could reduce costs and waste. Based on our findings, a 30% EV adoption rate could demand upgrades to 7.3% of transformers. At a 60% adoption rate, the number of transformers in need of upgrades increased to 16%.

Assuming that 30 million of the United States’ 50 million distribution transformers serve residential loads, 2.2 million

Table 4. Summary of findings.

Case

Average diversity factor

Average change in diversity factor

% of total transformer replacement

Average increase in residential load

Low

1.25

0.01

1.9%

0.174 kW

Medium

1.28

0.04

7.3%

1.10 kW

High

1.29

0.05

16%

2.74 kW

TOU

1.28

0.04

6.5%

0.95 kW

transformers may need to be replaced to support the load increases associated with a 30% EV adoption rate. In our high adoption scenario, with a 60% EV adoption rate, that number increased to 4.8 million.

With efforts ramping up in many cities to reduce natural gas use for heating and cooking in favor of electrified alternatives, millions of residential transformers will likely need to handle increasingly large loads even absent a contemporaneous increase in EV loads. Climate change-induced consumer demand changes and policy prescriptions could also affect peak demand in the future.

Given ongoing supply chain issues and future uncertainty, considering ways existing design and planning methods can be modified to handle increasing levels of EV adoption is essential.

EVs are an inevitable part of a decarbonized, renewables-rich society. The time to assess the likely impacts of an increasingly EV-saturated grid and plan for the safe, reliable integration of EV loads is now.

JODIE LUPTON, E.I.T., is a distribution studies engineer with POWER Engineers.

Her experience and expertise focuses on grid modernization projects like conservation voltage reduction, volt-var optimization, and system impact studies for distributed energy resource interconnections. In addition to her studies and automation work, Jodie has experience in underground and overhead distribution design. She holds a bachelor of science degree in electrical engineering from the University of West Florida.

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GRID RESILIENCE

A Consumers Energy worker performs inspections at a substation. As part of its funding from GRIP, the utility will train company apprentices with line worker crews that will be comprised of at least 33% apprentice-level employees to provide training on a variety of grid technologies.

Photo courtesy of Consumers Energy.

Getting a GRIP on Grid Upgrades With funding from the infrastructure law, the Grid Resilience and Innovation Partnership (GRIP) program is backing power grid projects with billions.

By RYAN BAKER, Associate Editor

T

he power grid of the future is getting a long-awaited boost.

The grid enhancements that have shown a lot of promise, but which have so far been slow to roll out in the U.S. due to a lack of a federal energy policy or even much government backing since the days of the American Recovery and Reinvestment Act of 2009, will receive some federal financial backing in a project that will lend a hand to hundreds of projects.

The funding, part of the Bipartisan Infrastructure Law, is intended to help electric utilities and grid operators install upgrades with potential to fight climate change and extreme weather, while helping deliver reliable and often renewable energy.

The Grid Deployment Office, established in August 2022 to maintain and invest in critical transmission, distribution and generation of power, is allocating $10.5 billion toward the Grid Resilience and Innovation Partnerships (GRIP) projects.

“These programs will accelerate the deployment of transformative projects that will help to ensure the reliability of the power sector’s infrastructure, so all American communities have access to affordable, reliable, clean electricity anytime, anywhere,” according to the Department of Energy website.

There are three different grant types that each project falls under. The first are the Grid Resilience Utility and Industry Grants. These receive $2.5 billion over the course of the rollout, amounting to about $600 million per year through 2026.

Grants in this category are meant to bolster the electric grid and minimize negative impacts due to extreme weather and natural disasters. Grid operators, electricity storage operators, electricity generators, transmission owners or operators, distribution providers and fuel suppliers may apply for these grants.

The second category, Smart Grid Grants, accounts for about

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GRID RESILIENCE $3 billion of the $10.5 billion. These will amount to $600 million per year through 2026.

According to the DOE, these grants will help enhance power system flexibility, efficiency and reliability while paying special attention to boosting the transmission system’s capacity, avoiding faults that could spark wildfires, incorporating renewable energy at the transmission and distribution levels, and making it easier to integrate an increasing number of electrified buildings, cars and other grid-edge devices. This grant program is open to institutions such as higher education, non-profits, as well as state, local and Tribal governments.

The largest grant program, which accounts for nearly half of the allocation at $5 billion, is the Grid Innovation Program. This will provide financial assistance to local entities that work with power sector owners and operators to help come up with implementation plans for transmission upgrades, energy storage and distribution infrastructure.

A line worker in a bucket truck drills into a power distribution pole as part of a power outage response.

Michigan’s Consumers Energy will receive project funding to build out much-needed infrastructure in some of the state’s underserved communities. Photo courtesy of Consumers Energy.

Office, explained this year’s funded projects in a webinar.

Robinson said many utilities wanted to work on projects havThe DOE’s initial payments for these programs kicked off ing to do with wildfire resilience (13 projects), microgrids (11 October 18, with the agency announcing $3.46 billion to help projects) and renewable integration (17 projects). fund 58 total grid projects across all but six states in the US. Additionally, all projects have Justice40 Initiative commitThe utilities involved put up roughly half of the total project ments, which is a requirement established by an executive order amount. The DOE is limiting its funding to the amount that that mandating that at least 40% of the benefits of certain federal given entity spent in the last three years on the specific efforts investments flow towards disadvantaged communities. In addithat they are asking help for. Additionally, there is a 100% cost tion, 84% of projects include a labor union partnership and make match, with an exception for small utilities that sell no more use of some unionized labor at some phase of the construction. than 4 million MWh of electricity per year. Those small utilities Colin Meehan, a GRIP program project manager, told the must match a third of the grant they received. webinar audience that project funding came after studies of Maria Robinson, director of the DOE’s Grid Deployment analytics on project effectiveness. Furthermore, Meehan discussed what the next round of applicants should be paying attention to for the second launch of project selection.

“Our intent is to address several different ways that we think we can simplify and expand access to the application process,” said Meehan.

There will be a focus on lowering barriers to entry for the future. The DOE plans to do outreach with project partners to help them meet eligibility and apply.

The agency seeks to make people available to answer questions from applicants, thereby making the application process more efficient and less of a time commitment for project partners. Doing so will include shorter page limits and better feedback. Finally, there will be more overall guidance on the application process such as providing more instructional webinars, technical criteria being simplified, additional guidance identifying priority areas of A worker installs poletop gear to a distribution line. National Grid’s Future Grid Plan, backed by investment, and requesting interviews for some DOE funding, will invest in network infrastructure, new transformers, power lines and substations, larger projects to help with selection. including line monitoring systems and communications systems. Photo courtesy of National Grid.

How to Get a GRIP

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GRID RESILIENCE a pilot project. According to the utility, this more granular data feedback from its distribution grid will enable it to use more distributed energy resources.

Some examples of projects under each grant for the first round of funding are:

Grid Resilience Utility and Industry Projects

Central Maine Power line workers have attached a recloser device to a pole top in the Portland, Maine area. CMP won a smart grid grant from the DOE to install advanced grid restoration and sequential reclosing technologies in its service territory. Photo by Central Maine Power.

Projects Across the US The projects themselves run the gamut of geography and technology but are united in their stated aim of delivering more reliable power from a more resilient grid. In hurricane-prone Florida, GRIP funding helped the Florida Municipal Power Agency and Fort Pierce Utilities Authority shore up local storm resilience by upping capacity and upgrading a pair of critical substations at risk of storm surges.

In wildfire-struck Northern California, GRIP money will enable “Project Leapfrog” to get off the ground. Liberty Utilities (CalPeco Electric) will use an array of smart devices, including smart meter reading, network infrastructure and smart meters to achieve better outage management, improved safety and emissions reductions. According to the DOE, Liberty is challenged by the mountainous terrain of its service territory, but this project will develop a smart utility network to deliver better customer service.

In rural North Carolina, Surry-Yadkin Electric Membership Corporation will use a Smart Grid Grant to decrease the impacts of outages by 15% by upgrading some of its outmoded and aging electric infrastructure. The upgraded system will use an automated restoration system with system monitoring capabilities that can identify the cause of outages and minimize their impacts.

In Alleghany and Beaver counties in Pennsylvania, Duquesne Light Co. will deploy grid enhancing technologies to boost their capacity and unlock more clean energy generation. This project will deploy a dynamic line rating application that DLC tested in

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Project: New Orleans Line Hardening and Battery Microgrid Applicant Utility: Entergy New Orleans Federal Share: $54,828,178 Utility Share: $54,828,178 Goals: Hardening transmission for 97 structures and distribution for 381 structures. Deployment of a battery backup project to lower energy costs for disadvantaged communities in New Orleans. Establish a workforce development program to teach students about clean energy jobs.

Project: Climate Adaptation Resilience Program Applicant Utility: Hawaiian Electric Company Federal Share: $95,313,716 Utility Share: $95,313,718 Goals: The goal of Hawaiian Electric’s (HE) project is to reduce damage from extreme weather events like hurricanes and wildfires by hardening the electric transmission and distribution system throughout HE’s whole service area. Hardening crucial transmission lines, consumer circuits, control centers, and important poles are some of the solutions. Furthermore, the project will undertake work related to lateral undergrounding and attempts to avoid and mitigate wildfires, including the removal of hazardous trees and the improvement of situational awareness.

Smart Grid Projects Project: Accelerating Building Thermal Electrification While Managing System Impacts Applicant Utility: Generac Grid Services Federal Share: $49,835,370 Utility Share: $52,939,597 Goals: “The goal of this initiative is to demonstrate that efficient building electrification can be achieved while minimizing system overloads, reliability issues, and the need for infrastructure upgrades,” according to the DOE’s fact sheet.

Project: Resiliency Enhancement for Fire mitigation and Operational Risk Management Applicant Utility: PacifiCorp Federal Share: $49,951,103 Utility Share: $53,186,717 Goals: To develop a comprehensive ecosystem of interoperable

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GRID RESILIENCE technologies to greatly improve situational awareness to prevent or lessen wildfires and to increase the flexibility, dependability, and resilience of the grid.

Grid Innovation Program Projects Project: Railbelt Innovative Resiliency Project Applicant Utility: Alaska Energy Authority Federal Share: $206,500,00 Utility Share: $206,500,000 Goals: “The primary objective of the RIR Project is to address various challenges facing the electrical grid in the three Railbelt regions of Alaska. These challenges include decreasing system frequency regulation, slowing frequency response to disturbances, and increasing Workers with EPB Chattanooga install hardware at a microgrid project linking various municipal services natural frequency power oscillations,” together. The Tennessee city-owned utility will use GRIP funding to add more energy storage capacity.

Photo by EPB Chattanooga. according to the DOE’s fact sheet.

Project: Joint Targeted Interconnection Queue Transmission Study Process and Portfolio Applicant Utility: Minnesota Department of Commerce Federal Share: $464 million Utility Share: $1.3 billion Goals: The project will coordinate five transmission projects spread across seven Midwest states in terms of planning, designing, and building. Many of these obstacles are removed by the JTIQ Portfolio project, which also offers a host of interregional advantages like additional renewable generating, scalable transmission options, reduced energy costs, improved community involvement, and workforce development.

In the near future, there will be more announcements on the current allocation for the first round of funded projects, and that will be consistent through the Fiscal Year 2026. The Biden Administration announced November 14 an additional $3.9 billion to be released for the second round of funding.

This funding, according to the DOE, will focus on projects that develop comprehensive solutions that connect grid communications systems and operations to increase resilience and reduce power outages and threats; deploy cutting-edge technologies like distributed energy resources and battery systems to provide essential grid services; and improve electric transmission by In a past project, EPB Chattanooga workers install hardware at a city microgrid project. The utility also plans to boost power system resilience by replacing increasing funding and advancing interconnection processes more than 1300 power poles to help the grid stand up to severe weather. Photo

by EPB Chattanooga. for faster build-out of energy projects.

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PUBLIC POWER

The fountain in front of the Nebraska State Capitol. This is one of the state government facilities that makes up Lincoln Electric System’s microgrid.

Photo by Lincoln Electric System.

Microgrid Fuels Nebraska Capital in Public Power Tradition Nebraska is the only 100% public power state in the U.S., and Lincoln Electric System pushes that tradition into 2024 with its microgrid project.

By SCOTT BENSON and KELLEY PORTER, Lincoln Electric System

S

ome ideas make too much sense to ignore. That was the feeling in 2016 when Lincoln Electric System first investigated the concept of constructing a 29 MW communityowned, microgrid to bolster local disaster-recovery efforts in the downtown Lincoln, Nebraska area.

The idea was born from two basic factors. First, project planners realized early on that there was an inherent synergy on the grid in the form of an anchor generation source — the J Street generation plant — owned by the utility and supplemental customer-owned generation, all situated near numerous vital city, county and state facilities. Second, this was an opportunity to enhance a community-centric mindset fostered by LES’ relationship with the county, city and its customer-owners.

Lincoln is the capital of Nebraska, which is the only 100% public power state in the country. Every electric utility in the Cornhusker state is customer owned and run by Nebraskans rather than being owned by big, out-of-state companies.

This is a tradition that goes back to the early 20th century, when Nebraska Sen. George William Norris pushed to pass the Rural Electrification Act, which was eventually signed by President Franklin D. Roosevelt in 1936.

Lincoln, also called the Star City and part of the Silicon Prairie, is a picture of the Midwest. A growing mid-sized urban area in the middle of the country, the city manages to maintain a small town, community feeling despite the nearly 300,000 residents who call it home.

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PUBLIC POWER

The Makings of a Microgrid In short, the pieces were already in place. The utility realized it had what you could see as an almost readymade microgrid already, but until then nobody had quite looked at it that way until a series of conversations in 2016 sent things into motion.

LES planners believe many utilities around the country may be in the same situation, already owning and operating resources that could further enhance system resiliency.

The U.S. Department of Energy agrees, and featured the project in a publication to use as an example of how other communities might use their own similarly situated power assets.

From there, it was just a question of how to link these together in a way that made the local grid — and Downtown Lincoln contains several key facilities, businesses and residences that are a part of LES’ microgrid.

Photo by Lincoln Electric System. community it serves — stronger.

Lincoln’s electricity demands are met in part by two warning. It only takes one such incident to put a city and its power plants outside the city, and it is located near ma- utility in front of national news attention.

The capitol area is home to many institutions critical to the jor transmission lines. Major outages are a rarity for the utility, but tornadoes and other severe weather have city and the region, including the Nebraska State Capitol, the the potential to do a lot of damage without much headquarters for the Lincoln Police Department and Lancaster

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PUBLIC POWER The area encompasses several advantages for remaining energized in the event of an emergency. First among these is a 30-MW oil- or natural gas-fired combustion turbine that anchors the project. Customer-owned resources around the microgrid, including five solar photovoltaic installations totaling just over 300 kilowatts, could supplement operations. Nearby thermal energy storage — the electrical equivalent of nearly 500 kW for 6 hours — could account for roughly 3,000 kWh of load shed.

The thermal energy storage stems from several District Energy plants that already provide low-cost, reliable and efficient heating and cooling to The Pinnacle Bank Arena, home of the University of Nebraska’s men’s and women’s basketball teams, is located enhance economic development in the Haymarket District. It is another of the buildings linked up to LES’ microgrid. Photo by Lincoln Electric System. of the community in Lincoln. This County Sheriff, Nebraska State Office Building, the Federal thermal energy system allows one plant to build ice overnight which is used to supplement traditional cooling systems in the Building and Pinnacle Bank Arena. afternoon of the next day.

And, though likely unable to connect in parallel with the miBringing Pieces Together Nebraska sees weather extremes from all four seasons. A com- crogrid’s anchor generator, multiple customer-owned diesel backmunity microgrid could be a major benefit should the need up generators could still be used to defer load during peak times, for local disaster recovery arise. Whether the area experiences further adding to the area’s potential as a community microgrid. an extreme ice storm causing major damage to utility infraDespite the system’s synergy with a microgrid in that area, structure, or a tornado ripping through the area, the ability to along with the long list of potential benefits it presented for disconnect the microgrid and operate it autonomously from the LES’ customer-owners, LES’ community microgrid concept was rest of the electric system is invaluable. Not only can this help initially judged impractical. strengthen grid resilience, providing service to a finite area of While the pieces were there and the microgrid’s proposed critical infrastructure and facilities can also help to mitigate primary generator was capable of black start and islanded operation in an isochronous mode, manually switching the the impacts of a crisis for the entire community. distribution system to isolate and serve just the critical facilities within the area would be too cumbersome.

Alternatively, LES staff also found it would be cost prohibitive to provide the level of automation required to speed up the switching process. With that, the project was put aside, but only for a moment.

Implementation

A snowy afternoon in Lincoln, Nebraska. Winters can be fierce in the Great Plains, with extreme storms capable of sending distribution lines toppling and inflicting power outages that last for days. Photo 256207960 © | Dreamstime.com

The ability to independently operate critical facilities as an island when the grid is down simply held too much value to sit idle for long though. Two years later, in 2018, the microgrid concept was revived with one simple, yet crucial, change in methodology.

Instead of attempting to isolate and restrict service to only critical facilities in the downtown area, the microgrid would serve nearly all the load within a finite perimeter.

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PUBLIC POWER While this change in approach may limit the total load potential for critical facilities, the simplicity of the design was more than able to address the switching issues that previously rendered the project unworkable.

The area typically serves the following loads that could potentially be critical during disaster recovery efforts: • City, county, state and federal government facilities, including the city police department and county sheriff.

• The Pinnacle Bank Arena — 15,500-seat indoor arena in the West Haymarket District of Lincoln — which could potentially serve as an emergency staging area The microgrid concept was tested when LES isolated the anchor generator from the network and confirmed its operation with two 5 MW load banks. Photo by Lincoln Electric System. during catastrophic events.

• District Energy heating and cooling plants that serve most of the facilities above.

Although not as critical to government function, the area also includes valuable community support infrastructure, including a radio tower, which could be operated locally to support emergency communications, a small grocery store, a small pharmacy and multiple gas stations.

LES used two 5-MW load banks to perform testing on the microgrid’s anchor generator in the fall of 2020, confirming its ability to operate independently from the rest of the electric system while picking up large portions of load. With that confirmation, LES’ community microgrid was declared in service.

After completing load bank testing to support the microgrid, LES staff opted to begin testing all of the utility’s local generating stations to ensure A diagram of the resources and critical loads that make up LES’ community microgrid. Photo by Lincoln Electric System. their operations during system recovery efforts.

When not supporting the microgrid, LES anticipates the battery being used to provide additional system benefits, including Onboarding Energy Storage load-related energy arbitrage and ancillary services.

To further support the microgrid, LES issued an open request for Bringing a battery storage project onboard would proposals for a battery storage system to be located in the area. strengthen the LES microgrid while supporting transmission LES had been looking to do a small energy storage project and and distribution system reliability by deferring load during siting it within the microgrid provided another benefit stream peak periods. to help justify a pilot. The storage system would be contracted under a power purchase agreement.

SCOTT BENSON (sbenson@les.com) is manager, Resource & Transmission Planning, In June 2023, LES executed a contract with Wattmore, a at Lincoln Electric System.

Colorado-based clean technology and renewable project development company. The 3-MW, 4-hour battery they proposed KELLEY PORTER (kporter@les.com) is manager, Customer & Corporate Communicais scheduled to be installed in downtown Lincoln by 2025. tions, at Lincoln Electric System.

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SOLUTIONS CENTER

BY HENRY NIVERI, ABB DISTRIBUTION SOLUTIONS

Virtual Substation Protection, Control and Automation Substations make the grid work, and new technologies are helping them meet the growing demands on the capabilities.

T

he demands placed on the modern substation are vast and growing. To adapt to the requirements of a rapidly changing power grid environment, medium-voltage (MV) substation operators are tasked with reducing costs, simplifying equipment maintenance and updates, accommodating increasing numbers of distributed energy resources (DERs) and improving renewable penetration levels into the grid, all while responding to constant and high demand.

While certainly no easy feat, the good news is that virtualization can help solve many of these challenges.

Substations are essentially the motherboard of the power industry, responsible for transforming voltage from high to low, or the reverse, to enable electricity to be transmitted safely and

effectively to industrial and residential customers. It is therefore easy to see why substations are such a critical component of the energy transition.

Also, over the last five years, we have seen a radical evolution in the electricity grid as it increases its share of distributed energy resources (DERs), such as solar and wind energy, as part of the total energy generation mix. But while this transition may be net zero critical, the increase in DERs brings with it new challenges for substation operations ranging from voltage fluctuation and reverse power flow to overheating of components. This reinforces the need for investment in intelligence and resilience across the grid, especially in distribution networks where voltage stability is imperative. At the same time, distribution system operators (DSOs) remain under constant pressure to reduce capital expenditure and operating expenses generally.

Enter the growing case for virtualization as a way for DSOs to address these challenges, enabling the flexible and rapid deployment and evolution of substation applications from different vendors onto the same hardware by, essentially, creating virtual replicas.

Virtues of Virtualization Virtualization – the concept of decoupling software from the underlying hardware – can help DSOs work more effectively and efficiently in many ways.

To understand how let’s consider the typical modern substation. In addition to the standard primary equipment, such as circuit breakers, busbars and switchgear, most substations now contain intelligent secondary equipment designed to allow automation and control. This can range from communication components and operator terminals through to SCADA (supervisory control and data acquisition) systems, running specific applications and working in isolation.

The result can be an operational minefield for the busy DSO, tasked with deploying and maintaining an ever-growing list of varied components. In some cases, because individual devices are usually vendor-specific it can mean modifications involve a

R “ I L

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SOLUTIONS CENTER specialist skill set to be outsourced at a cost. This requirement will continue to grow as more functionalities are added.

Through virtualization, where applications run in a ‘virtual’ environment abstracted from the underlying platform and isolated from other applications running on that platform, it is possible to deploy, execute, exchange and migrate almost independently of the platform. In most scenarios, this will involve installing one common hardware server at a substation, managed by a central operating system (OS) otherwise known as a hypervisor. From thereon in, different virtual machines (VMs) can be created for everything from protection and control through to automation and energy reporting, enabling DSOs to run what appear to be multiple machines, with multiple operating systems, on a single computer.

Fundamentally, this approach allows for a much smaller hardware footprint and reduces the need for vendor-specific skill sets and the amount of knowledge required to maintain the substation. It also enables most key activities to be performed remotely, in real-time, anywhere in the world, removing the need for a physical presence on site. As a result, virtualization can help to achieve high availability and resiliency at a reasonable cost.

What is equally appealing about a virtual approach is the ability to aggregate all the data from various applications and systems on separate VMs in the substation into one single user interface.

For the busy DSO, the wide-reaching visibility afforded by this approach can empower better decision making in power quality, energy optimization, fault detection, asset management and more.

Cloudy Comparisons Crucially though, despite many similarities it is important to note that the virtualization of substation technology is very different to cloud computing and brings with it a number of challenges.

While the cloud, for example, has ample and scalable computing, storage and networking resources, the resources available in substation devices are more modest. Unlike the cloud, the applications running on substation devices are of mixed criticality (safety-critical and non-safety-critical) and some applications may require specific hardware configurations – for example, support for the Precision Time Protocol in a network card. Moreover, many substation applications have special timing and high availability requirements that must be met during operation.

To ensure a seamless migration onto VMs, it is advisable to work with a specialist technology partner who will ensure a planned and methodical approach - reviewing existing assets, choosing the most suitable provider, preparing your teams.

Otherwise, the risk is that configuration mistakes could compromise the real-time guarantees for the applications running in the VMs or containers.

Into Practice

Virtualization is a critical component of grid resilience and must play an important role in enabling DSOs to reduce complexity and work smarter, not harder.

When was the last time you tested your aged insulators?

The US grid has millions of old insulators which are often close to or past their end of life.

Testing of such insulators is an extremely valuable approach to assess reliability and risk management.

Sediver's West Memphis laboratory regularly performs such work, providing US utilities with clear factual diagnostics.

• State-of-the-art testing equipment • Sediver’s unique expertise in the evaluation of the results Read our INMR publication on “Evaluation of Field Returned Insulators from US Grid Through Laboratory Testing”

• Full support from Sediver’s extensive R&D Team • Experience with complex case studies for refurbishment/ upgrades of AC and DC lines

Your trusted insulator partner in the USA for 55+ years Need more info? info.usa@sediver.com - www.sediver.com

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12/6/23 8:28 AM 12/15/2023 11:13:34 AM

SOLUTIONS CENTER In 2018 ABB introduced its SSC600 device, an innovative approach to protection and control in distribution networks in which all the protection and control functionality is centralized into one single device. Building on the success of the SSC600, ABB has now introduced SSC600 SW - the virtualized version of the SSC600 device.

An example of the benefits with centralized protection can be found in Finland, where our SSC600 has helped secure reliability

QUALITY FORGED DAILY.

and ensure asset optimization for Finnish utility, Parikkalan Valo.

As part of a major refurbishment of its Punkasalmi substation in Finland, Parikkalan Valo sought a solution to ensure safe and reliable power supply. As part of the remodeling of the substation, originally constructed in 1986, the utility wanted to be able to manage its electrical network and assets more efficiently; ensuring flexibility to meet future needs as requirements change.

Parikkalan Valo chose ABB’s centralized protection with SSC600, whereby all protection and control functions of the substation are centrally managed, operated and engineered in the same device.

This means it is possible to update the entire protection and control functionality in one go, and there is no need to update an installed base consisting of protection devices of different types and ages.

Today, these benefits, and more, are also possible with virtualized protection and control.

A Virtual Reality As we enter a new pace of digitalization, substation technology has followed. Today, most modern substations feature an increasing number of devices and automation components from multiple vendors – meaning more and more intelligent electronic devices are required. Maintaining and updating a myriad of proprietary devices can be expensive, timely and complex.

Undoubtedly, the radically evolving power grid will continue to add new pressure on DSOs. The emergence of virtualization as a route to better efficiencies, intelligence and resilience is inevitable, and now is the time to make the virtualized protection and control opportunity a firm reality for the future.

When extreme weather strikes, rely on Hughes Brothers for high-strength steel framing and urgent power restoration and solutions.

DOWNLOAD PDF FOR MORE INFO HughesBros.com

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HENRY NIVERI (henry.x.niveri@fi.abb.com) is product manager at ABB’s Distribution Solutions division. Currently based in Vaasa, Ostrobothnia, Finland, Niveri specializes in centralized protection for digital offerings, engineering software and design architecture. He received his master’s degree in computer science from Helsinki University of Technology in Espoo, Finland.

12/11/23 12:01 PM

12/15/2023 11:14:38 AM

FOCUS: A LINEWORKER’S VIEW

BY AMY FISCHBACH, FIELD EDITOR

On the Job We are currently installing 700 ft of 25 kV three-phase underground to a 1000 kVA padmount transformer for a business in our town. We are also looking to do a conversion job from 12.5 kV to 25 kV in the northern part of Phillipi.

Safety Lesson The importance of job-site safety that sticks with me is when Hurricane Fran hit in 1996. Power was out, and lines were down for miles. I was working for Pike Electric on the CP&L system.

There was a single dusk-to-dawn light burning by itself with no electric for miles around. My foreman told all of us to wear rubber gloves on everything we touched because people were using generators, and they were backfeeding the downed lines.

That really opened my eyes up on how easily you could get hurt or killed.

Memorable Storm

Meet Wes Jones Philippi Municipal Electric Wes Jones has worked in the construction and maintenance of power lines for the past 30 years.

• Born in Phillippi, West Virginia, to Bill and Anne Jones.

Has one brother, Eddie.

• Has two daughters, Kaitlin, 23, and Kory, 19.

• Enjoys spending time with his family, working on his property, doing new projects around the house and going on annual family vacations.

• Got inspired by Ronnie Ball and Jerry Purdham to work in the line trade. None of his relatives have worked for the power industry—only friends.

Early Years In 1992, I started working for Davis H. Elliot as a groundman.

I mostly dug hand holes for poles and anchors. I also bonded the pole ground to the neutral off of hooks.

Day in the Life Fast forward 31 years, and I am the superintendent for Philippi Municipal Electric. My main responsibilities are to keep the lights on in our town from the delivery of our feed to the meter base. We operate with three different distribution voltages: 25 kV, 12.5 kV, and 4 kV. My typical workday starts at 5 a.m., dealing with streetlights, substation voltage checks, services, random outages, vehicle maintenance and right-of-way issues.

In 2012, Hurricane Sandy came up the Allegheny Mountains and brought winds never seen before by our small town. We lost our feed from First Energy for six days. Our system suffered many broken poles and downed power lines. I called in mutual aid from a Kentucky municipal, and we worked together for five days. I stayed in my office without power. Mutual aid left before First Energy had the 138 kV feed back on. The storm started with rain and wind, followed by hot and muggy days.

Challenges and Rewards It’s just me and my coworker who serve 2,000 customers, which can be a challenge. The reward is that you can go home knowing that you served your customers well and that nobody is without power, and most importantly, everyone is safe.

Tools and Technology I couldn’t perform my job without my Klein pocket knife, waypoint spotlight and my Milwaukee crimper. Battery-powered tools will be the future in line work. Old squeeze tools have ruined many lineworkers’ shoulders, including mine. Remote cutters for URD lines will increase the safety of the lineworkers and the public.

Life in the Line Trade With every job comes the good and the bad, but I have enjoyed many of years of working with great people in the lineworker industry. Some have come and gone, and I miss them dearly.

You get a great deal of pride knowing that you are a part of a group of people who serve America. I think about past experiences and focus on new ones. Every day is different. The most important thing is for your pole buddy and yourself to go home safely every day.

Future Plans The future is unknown for me. I will be eligible to retire in 45 months. Whatever happens down the road, I’m sure I will still point at some pole or line from Florida to Michigan and say, “I helped build that! “ January 2024 | T&D World 45

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SOCIAL MEDIA HUB

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www.tdworld.com Steve Sullivan, President of Connecticut Electric Operations, Eversource Energy We’ve hired some really talented folks out of this program, and our program with Capital Community College, who are thriving here at Eversource Energy, and that could be you!

Western Farmers Electric Cooperative (WFEC) seeks to identify possible contractors for future Emergency Electric Power Restoration and Debris Removal Services in 2024. Work could be performed across the State of Oklahoma, as well in portions of Texas and Kansas. More information about our service territory can be found at www.wfec.com. Please submit your contact information via email to bids@wfec.com or send a letter to Procurement Services, 3000 S. Telephone Road, Moore, OK 73160.

Small Businesses, Minority-Owned Businesses, Woman-Owned Businesses, and Labor Surplus Area Firms are especially encouraged to submit their information. WFEC accepts new contractors throughout the year; however, to establish an agreement for 2024, please submit your information

by December 19, 2023.

Aidan Tuohy Director, Transmission Operations and Planning at EPRIDirector, Transmission Operations and Planning at EPRI In the last few weeks, I’ve had the pleasure of making two trips to Latin America to discuss EPRI R&D in the transmission operations space, and learn from our members about the challenges and opportunities in the region as power systems transition to a cleaner resource mix worldwide.

Tennessee Valley Authority We have restored all highvoltage connections to local power companies damaged by the severe weather that swept across Middle Tennessee and Western Kentucky over the weekend. Our crews continue to make repairs to our transmission system to restore redundancy. Local power companies are working around the clock to repair storm damage that remains on their local system. We will continue to support and assist communities in need. #TNWX #KYWX.

NY Power Authority @ NYPAenergy Our #EnvironmentalJustice Adult Energy Literacy Programs, like weatherization workshops & community-based/controlled indoor food production systems, help our neighbors to make positive energy choices for their families & community. #EJFridays.

NV Energy @NVEnergy NV Energy participated in Yerington’s 7th annual Parade of Lights hosted by the @YccYerington.

This is the 3rd year #NVEnergy has entered the parade—our team loves supporting local events and already looks forward to next year’s #ParadeOfLights!

⚡

⭐

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Advertiser

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Website

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Account Director Bailey Rice Phone: 630-310-2598 Email: brice@endeavorb2b.com Sales Director, Energy Jeff Moriarty Phone: 518-339-4511 Email: jmoriarty@endeavorb2b.com Sales Support Manager Debbie Brady Email: dabrady@endeavorb2b.com International Linemen’s Rodeo, T&D World Buyers Guide and Events Sam Posa Phone: 913-515-6604 Email: sposa@endeavorb2b.com

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Utility Analytics Institute Memberships James Wingate Membership Development Manager Phone: 404-226-3756 Email: jwingate@endeavorb2b.com Utility Analytics Institute, Smart Utility Summit and Smart Water Summit

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January 2024 | T&D World

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12/18/2023 9:36:11 AM

STRAIGHT TALK

BY DAVID WALLS AND JEFF PLEWES, CRA’s ENERGY PRACTICE

Is There a Formula for Successful GRIP Applications?

T

he Department of Energy has issued its Funding Opportunity Announcement for the second round of GRIP (Grid Resilience and Innovation Partnership Program) funding opportunities under the Infrastructure Investment and Jobs Act (IIJA) (also referred to as the Bipartisan Infrastructure Law (BIL)). Funding is David Walls expected to be $3.9 billion.

Similar to round one, concept papers (which are due on Jan. 12, 2024) are being solicited for each of the GRIP funding topic areas including (1) Grid Resilience Utility and Industry Grants ($918 million), (2) Smart Grid Grants ($1.08 billion) and (3) Grid Innovation Grants Jeff Plewes ($1.82 billion). Full applications will be due on April 17th for topic areas (1) and (3), with topic area (2) due May 22nd.

Utilities and other organizations planning to submit applications for this next round of funding are already well underway in writing their concept papers, sharpening their plans based on experience from previous submittals, and using clues that DOE has provided regarding what is desired in this new round. In the first round of full applications, the odds of winning were about 13-26%, depending on the topic area. Based on what we have learned in round one, is it possible to improve your chances of success by focusing on key DOE objectives? We can expect this round to be even more competitive than the previous round, so companies should be looking at how they can improve their concept papers and advance the key areas of priority for investment.

Key goals for the DOE include energy justice, the integration of renewable energy, the application of data-enabled technology and investments in grids that support resilience. It aims to do this through prevention, protection and recovery, and investments with benefits that flow directly to disadvantaged communities. Investments should also provide the ability to catalyze and leverage private investment, so there is a multiplier effect related to these projects that continues well into the future.

Priority investment areas for this round include the following: • Sharing best practices across multiple utility service territories • Projects that boost innovation across all stages of project development and execution • Facilitating clean energy deployment, generation diversity and benefits • Enabling DER integration through the application of automation, digitization, and advanced technology • Decreasing interconnection queues, to facilitate the construction of clean energy

• Increasing system resilience related to climate change-induced natural disasters • Increasing regional and interregional electricity transfer capacity Through the first round, there was significant learning regarding the requirements for Community Benefits Plans and we can expect there to be more focus on this aspect of the applications in the second round. By prioritizing energy justice there is an objective to dramatically alter the relationship between energy providers and their communities. This should be accomplished by collaborating closely with stakeholders in the community, starting with the planning process and focusing on the needs of disadvantaged communities and Tribes. The desire is to move away from traditional planning approaches and solutions and engage the community to identify new ways to reduce power outages, reduce restoration times and environmental impacts and bring high quality jobs to the communities. Examples of how this could be accomplished may include both utility and behind-the-meter microgrids, that are linked to critical loads in communities. Another example could be projects that have agreements with local unions and hiring people locally. For the Grid Resilience Utility and Industry Grants (topic area 1), applicants must address at least three of the key areas, but addressing more than three is likely to be beneficial. These areas range from utility pole management and hardening of power lines to fire-resistant technologies and fire prevention systems, and advanced modeling technologies. While the Concept Paper form has been streamlined to facilitate the application process, we can expect there to be more rigor and focus on advancing the goals that DOE has identified. Projects that have more diverse teams, which apply new and innovative technologies and address rural or hard to reach communities are likely to achieve more success. Applicants should consider providing a high-level roadmap that describes how their project will facilitate learning, and additional future investments.

An interesting way for a project to potentially stand out is to partner with other utilities and describe how learning and advancements will be shared across companies. This might include multiple investor-owned utilities operating in regions, or investor-owned utilities working together with local rural electric coops and municipal utilities. So, while there may not be a specific formula for success, there are many things that applicants should consider that will improve their chances of success. Through its investments, the DOE is essentially de-risking new projects, suggesting this is an opportunity for creative thinking and exploring new approaches to addressing energy challenges.

By taking lessons learned from round one, utilities can position themselves for success over the coming month.

DAVID WALLS is vice president, and JEFF PLEWES is principal in CRA’s Energy Practice.

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