Megaproject

Power Grid International

Virtual Power Plant Adoption Is Growing In The Us, But Not Nearly Fast EnoughWith peak demand growing, utility capital investments rising, and a growing number and severity of extreme weather events, the U.S. electrical grid needs all the help it can get. If the DOE has anything to say about it, a good portion of that help should come in the form of virtual power plants (VPPs). A new report from the U.S. Department of Energy (DOE), Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update, provides a fresh look at the DOE’s roadmap for the public and private sector to accelerate the commercialization of virtual power plant (VPP) technologies, given the constantly evolving landscape that is the U.S. energy market. DOE published the original Pathways to Commercial Liftoff: Virtual Power Plants report in September 2023, since noting VPP adoption has grown, new VPP deployments have been launched, and new insights and analysis of VPP benefits have emerged. However, DOE maintains that VPP deployment needs to accelerate in the U.S. to reach a target of 80-160 GW of VPPs (10%-20% of peak load). To reach the target of 80-160 GW of VPPs by 2030, the pace of deployment will need to accelerate, DOE argues. The VPP scale has grown over the past year to 33 GW, but the U.S. will need to pick up the pace if it wants to hit that goal. Achieving “liftoff” will require progress on five imperatives, DOE argues: Since the original VPP Liftoff report was released in September 2023, DOE said the pressures on the U.S. Electric grid have intensified. Peak demand is expected to increase from approximately 800 GW in 2024 to approximately 900 GW in 2030 due to growth in energy-intensive data centers, domestic manufacturing, and the electrification of transport and heating. Additionally, utility capital investments for the transmission and distribution grid have grown by 10.8% and 14.6% respectively from 2022 to 2023. These capital investments are expected to continue growing to meet rising load growth and replace aging assets, which could drive up future electricity costs for ratepayers. Finally, the U.S. experienced a record 28 “billion-dollar” extreme weather events in 2023 that caused a cumulative $95 billion of damage and injury and were responsible for 75%-80% of U.S. power outages for households and businesses. DOE described “equitable benefits” as upfront incentives that stack across federal, state, city, and tribal programs, inclusive utility investments, and partnerships with community-based organizations. One example is San Diego Community Power’s Solar Battery Savings program, which uses upfront, stackable incentives to provide the opportunity for no-cost solar panels and batteries for underserved communities. In addition to the roughly 30 GW of VPP capacity already enrolled in the U.S., enrolling 30%-50% of the new dispatchable DER capacity that is projected to be added to the grid between now and 2030 could help achieve “liftoff” nationally, DOE argues. It may not be that complicated to increase enrollment: pre-enrolling customers in VPP programs with opt-outs, instead of the most commonly used method of opt-ins, could be a simple and powerful solution. Chris Rauscher, head of grid services and VPPs at Sunrun, is a fan of this method, and discussed its benefits in a previous interview with POWERGRID International. “Our opt-out rate is vanishingly small,” said Rauscher, who strongly favors this method. “Auto-enrollment works.” Sunrun runs CalReady, the biggest single-owner VPP in the United States, comprised of more than 16,000 home solar and battery energy storage systems. It’s the most robust aggregator enrolled in California’s Demand Side Grid Support program, administered by the California Energy Commission as part of the state’s Strategic Reliability Reserve to boost energy supplies during times of need like heat waves or wildfires. Enrolled customers are compensated for sharing their stored energy and Sunrun gets a cut for dispatching the batteries. Formerly known as Sunrun’s Peak Power Rewards program, the VPP supplied Pacific Gas & Electric Company (PG&E) with up to 32 megawatts (MW) during peak times in summer 2023 and averaged 48 MW during a heatwave last July, topping out over 50 MW. Because Sunrun is a third-party ownership (TPO) company, it can auto-enroll customers into virtual power plant programs rather than relying on them to opt in themselves. In lieu of a bunch of paperwork, Sunrun pushes communications to its customers via email and its app giving them the option to opt out. “I think the biggest thing is that customers don’t care about virtual power plants,” Rauscher said with a laugh. “There’s an old saying that they spend six minutes total each year worrying about their electricity. Customers just want hot showers and cold beer.” Rauscher contends customers want a fundamental value proposition from solar and batteries. Specifically, a lower bill from solar, access to backup power from their battery, and for the battery to be capable of time of use management. “And then if you give them additional money for virtual power plant services, then that’s really a compelling value proposition,” he adds. DOE notes that new efforts across the industry and designing standards for utility-aggregator interfaces, aggregator-DER interfaces, cybersecurity responsibilities, and other aspects of VPP operations. Without standards, however, DOE argues that many utilities are still “capturing near-term value now” with basic VPP configurations that require less than $1 million in upfront investment and can be deployed in less than six months. One example of standardization efforts DOE drew attention to is the development of a model grid services contract from the North American Energy Standards Board and device interoperability standards from the Mercury Consortium. Additionally, one example of a rapid, utility-led VPP deployment is National Grid’s ConnectedSolutions program, which launched in under four months and now has 250 MW of peak shaving capacity in Massachusetts and New York. While most utilities are free to implement some form of VPP without any policy or regulatory change, VPP deployment has so far been highest in areas where state regulators and policymakers have implemented VPP-supportive actions. This lines up with a recent report from National Grid Partners, which found that nearly three-quarters (72%) of surveyed utility leaders say innovation at their organization is primarily driven by regulation or compliance. Some regulators are aiming to motivate utility action to be “more in line with ratepayer interest” by establishing cost recovery pathways for VPP-related investments, improving system planning, supporting DER deployment and aggregation, and enhancing VPP operation and compensation models, DOE said. Policymakers are also using legislation to accelerate deployment by attempting to establish a direction and remove ambiguity about VPP goals and other program parameters for utility regulators and other stakeholders. DOE pointed to two examples of VPP-supportive regulation and legislation: the New York Public Service Commission’s Value of Distributed Energy Resources (VDER) mechanism to compensate DERs based on their system value; and a bill signed by Colorado’s legislature in May 2024 that requires the state’s largest investor-owned utility (IOU), Xcel Energy, to submit a VPP plan to the Colorado Public Utility Commission Both CAISO and ISO-NE have “fully complied” with the requirements of FERC Order 2222 (which enables DERs to participate alongside traditional resources in the regional organized wholesale markets through aggregations), which DOE says “theoretically” unlocks wholesale market participation from a wide range of DERs in those regions. However, challenges and obstacles still remain when it comes to integrating VPPs into wholesale markets, especially in data access, metering requirements, and participation models. CAISO, NYISO, PJM, and SPP all allow participants that meet certain criteria to use calculated telemetry readings based on sampling rather than requiring direct telemetry for each DER to participate, which allows a greater number of DERs to participate given related telemetry requirements and reduced participation costs. Read the full report here. Originally published in Renewable Energy World.

powerplant

Jan 14, 2025

Power Grid International

How Energy Storage Operators Can Harness Recent Advancements In Battery Aging Simulation SoftwareContributed by Marie Sayegh, Technical Solution Engineer at TWAICE Battery technology stands at the forefront of the energy revolution. Battery energy storage systems (BESS) are crucial for the clean energy transition. They provide additional stability and flexibility and prepare grids to operate fully on renewable energy. Yet, with increasing deployment, the challenges of BESS become more apparent. BESS are highly complex systems. They involve networks of battery cells, inverters, battery management systems, cables, and other hardware. While a recent study done by EPRI, PNNL, and TWAICE showed that BESS failure incident rates have dropped by 97% since 2018, availability issues and underperforming components still plague many storage operators. In this context, software plays a crucial role in right-size, managing, and maximizing storage systems and their lifetime. By simulating battery behavior under various conditions, simulation models allow operators to predict battery performance and lifetime and optimize system designs. For utilities and energy operators looking to deploy BESS, right-sized deployments are critical to ensure they are getting the most from their investment. Simulation models play a critical role throughout the lifecycle of a BESS project. They help to align stakeholders on realistic performance expectations during planning, and help operators determine how batteries will perform in various usage scenarios, like peak shaving. One key subset of modeling software is battery aging models. These models simulate different degradation processes occurring within battery cells over time. Grid-scale BESS may be asked to perform a variety of functions, from peak shaving and backup power to wholesale market participation and supporting solar. Battery aging models offer valuable insights into how batteries degrade under these different operating conditions. For asset managers, it is paramount that the battery cells hold up to all kinds of fluctuations. For residential storage applications, for example, variations in temperature are a major concern. Simulation models can provide the necessary insights. Similar to the residential storage temperature challenge, Swedish mining firm Epiroc recently applied modeling software to better understand how the batteries for its electric vehicles would perform and age while operating in extremely high temperatures underground. Using simulation software, Epiroc chose the cell that performed best. With these insights, Epiroc made sure that the batteries would still deliver high performance after several years of operation. Residential storage operators can apply the same simulation models to assess the impact of temperature fluctuations on battery aging. Submit a case study! We want to hear about what you’re working on. Submit a case study with the chance to be featured in POWERGRID International. Temperature fluctuations might not be a particular concern for grid-scale BESS. Usually, the containers are air-conditioned at a stable temperature. However, other parameters like depth of discharge, load profiles, and cycle numbers per day influence a BESS lifetime and performance. Battery aging models can predict the impact of all these parameters, not just temperature. New aging models offer a further advantage. While lithium-ion remains the dominant battery storage technology, alternative chemistries are reaching commercialization just as storage operators look to overcome limitations of lithium, such as supply chain concerns. Aging models can predict how alternative batteries will respond in real-world scenarios. Comparing lithium-ion with sodium-ion batteries, engineers can see which technology fits the best in terms of battery performance and lifetime. Modeling that’s compatible with sodium-ion batteries, for example, helps operators learn more about the technology. Battery aging simulation has improved significantly in recent years. One subset of simulation models, for example, investigates physicochemical degradation effects and integrates them into semi-empirical approaches. With that, it can capture complex degradation mechanisms like lithium plating. Lithium plating is a process where lithium ions deposit in a metal form on the anode surface. It can lead to reduced capacity and potentially to short circuits. New aging models also simplify the identification of degradation issues. They summarize them into three main modes: Loss of lithium inventory, loss of active anode material, and loss of active cathode material. This categorization improves the analysis and predictions of battery performance and longevity. In addition to providing information about degradation modes, the new generation of aging models can model open circuit voltage (OCV) over the lifetime of the battery. Especially with Lithium-Iron-Phosphate (LFP) batteries, commonly used with grid-scale batteries, the change in OCV plays a major role. OCV is the voltage at the battery’s terminals when it is at rest, so when no current is flowing. The OCV is directly linked to the State of Charge (SOC). LFP batteries have a very flat voltage profile over a large portion of their charge range. This means that the voltage doesn’t change much when the battery is charging or discharging, especially in the middle range of the SOC. Why is this a problem? For LFP batteries it is hard to estimate SOC: Since the voltage changes very little in the mid-range of SOC, it becomes difficult to accurately determine how much charge is left in the battery using voltage alone. With battery aging, things get even more complicated: Over time, as the battery ages, the OCV curve may shift slightly, based on the reigning degradation modes. This change further complicates SOC estimation and can lead to sudden drops in State of Charge. The change in OCV, however, is often overlooked in simulations. Over time, the accuracy of the simulation models is reduced. New aging models can simulate how the OCV curve changes as the battery ages. In return, it leads to more accurate estimations of State of Charge and State of Health, two of the most common real-time battery indicators for BESS operators. Accurate state estimations are an important factor when operating BESS. In the worst case, inaccurate values lead to penalties. A sudden drop in SOC reduces the amount of energy a system can provide to the grid. Next to penalties, utilities also need to think about BESS lifetime. In trading applications, asset managers need to weigh potential revenue against the long-term impact on battery health. The standard degradation curves from cell suppliers are too generic to provide realistic insights. Usually, this aging data assumes that the battery is fully charged and discharged – something that is not happening in real life. Simulation models assess battery aging based on real-world scenarios, for example with a depth of discharge around 80%. New aging models provide realistic insights into battery aging. With that, they help to develop trading strategies that generate revenue without excessively accelerating aging. This ensures that the system remains cost-effective over its entire lifecycle. For a European generator of renewable energy, adapting trading algorithms to battery aging was beneficial. The utility improved its profitability by more than $1M per 10 MWh. It used the scenarios from the aging models to identify the operating conditions that maximized BESS performance and lifetime. The increase in profitability was followed by a 20% increase in battery lifetime. The advancements in aging models extend far beyond theoretical insights. Using aging simulation, stakeholders ensure they have safe storage operations while simultaneously enhancing system performance and extending the lifetime of their energy storage investments. This proactive approach to managing battery health ensures that BESS installations function optimally, reducing downtime and maximizing return on investment. With simulation models, engineers can make informed decisions regarding cell selection, system design, and operation, ultimately maximizing the efficiency and longevity of BESS installations. Increasingly sophisticated simulation models signify a profound shift in battery technology.

powerplant

Jan 13, 2025

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