Explore the vast range of titles available.

Under the increasing penetration of distributed energy resources and new smart network technologies, distribution utilities face new challenges and opportunities to ensure reliable operations, manage service quality, and reduce operational and investment costs. Simultaneously, the research community is developing algorithms for advanced controls and distribution automation that can help to address some of these challenges. However, there is a shortage of realistic test systems that are publically available for development, testing, and evaluation of such new algorithms. Concerns around revealing critical infrastructure details and customer privacy have severely limited the number of actual networks published and that are available for testing. In recent decades, several distribution test feeders and US-featured representative networks have been published, but the scale, complexity, and control data vary widely. This paper presents a first-of-a-kind structured literature review of published distribution test networks with a special emphasis on classifying their main characteristics and identifying the types of studies for which they have been used. This both aids researchers in choosing suitable test networks for their needs and highlights the opportunities and directions for further test system development. In particular, we highlight the need for building large-scale synthetic networks to overcome the identified drawbacks of current distribution test feeders.

This work describes the Grid-Enhanced, Mobility-Integrated Network Infrastructures for Extreme Fast Charging (GEMINI) architecture for the co-simulation of distribution and transportation systems to evaluate EV charging impacts on electric distribution systems of a large metropolitan area and the surrounding rural regions with high fidelity. The current co-simulation is applied to Oakland and Alameda, California, and in future work will be extended to the full San Francisco Bay Area. It uses the HELICS co-simulation framework to enable parallel instances of vetted grid and transportation software programs to interact at every model timestep, allowing high-fidelity simulations at a large scale. This enables not only the impacts of electrified transportation systems across a larger interconnected collection of distribution feeders to be evaluated, but also the feedbacks between the two systems, such as through control systems, to be captured and compared. The findings are that with moderate passenger EV adoption rates, inverter controls combined with some distribution system hardware upgrades can maintain grid voltages within ANSI C.84 range A limits of 0.95 to 1.05 p.u. without smart charging. However, EV charging control may be required for higher levels of charging or to reduce grid upgrades, and this will be explored in future work.

With the increasing share of distributed energy resources on the electric grid, utility companies are facing significant decisions about infrastructure upgrades. An alternative to extensive and capital-intensive upgrades is to offer non-firm interconnection opportunities to distributed generators, via a coordinated operation of utility scale resources. This paper introduces a novel flexible interconnection option based on the last-in, first-out principles of access aimed at minimizing the unnecessary non-firm generation energy curtailment by balancing access rights and contribution to thermal overloads. Although we focus on solar photovoltaic (PV) plants in this work, the introduced flexible interconnection option applies to any distributed generation technology. The curtailment risk of individual non-firm PV units is evaluated across a range of PV penetration levels in a yearlong quasi-static time-series simulation on a real-world feeder. The results show the importance of the size of the curtailment zone in the curtailment risk distribution among flexible generation units as well as that of the “access right” defined by the order in which PV units connect to the grid. Case study results reveal that, with a proper selection of curtailment radius, utilities can reduce the total curtailment of flexible PV resources by up to more than 45%. Findings show that non-firm PV generators can effectively avoid all thermal limit-related upgrade costs.

The amount of water required for electricity generation is expected to increase as CO 2 emissions are reduced. A capacity expansion model of the Texas electricity grid in the USA demonstrates the trade-offs between CO 2 emissions and water use in designing the power generation mix. Better understanding of the ‘water–energy nexus’ should help to coordinate mitigation and adaptation planning in the energy sector. In 2011, the state of Texas experienced the lowest annual rainfall on record 1 , with similar droughts affecting East Africa, China and Australia. Climate change is expected to further increase the likelihood and severity of future droughts 2 . Simultaneously, population and industrial growth increases demand for drought-stressed water resources 3 and energy, including electricity. In the US, nearly half of water withdrawals are for electricity generation 4 , much of which comes from greenhouse gas emitting fossil fuel combustion. The result is a three-way tension among efforts to meet growing energy demands while reducing greenhouse gas emissions and water withdrawals, a critical issue within the so-called water–energy nexus. We focus on this interaction within the electric sector by using a generation expansion planning model to explore the trade-offs. We show that large reductions in CO 2 emissions would probably increase water withdrawals for electricity generation in the absence of limits on water usage, and that simultaneous restriction of CO 2 emissions and water withdrawals requires a different mix of energy technologies and higher costs than one would plan to reduce either CO 2 or water alone.

Purpose of Review Increased charging needs from widespread adoption of battery electric vehicles (EVs) will impact electricity demand. This will likely require a combination of potentially costly distribution infrastructure upgrades and synergistic grid-transportation solutions such as managed charging and strategic charger placement. Fully implementing such strategic planning and control methods—including business models and mechanisms to engage and compensate consumers—can minimize or even eliminate required grid upgrades. Moreover, there are also opportunities for EV charging to support the grid by helping solve existing and emerging distribution system challenges associated with increasing distributed energy resources (DERs) such as solar generation and battery energy storage. This paper reviews the potential impacts of EV charging on electricity distribution systems and describes methods from the literature to efficiently integrate EVs into distribution systems. Recent Findings Recent work has begun to extend beyond earlier efforts with limited adoption, simple controls, and mostly plug-in hybrid EVs and short-range EVs to look at high adoption rates of long-range EVs, larger distribution test systems, and more advanced EV charge control methods. In addition, increased interest and viability of higher power charging have prompted several studies showing how adverse impact from EV charging on electricity distribution systems can be exacerbated by high-power charging levels and concentrated EV adoption in certain areas. There has also been considerable recent effort to look at bulk transmission-level impacts of widespread EV adoption, which often includes a brief mention of distribution concerns, while also highlighting EV-distribution interactions as a key need for future work. Summary The additional loads from widespread EVs could require costly upgrades to maintain distribution system reliability; however, careful planning and advanced operations strategies can reduce or eliminate such upgrade needs. Moreover, EV charging infrastructure can also support grid stability and improve distribution systems especially when paired with distributed solar, storage, or when equipped with smart charge management and grid-interactive support. Previous studies have found that impacts of unmanaged charging include limited load hosting capacity, transformer and line overloads, and voltage and power quality degradation. Past studies have also explored a wide range of opportunities to mitigate these impacts, including traditional upgrades, enhanced controls, and market design. However, the smaller-scale of most past studies limits their ability to capture impacts and opportunities introduced by managed EV charging, regional-scale movement of EVs, and more widespread EV deployment. With accelerated EV adoption driven by sustained technology progress, policy support, and rapid charging infrastructure deployment, it will become increasingly important to capture entire regions, rather than a single or a few feeders; to advance theoretical control developments to be simulated against more realistic and diverse distribution systems and to advance to widescale field deployments; and to develop more holistic approaches which incorporate EV charging alongside a variety of distributed energy resources. This will require enhanced collaboration across multiple disciplines to develop cost-effective and reliable solutions for the combined mobility and electricity systems of the future.

In 2011, the state of Texas experienced the lowest annual rainfall on record, with similar droughts affecting East Africa, China and Australia. Climate change is expected to further increase the likelihood and severity of future droughts. Simultaneously, population and industrial growth increases demand for drought-stressed water resources and energy, including electricity. In the US, nearly half of water withdrawals are for electricity generation, much of which comes from greenhouse gas emitting fossil fuel combustion. The result is a three-way tension among efforts to meet growing energy demands while reducing greenhouse gas emissions and water withdrawals, a critical issue within the so-called water-energy nexus. We focus on this interaction within the electric sector by using a generation expansion planning model to explore the trade-offs. We show that large reductions in CO sub(2) emissions would probably increase water withdrawals for electricity generation in the absence of limits on water usage, and that simultaneous restriction of CO sub(2) emissions and water withdrawals requires a different mix of energy technologies and higher costs than one would plan to reduce either CO sub(2) or water alone.