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California aims to replace gasoline and diesel light-duty vehicles (LDVs) with zero-emission LDVs, many of which will be plug-in battery electric vehicles (BEVs) and achieve 100% zero-carbon electricity by 2045. Large-scale plug-in BEV deployment will substantially increase electricity demand, particularly during peak hours (4:00pm to 9:00pm) when renewable energy is in short supply. Popular strategies for charging BEVs with electricity produced from renewable energy include smart charging and creating more energy storage that soaks up renewable energy during the day and dispenses it later when needed. These strategies, however, may not be enough. Consumer acceptance limits smart charging, and increased energy storage capacity is expensive. Another potential strategy involves lowering the overall demand for electricity by shifting BEV trips to electric-powered bicycles (e-bikes). While e-bikes cannot entirely replace BEV trips, they are ideal for short trips (five miles or less). Currently, 64% of US vehicle trips fall into the short trip category.

Decarbonization plans depend on the rapid, large-scale deployment of batteries to sufficiently decarbonize the electricity system and on-road transport. This can take many forms, shaped by technology, materials, and supply chain selection, which will have local and global environmental and social impacts. Current knowledge gaps limit the ability of decision-makers to make choices in facilitating battery deployment that minimizes or avoids unintended environmental and social consequences. These gaps include a lack of harmonized, accessible, and up-to-date data on manufacturing and supply chains and shortcomings within sustainability and social impact assessment methods, resulting in uncertainty that limits incorporation of research into policy making. These gaps can lead to unintended detrimental effects of large-scale battery deployment. To support decarbonization goals while minimizing negative environmental and social impacts, we elucidate current barriers to tracking how decision-making for large-scale battery deployment translates to environmental and social impacts and recommend steps to overcome them.

California has ambitious goals for reducing and eliminating greenhouse gas emissions from the State’s electricity system as a cornerstone of efforts to decarbonize the State’s economy more broadly. Electricity decarbonization efforts are codified by Senate Bill (SB) 100 which seeks to have 100% of retail sales of electricity by the year 2045 provided by eligible zero-carbon resources with an interim target of 60% of retail sales of electricity provided by eligible renewable resources by the year 2030. This policy contributes to a broader goal of achieving economy-wide carbon neutrality in the State by 2045, codified by Executive Order B-55-18.Planning studies were undertaken to determine how California should proceed in terms of electricity generation and storage resource rollout to meet these goals, such as the Senate Bill 100 Joint Agency Report [1], which highlights the need for rapid renewable resource and energy storage buildout. Energy storage is typically selected as utility-scale lithium-ion batteries for short-duration storage and pumped hydropower energy storage for long-duration energy storage functions, primarily due to their relatively low cost for the former and technological maturity for the latter. Since the capacity expansion models used for such planning studies focus on minimizing cost, the recommended course from these studies focuses on lithium-ion and pumped hydropower energy storage connected as utility energy storage.In practice, however, energy storage deployment will not be dictated by a central plan. Energy storage is being deployed to serve different priorities. Behind-the-meter energy storage may be deployed by individual residential, commercial, and industrial customers to serve their specific needs, provide electricity savings, and enable higher uptake of local renewable resources. Energy storage may also be installed at wind or solar farms to enable these to act as more dispatchable resources for the electric grid and enable them to provide electricity to the grid when they would otherwise not be generating. Additionally, other energy storage technologies such as flow batteries and hydrogen energy storage are emerging as potential alternatives to lithium-ion batteries and pumped hydropower, each with its own advantages and disadvantages in terms of technical, economic, and practical (i.e. safety, recyclability, etc...) characteristics.Energy storage is a critical enabler of plans for complying with Senate Bill 100 and broader economy-wide decarbonization goals. Therefore, it is critical to understand the effect of alternative configurations for energy storage deployment on the broader electricity system’s ability to rely on zero-carbon electricity for meeting load, how well it can use available renewable electricity generation, and the system-wide cost of electricity.Therefore, the goal of this project is to provide information on the preferred configuration of energy storage technologies for supporting a decarbonized California electric grid by investigating alternative configurations for the buildout of energy storage to meet California’s electricity decarbonization goals and comparing them to the configuration suggested by Senate Bill 100 planning studies.

The present project aims to provide information on the preferred configuration of energy storage technologies for supporting a decarbonized California electricity system. Energy storage technologies have been identified as critical for enabling compliance with California’s electricity decarbonization goals. While lithium-ion batteries are currently the leading option for meeting energy storage needs, particularly in the near term, a diverse array of other commercial or near-commercial energy storage technologies are available that have characteristics better suited to meet the particular needs of a future electricity system.In this context, the present project aims to determine which energy storage technologies are best suited to serve different functions required to operate a future, decarbonized electricity system in California and elucidate how energy storage technology characteristics map to their suitability for different applications. This will be accomplished by meeting the following objectives:  Determine the net costs associated with deploying different energy storage technology portfolios to facilitate an electricity system that complies with SB 100 goals and IRP targets.  Compare the costs and benefits associated with the use of different energy storage technology portfolios in terms of expenditures and system-wide electricity system operations.  Determine the energy storage characteristics that are better suited for providing different grid services at a minimal net cost.

Batteries are important for promoting renewable energy, but, like most engineered products, they contain multiple hazardous materials. The purpose of this study is to evaluate industrial-scale batteries using GreenScreen® for Safer Chemicals, an established chemical hazard assessment (CHA) framework, and to develop a systematic, transparent methodology to quantify the CHA results, harmonize them, and aggregate them into single-value hazard scores, which can facilitate quantitative comparison and a robust evaluation of data gaps, inconsistencies, and uncertainty through the implementation of carefully selected scenarios and stochastic multicriteria acceptability analysis (SMAA). Using multiple authoritative toxicity data sources, six battery products are evaluated: three lithium-ion batteries (lithium iron phosphate, lithium nickel cobalt manganese hydroxide, and lithium manganese oxide), and three redox flow batteries (vanadium redox, zinc-bromine, and all-iron). The CHA results indicate that many materials in these batteries, including reagents and intermediates, inherently exhibit high hazard; therefore, safer materials should be identified and considered in future designs. The scenario analysis and SMAA, combined, provide a quantitative evaluation framework to support the decision-making needed to compare alternative technologies. Thus, this study highlights specific strategies to reduce the use of hazardous materials in complex engineered products before they are widely used in this rapidly-expanding industry sector.

Energy storage systems are critical for enabling the environmental benefits associated with capturing renewable energy to displace fossil fuel-based generation, yet producing these systems also contributes to environmental impacts through their materials use and manufacturing. As energy storage capacity is scaled up to support increasingly renewable grids, the environmental benefits from their use may scale at different rates than the environmental impacts from their production. This implies the existence of capacity thresholds beyond which installing additional storage capacity may be environmentally detrimental. Identifying such thresholds are important for ensuring that energy storage capacity selection in future grids are consistent with net emissions reduction goals, but such thresholds have not been studied in the present literature. To identify such thresholds, here we combine electric grid dispatch modeling with life cycle analysis to compare how the emissions reductions from deploying three different flow battery energy storage types on a future California grid (>80% wind and solar) compare with emissions contributions from producing such batteries as total battery capacity installed on the grid increases. Depending on the type of battery and environmental impact indicator (greenhouse gas or particulate matter emissions), we find that the marginal environmental benefits of storage begin to diminish at deployed capacities of 38–76% of the mean daily renewable generation (256–512 GWh in our California scenarios) and reach zero at 105–284% of mean daily renewable generation (700–1810 GWh). Such storage capacities are conceivable, but upstream impacts of storage must be assessed in evaluating the environmental benefits of large-scale storage deployment, or they could negate the environmental benefits of regional electricity system decarbonization.

To aid in addressing issues of air quality and greenhouse gas (GHG) emissions in the South Coast Air Basin, local transit agencies are considering a shift to battery electric buses (BEBs) and hydrogen fuel cell electric buses (FCEBs). Each of these options vary in their overall effectiveness in reducing different emission types over their life cycle, associated life cycle costs, ability to meet operational needs of transit agencies, and life cycle environmental footprint. This project carried out a life cycle-based analysis and comparison of the GHG emissions, criteria pollutant emissions, and other environmental externalities associated with BEBs and FCEBs, taking into account their ability to meet operational constraints of the Orange County Transportation Authority. From an environmental footprint perspective, this study found the following. First, both FCEBs and long-range BEBs have comparable impacts for global warming potential and particulate matter formation but when the FCEBs were fueled using renewable hydrogen. Second, using electricity from the current California grid mix to drive electrolysis to produce hydrogen for FCEBs produced only marginal benefits compared to current natural-gas fueled vehicles due to the low supply chain efficiency of this pathway. Third, the mining of precious metals is a major contributor to environmental footprint categories for both BEBs and FCEBs. Fourth, both FCEVs and long-range BEBs provide significant reductions in environmental footprint compared to conventional diesel and natural gas buses. From a cost perspective, this study found the following. First, with current-day cost inputs, FCEBs and BEBs have comparable total cost of ownership, but both have slightly higher costs than diesel and natural gas buses. Second, FCEBs have an equivalent total cost of ownership to BEBs when the electricity rate for charging is $0.24/kWh. Higher values render FCEBs as the cheaper option and lower values render BEBs as the cheaper option. Second, the total cost of ownership of these technologies is highly sensitive to electricity costs, and the rapid evolution of the electricity system has strong implications for the economic comparison between BEBs and FCEBs. Overall, this study finds that while both FCEBs and BEBs provide life-cycle environmental benefits, further cost reductions in electricity rates and initial purchase costs are needed to achieve total cost of ownership parity with conventional bus powertrains. With the rapid evolution of the electricity system and falling costs for renewable electricity resources, these cost reductions may occur in the near future.

Climate change and increased electrification of space and water heating in buildings can significantly affect future electricity demand and hourly demand profiles, which has implications for electric grid greenhouse gas emissions and capacity requirements. We use EnergyPlus to quantify building energy demand under historical and under several climate change projections of 32 kinds of building prototypes in 16 different climate zones of California and imposed these impacts on a year 2050 electric grid configuration by simulation in the Holistic Grid Resource Integration and Deployment (HIGRID) model. We find that climate change only prompted modest increases in grid resource capacity and negligible difference in greenhouse gas emissions since the additional electric load generally occurred during times with available renewable generation. Heating electrification, however, prompted a 30-40% reduction in greenhouse gas emissions but required significant grid resource capacity increases, due to the higher magnitude of load increases and lack of readily available renewable generation during the times when electrified heating loads occurred. Overall, this study translates climate change and electrification impacts to system-wide endpoint impacts on future electric grid configurations and highlights the complexities associated with translating building-level impacts to electric system-wide impacts.

A study was conducted to compare the technical potential and effectiveness of different water supply options for securing water availability in a large-scale, interconnected water supply system under historical and climate-change augmented inflow and demand conditions. Part 2 of the study focused on determining the greenhouse gas and renewable energy utilization impacts of different pathways to stabilize major surface reservoir levels. Using a detailed electric grid model and taking into account impacts on the operation of the water supply infrastructure, the greenhouse gas emissions and effect on overall grid renewable penetration level was calculated for each water supply option portfolio that successfully secured water availability from Part 1. The effects on the energy signature of water supply infrastructure were found to be just as important as that of the fundamental processes for each option. Under historical (baseline) conditions, many option portfolios were capable of securing surface reservoir levels with a net neutral or negative effect on emissions and a benefit for renewable energy utilization. Under climate change augmented conditions, however, careful selection of the water supply option portfolio was required to prevent imposing major emissions increases for the system. Overall, this analysis provided quantitative insight into the tradeoffs associated with choosing different pathways for securing California's water supply.

The technical potential and effectiveness of different water supply options for securing water availability in a large-scale, interconnected water supply system under historical and climate-change augmented inflow and demand conditions were compared. Part 1 of the study focused on determining the scale of the options required to secure water availability and compared the effectiveness of different options. A spatially and temporally resolved model of California's major surface reservoirs was developed, and its sensitivity to urban water conservation, desalination, and water reuse was examined. Potential capacities of the different options were determined. Under historical (baseline) hydrology conditions, many individual options were found to be capable of securing water availability alone. Under climate change augment conditions, a portfolio approach was necessary. The water savings from many individual options other than desalination were insufficient in the latter, however, relying on seawater desalination alone requires extreme capacity installations which have energy, brine disposal, management, and cost implications. The importance of identifying and utilizing points of leverage in the system for choosing where to deploy different options is also demonstrated.

A spatial and temporal analysis of wind power generation characteristics was conducted in order to determine the implications of intermittent wind generation dynamics on the profile of the electric loads that must be balanced by dispatchable electrical generators on the electric grid. A parametric analysis was conducted to evaluate the sensitivity of the typical magnitudes of wind power fluctuations on different timescales, power variation range, typical daily and seasonal wind profiles to wind farm size and regional distribution. A methodology to evaluate wind dynamics based on power spectral density analyses have been developed. Results indicate that increasing the size of a local wind farm significantly reduced the magnitude of wind power fluctuations on timescales faster than 12 h, with the largest reductions occurring at the fastest timescales. Additional reductions in power fluctuations can be achieved with the implementation of local and regional distribution of wind turbines in disperse high wind areas. In these cases, it was discovered that the timescale band within which the largest reductions in power fluctuations occurred was dependent on regional geographic features, and did not necessarily correspond to the fastest timescales. In addition, it was also discovered that the aggregation of wind power from different regions could produce a more uniform frequency distribution of power fluctuation reductions. © 2011 Elsevier Ltd.

A parametric study of a solid oxide fuel cell-gas turbine (SOFC-GT) hybrid system design is conducted with the intention of determining the thermodynamically based design space constrained by modern material and operating limits. The analysis is performed using a thermodynamic model of a generalized SOFC-GT system where the sizing of all components, except the fuel cell, is allowed to vary. Effects of parameters such as pressure ratio, fuel utilization, oxygen utilization, and current density are examined. Operational limits are discussed in terms of maximum combustor exit temperature, maximum heat exchanger effectiveness, limiting current density, maximum hydrogen utilization, and fuel cell temperature rise. It was found that the maximum hydrogen utilization and combustor exit temperature were the most significant constraints on the system design space. The design space includes the use of cathode flow recycling and air preheating via a recuperator (heat exchanger). The effect on system efficiency of exhaust gas recirculation using an ejector versus using a blower is discussed, while both are compared with the base case of using a heat exchanger only. It was found that use of an ejector for exhaust gas recirculation caused the highest efficiency loss, and the base case was found to exhibit the highest overall system efficiency. The use of a cathode recycle blower allowed the largest downsizing of the heat exchanger, although avoiding cathode recycling altogether achieved the highest efficiency. Efficiencies in the range of 50-75% were found for variations in pressure ratio, fuel utilization, oxygen utilization, and current density. The best performing systems that fell within all design constraints were those that used a heat exchanger only to preheat air, moderate pressure ratios, low oxygen utilizations, and high fuel utilizations. Copyright © 2010 by ASME.

A 100 MW-class planar solid oxide fuel cell synchronous gas turbine hybrid system has been designed, modeled, and controlled. The system is built of 70 functional fuel cell modules, each containing 10 fuel cell stacks, a blower to recirculate depleted cathode air, a depleted fuel oxidizer, and a cathode inlet air recuperator with bypass. The recuperator bypass serves to control the cathode inlet air temperature, while the variable speed cathode blower recirculates air to control the cathode air inlet temperature. This allows for excellent fuel cell thermal management without independent control of the gas turbine, which at this scale will most likely be a synchronous generator. In concept the demonstrated modular design makes it possible to vary the number of cells controlled by each fuel valve, power electronics module, and recirculation blower, so that actuators can adjust to variations in the hundreds of thousands of fuel cells contained within the 100 MW hybrid system for improved control and reliability. In addition, the modular design makes it possible to take individual fuel cell modules offline for maintenance while the overall system continues to operate. Parametric steady-state design analyses conducted on the system reveal that the overall fuel-to-electricity conversion efficiency of the current system increases with increased cathode exhaust recirculation. To evaluate and demonstrate the conceptualized design, the fully integrated system was modeled dynamically in MATLAB-SIMULINK. Simple proportional feedback with steady-state feed-forward controls for power tracking, thermal management, and stable gas turbine operation were developed for the system. Simulations of the fully controlled system indicate that the system has a high efficiency over a large range of operating conditions, decent transient load following capability, fuel and ambient temperature disturbance rejection, and the capability to operate with a varying number of fuel cell modules. The efforts here build on prior work and combine the efforts of system design, system operation, component performance characterization, and control to demonstrate hybrid transient capability in large-scale coal synthesis gas-based applications through simulation. Furthermore, the use of a modular fuel cell system design, the use of blower recirculation, and the need for integrated system controls are verified. © 2010 by ASME.