• Energy Research

High temperature water splitting (HTWS) via electrochemical processes are of growing interest due to their potential for achieving high thermodynamic efficiency. In particular, protonic ceramic electrolysis cells (PCECs) operating between 500°-600°C have the attractive feature that, in theory, pure dry hydrogen is produced at the hydrogen electrode (see Figure 1) and, unlike more conventional solid oxide electrochemical cells (SOECs) operating at 800°C, no further gas separation is needed. These features allow much simpler and elegant hydrogen production system concepts that have the potential to be significantly less costly and more efficient. For example, the dry H2 gas production at the fuel electrode allows for a much simpler balance-of-plant. The lower operating temperature also has numerous benefits, including lower plant heat losses, the ability to find more options for integrating various process heat sources by virtue of the lower grade heat requirements, and reduced capital cost due to a reduction in both gas process heat exchanger temperature and surface area requirements. A simple thermodynamic evaluation indicates that balance-of-plant steam generation specific energy (kJ/kg) requirements are some 17% lower when operating at 500°C versus 800°C. The present work focuses on scale-up of advancing PCEC material sets developed by collaborating faculty at the Colorado School of Mines and an industrial partner, and their design/integration into MW-scale hydrogen production systems. Realizing high efficiency HTWS systems based on novel protonic ceramics requires understanding of numerous system-level considerations. One of our efforts is largely concerned with developing viable system designs that enable >75% system efficiency at centralized hydrogen production costs of < $2/kg (without compression, dispensing, and storage). This requires evaluation of plant operating conditions, especially in the PCEC stack periphery, where operating temperature, pressure, reactant utilization, sweep gas (if any) on the fuel electrode, thermal management, gas compression, and balance-of-plant integration all play critical roles in establishing cost effective, high performance HTWS systems. In this presentation, validated PCEC models using the latest large platform experimental cell data are used to explore optimal stack design parameter selection, such as cell voltage, reactant utilization, and reactant supply composition. System design implications from parameter sensitivity studies is summarized, and a comparative techno-economic analysis of PCEC-based hydrogen production systems with SOEC and PEMEC technologies is given. Figure 1

Abstract Utilities have greatly increased the use of time-of-use (TOU) rate structures for residential customers to more closely match the cost of delivered electricity as well as demand tariffs to incentivize a temporal shift in residential energy use. However current research tends to focus on a particular climate or location. This study analyzes four residences across four different climate zones in Arizona and explores the value of adding battery storage to a net-zero energy (NZE) photovoltaic (PV) system. Using the National Renewable Energy Lab's Building Optimization (BEopt) and System Advisor Model (SAM) tools, this study performs parametric analysis by varying battery size to determine a capacity that produces a maximum net present value (NPV). A sensitivity analysis on three possible future battery price trends is also performed. This study finds the NZE PV systems are only able to mitigate 37–44% of the peak electricity purchases and 4–12% of demand charges due to mismatch between solar potential and on-peak hours. Adding large batteries, 1.5–1.6 times larger than required to meet the annual peak energy purchase requirements, provides a maximum NPV for PV-battery systems at locations with favorable utility rates. We conclude that the best economics are achieved, at both current and expected future battery prices, when batteries are sized to never require replacement during the PV system lifetime.

Existing modeling approaches for long-duration energy storage (LDES) are often based either on an oversimplified representation of power system operations or limited representation of storage technologies, e.g., evaluation of only a single application. This manuscript presents an overview of the challenges of modeling LDES technologies, as well as a discussion regarding the capabilities and limitations of existing approaches. We used two test power systems with high shares of both solar photovoltaics- and wind (70% - 90% annual variable renewable energy shares) to assess LDES dispatch approaches. Our results estimate that better dispatch modeling of LDES could increase the associated operational value by 4% - 14% and increase the standard capacity credit by 14% - 34%. Thus, a better LDES dispatch could represent significant cost saving opportunities for electric utilities and system operators. In addition, existing LDES dispatch modeling approaches were tested in terms of both improved system value (e.g., based on production cost and standard capacity credit) and scalability (e.g., based on central processing unit time and peak memory usage). Both copper plate and nodal representations of the power system were considered. Although the end volume target dispatch approach, i.e., based on mid-term scheduling, showed promising performance in terms of both improved system value and scalability, there is a need for robust and scalable dispatch approaches for LDES in transmission-constrained electric grids. Moreover, more research is required to better understand the optimal operation of LDES considering extreme climate/weather events, reliability applications, and power system operational uncertainties. Comment: 45 pages, 16 figures, Submitted to Renewable and Sustainable Energy Reviews