Optimizing integrated renewable and gaseous systems for grid and residential applications

In the United States, lower electricity prices because of the large deployment of natural gas and renewable electricity generation technologies might present an opportunity to produce energy carriers, such as hydrogen, to replace existing fuels. To assess this opportunity, integrated renewable and gaseous systems for grid and residential applications were examined as the following three studies: 1) impacts of renewable hydrogen production on potential hydrogen demand for on-road vehicles, 2) effects of electrolyzer facility locations on hydrogen supply-chain for light-duty vehicles in Texas, and 3) assessment of primary energy consumption, carbon dioxide emissions, and peak electric load for a residential fuel cell using empirical natural gas and electricity use profiles. The first study included two-part analyses: 1) determining the required growth in renewable power and water usage to power transportation in the United States with hydrogen at the national-level, and 2) investigating the technical and economic potential of hydrogen demand and production in electricity markets. The first part of this work assessed the potential for hydrogen to act as an energy carrier to replace existing energetic requirements for on-road vehicles in the United States. This work quantified the amount of hydrogen needed to deliver the energy that is currently used in the transportation sector by on-road vehicles along with associated water demand and CO₂ emissions. Results showed that approximately 16 quadrillion BTUs (Quads) of electricity would be needed to produce nearly 11 Quads of hydrogen via electrolysis to displace the approximately 22 Quads of fuels that met the energy needs of road vehicles in the United States during 2016. Using a capacity factor of 25%, which is typical for new solar farms in the desert southwest, the required capacity of new renewable power generation to produce an additional 16 Quads of electricity is approximately 2.1 TW if all of that electricity was generated by new solar farms. Since the electricity generating capacity in the United States was approximately 1.2 TW (including approximately 108 GW of renewables in 2016, excluding hydroelectric and biomass), the results indicate that a significant investment would be necessary to produce hydrogen via electrolysis powered by renewable electricity. Using hydrogen produced from renewable electricity for road vehicles would reduce energy requirements in the transportation sector by over 40%, the rejected energy in the overall economy would be reduced by over 9.5%, and CO₂ emissions would be reduced by over 1.56 billion metric tons (approximately a 30% reduction in total U.S. CO₂ emissions). At scale, approximately 1.5 trillion liters (400 billion gallons) of distilled water per year would be required to produce nearly 11 Quads of hydrogen, which is approximately 0.4% of total freshwater withdrawals in the United States. Furthermore, the second part of this work developed two methods to investigate the technical and economic potential of hydrogen demand and production: 1) estimating potential hydrogen demand for light-duty vehicles (LDVs) at the county-level using a first-order engineering model, and 2) quantifying temporal renewable hydrogen production from wind energy using a linear programming model. The potential hydrogen demand was primarily evaluated for three geographical regions: 1) the United States, 2) Texas, and 3) the Texas Triangle which is one of the nation's most important mega-regions. The linear programming model compared marginal electricity and hydrogen prices to maximize revenue over the course of a year. The analysis primarily focused on the Electric Reliability Council of Texas (ERCOT), but also included other six U.S. electricity markets for hypothetical analysis. Results showed that the potential hydrogen demand for the United States, Texas, and the Texas Triangle are 53.3, 5.3, and 3.9 billion kg, respectively. Using the electrolyzer system energy efficiency of 75% and the marginal hydrogen price of $4/kg, the wind energy in Texas as of 2015 could produce nearly 0.84 billion kg of hydrogen, which could supply about 22% of the potential hydrogen demand for LDVs in the Texas Triangle. When the marginal hydrogen price is low (e.g. $1/kg), it is only favorable to produce hydrogen during early morning hours, especially, 2--6 a.m., in ERCOT and other electricity markets except California's market. These results could provide information for decision makers to better understand the holistic feasibility of a hydrogen economy in the United States. The second study examined the following two scenarios for identifying the effects of electrolyzer facility locations on hydrogen supply-chain for light-duty vehicles in Texas: 1) a wind farm and an electrolyzer facility are co-located, and hydrogen is transported via trucks from production sites to demand sites, and 2) an electrolyzer facility is located at a demand site, and hydrogen is produced using the grid electricity during off-peak hours. This analysis used geographical datasets to estimate delivering costs as well as electrolyzer facility installment costs. Using integer programming models, this work quantified optimal values of total costs while satisfying capacity and other constraints for hydrogen production. Results showed that the optimal values for Scenario 1 (centralized hydrogen production) are approximately twice as high as Scenario 2 (distributed hydrogen production), suggesting that the location of an electrolyzer facility significantly affects total costs of hydrogen supply-chain. While most of delivering paths look similar for both scenarios, the number of wind farms used for hydrogen production for Scenario 2 is higher than Scenario 1, which could be because of the line loss for Scenario 2. The wind farms located in South Texas primarily serve the region of Houston and San Antonio. However, as the hydrogen demand increases, the wind farms located in West Texas also serves this region, resulting a long distance of delivering hydrogen or electrons. A sensitivity analysis shows that trucking hydrogen is economical only with favorable electrolyzer CAPEX and hydrogen transportation cost. Lastly, the third study used empirical data for 20 single-family homes from a smart grid demonstration project in Austin, Texas to create intra-day natural gas and electricity use profiles on one-minute intervals based on cooling and heating degree days. Combining these intra-day energy use profiles with emissions factors and a linear programming model, temporal energy use profiles were evaluated to quantify primary energy consumption, CO₂ emissions, and peak electric load for a house with a residential fuel cell used as on-site power generation versus being connected to the electric grid. Results showed that natural gas use primarily peaked in the morning, while electricity use peaked in the afternoon. For fuel cell capacities of 0--3.0 kW [subscript e] and efficiency of 40%, total CO₂ emissions, including the fuel cell for the cooling day, were 1.7--1.9 times higher than the heating day. For a fuel cell capacity of 1.0 kW [subscript e] and efficiency of 40%, peak electric load decreased during on-peak hours (14:00--20:00) for the cooling and heating days by 60% and 44%, respectively. Effects of fuel cell capacity and efficiency on total primary energy consumption and CO₂ emissions showed that as the fuel cell capacity and efficiency increased, primary energy consumption and CO₂ emissions were reduced from the baseline values that represent conventional homes' patterns. These results show that the use of residential fuel cells can offer environmental benefits from reducing primary energy consumption and CO₂ emissions, and grid reliability benefits by reducing peak electric load. All three studies have demonstrated that optimized integrated renewable and gaseous systems for grid and residential applications could offer enhanced grid reliability and decarbonization in multiple sectors.