Evaluating the Potential for Hydrogen Co-Firing to Reduce Emissions from Electricity Generation
Creators: name: Mohamed, Fathelrahman
Publisher: name: Graduate Studies
Year: 2023
Subjects: subject: Electricity
subject: Natural Gas
subject: Hydrogen
subject: Gas Turbine
subject: Alberta TIER
subject: Carbon Intensity
subject: Energy
subject: Engineering

description: Direct emissions from electricity generation in Alberta were approximately 36 MtCO2e/y in 2019, which is approximately 10% of the total emissions in the province. While the phase out of coal-fired generation under way in Alberta will contribute to a reduction in emissions, there is much work that remains to achieve net-zero by 2050 in electricity generation. For example, Alberta had around 2 GW of natural gas combined cycle (NGCC) generation capacity in 2019, which was approximately 13% of total generating capacity, and based on the Alberta Electric System Operator (AESO) connections queue, NGCC capacity in the province is expected to increase, growing this capacity further. There are several options to address emissions from this gas-fired generation, including application of carbon capture (CC) units, co-firing with hydrogen and hydrogen-methane blends, and replacement with renewables coupled to energy storage. While much has been said, primarily by turbine manufacturers, about the potential for co-firing hydrogen, there is little public data on the performance impacts. In this work, I assess the potential application of hydrogen fuels to decarbonize existing NGCC power plants and compare with application of CC unit to the same plants. A simulation model of a modern NGCC was developed to assess the performance, including efficiency and electric power output, for increasing the amount of hydrogen in the fuel. Using the model, I observe that adding hydrogen to the fuel will result in extra water vapour in the exhaust gas products, which could cause excessive thermal stress on the hot gas path. Thus, modifications that depend both on the desired hydrogen blend and the turbine model will likely be required, especially for older power plants. Perhaps the simplest way to maintain hot gas parts at temperatures near or lower than that of natural gas fuel is to reduce the firing temperature, which is advised by the majority of machine manufacturers. While results from the simulation model confirm that blending 5%-70% of pure hydrogen by volume in the fuel resulted in 1.5%-50% reduction in direct CO2 emissions, I also observe that power output (and, thus, net efficiency) may decrease. I use the results from this model to estimate the reduction in power output, the life cycle greenhouse gas (GHG) emissions reduction, and the cost of power as a function of hydrogen percentage and reduction in firing temperature. The results allow us to compare the mitigation cost directly with that for a CC unit, and to better understand how they might compare with use of renewables and storage. The results of the study suggest that implementing the Technology Innovation and Emission Reduction Regulation (TIER) carbon tax and credit system for a power plant with a 15-year lifespan in Alberta, the use of hydrogen blended fuel would increase the levelized cost of electricity (LCOE) at least by 20% for high-efficiency hydrogen gas turbine cycles due to the high fuel prices, which can account for over 60% of gas-fired plant LCOE. Therefore, retrofitting the plant with CC unit would be a more competitive option than using 40% hydrogen blended fuel. The study also found that when the carbon price is low and following TIER best performance benchmark emission regime, using pure natural gas would be cost-effective, as the current carbon price is too low to justify switching to hydrogen. However, at higher carbon prices, plant owners may find adding CC unit or even building a new plant with CC unit more attractive. To achieve breakeven carbon costs for 100% hydrogen gas turbines compared to natural gas equivalents, it would require a carbon price range of C$250/ton to C$300/ton, which is approximately four times the current Alberta carbon price and 1.5 times the projected carbon price in 2030. The results of this work will be of interest not only to the power sector in Alberta, but also to regulators and policy makers who will be faced with extending existing policy frameworks and building new ones to support net-zero ambitions.