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This study evaluates optimal carbon‐neutral power supply strategy in China up to 2060 with a multi‐region high spatial and temporal dynamic optimal power expansion planning model. Furthermore, this study explores installable potential of hydrogen and fuel cell system and analyzes the influences of its capital cost reduction at different levels. The results show that the national installed capacity would rise to be over 9000 GW in 2060, in which wind and solar PV will take up around 61%; the intermittency of renewable power generation is mainly managed with hydrogen production, power output curtailment and charge and discharge of energy storage; hydrogen and fuel cell system would improve the capacity factor and reduce the curtailment rate of renewable power generation. © 2023 The Authors. IEEJ Transactions on Electrical and Electronic Engineering published by Institute of Electrical Engineer of Japan and Wiley Periodicals LLC. [ABSTRACT FROM AUTHOR]

• Modeled grid-connected hydrogen storage and carbon capture and storage (CCS) technology. • Hydrogen storage becomes economically feasible in carbon-regulated cases only when the system cost reduces by 20%. • The production and storage profiles of hydrogen are influenced by the seasonal, weather, and diurnal variations. • To reduce 80% emission by 2050, about 179 GW, 106 GW, and 35 GW of CCS-based coal power plants should be constructed in the eastern, western, southern parts of India. • Northern and southern part benefits the most from the CCS based power generation in the eastern part of India. This study integrates grid-connected hydrogen storage and carbon capture and storage (CCS) technology in a spatially disaggregated capacity expansion model, that can explicitly characterize the operational behavior of other conventional technologies. The model is then used to assess the decarbonizing pathways of the integrated power grid of four countries: Bangladesh, Bhutan, India, and Nepal of South Asia under multiple policy scenarios. The impact of the cost associated with hydrogen system components, and with capturing, transporting, and injecting CO 2 in storage sites on the technology choices and their capacities are further evaluated through sensitivity analysis. The hydrogen storage system is effective in tapping surplus energy produced from intermittent renewables mostly in coal deficit regions for both short as well as long-term duration, but its large-scale deployment depends on electrolyzer and fuel cell cost reductions by more than 20% to compete against battery technology. In a very optimistic situation of 90% cost reduction, northern, western, southern parts of India and Bangladesh can completely decarbonize its power sector by 2050 through the installation of about 593 GW, 395 GW, 138 GW, and 120 GW of hydrogen storage tank. The storage and production profiles of hydrogen are influenced by seasonal, weather, and diurnal variations. Under limited solar PV and nuclear scenario, India should start operating CCS-based coal power plants from 2030 to meet the 80% emission reduction target and techno-economically feasible capacity requirements reach about 179 GW, 106 GW, and 35 GW by 2050 in the eastern, western, and southern parts of India respectively. [ABSTRACT FROM AUTHOR]

In this paper, a regionally disaggregated global energy model treating energy and CO2 transportation in detail is used to examine a cost-effective pattern for their interregional transportation over the 21st century under the CO2 stabilization target of 550 ppm. Also, we assess future perspectives for the hydrogen economy in such a scenario. The results show that as major petroleum and gas supplies shift to unconventional resources along the second half of this century due to resource depletion, the Middle East loses its importance as a petroleum and gas exporter and the global patterns of their transportation change significantly. We then show that while hydrogen's competitiveness decreases due to the detailed treatment of energy and CO2 transportation, biomass- derived Fischer­Tropsch (FT) fuels become attractive because their production facilitates a wide diffusion of CO2-neutral energy carriers by considerably reducing the transportation cost. FT fuels are produced in regions rich in forest resources and then transported on a large scale by tanker. By contrast, hydrogen is produced mainly at the center of its consumption regions using domestic feedstock, and its interregional delivery, which is done only by pipeline, plays a marginal role due to its high transportation cost. It is confirmed that such a hydrogen supply structure offers energy security benefits. Finally, we show that the regional distribution of CO2 storage capacity is a major determinant of the pattern of hydrogen transportation around 2100, because all the CO2 generated from hydrogen production is required to be captured for sequestration in that period and because interregional CO2 transportation is hardly chosen for economic reasons. [ABSTRACT FROM AUTHOR]

The involvement of green hydrogen in energy transformation is getting global attention. This assessment examines the hydrogen production and its utilization potential in one of the hydropower-rich regions, Nepal under various demand growth and technology intervention scenarios by developing a power grid model of 52 nodes and 68 transmission lines operating at an hourly time-step. The model incorporates a grid-connected hydrogen storage system as well as charging stations for electric and hydrogen vehicles. The least-costly pathways for power grid expansion at the nodal and provincial levels are identified through optimization. The results show that 32 GW of installed capacity is required to meet domestic electricity demand and 14 GW more hydropower should be exploited to completely decarbonize the transport sector by 2050. For maintaining 50% shares of hydrogen vehicle in the transport sector and meet government electricity export targets, Nepal requires 5.7 GW, 12 GW and 23 GW of the additional electrolyzer, hydrogen storage tanks and storage-based hydropower capacities respectively. For a given electricity demand, introducing hydrogen systems can reduce the capacity requirements of hydro storage by storing surplus power generated from pondage run-of-the-river and run-of-the-river hydropower during the rainy season and using it in the dry season. • Integrated hydrogen energy storage system and charging stations within a power grid model. • 14 GW of additional hydropower plant is required to completely decarbonize the transport sector. • Huge storage-based hydropower is exploited only in export-oriented scenario. • Share of storage-based hydropower decreases with a reduction in hydrogen system cost. • Hydrogen system reduces power curtailment from pondage run-of-the-river and run-of-the-river hydropower. [ABSTRACT FROM AUTHOR]

Abstract Hydrogen as an energy carrier allows the decarbonization of transport, industry, and space heating as well as storage for intermittent renewable energy. The objective of this paper is to assess the future engineering potential for hydrogen and provide insight to areas of research to help lower economic barriers for hydrogen adoption. This assessment was accomplished by creating top-level system models based on energy requirements for end-use services. Those models were used to investigate four case studies that provide a global view augmented with specific national examples. The first case study assesses the potential penetration of hydrogen using a global energy system model. The second applies the dynamic integrated climate–ecosystem–economics model to derive an estimate of the impact of the diffusion of hydrogen as an energy carrier. The third determines the required growth in renewable power and water usage to power transportation in the United States (US) with hydrogen. The fourth assesses the use of hydrogen for heating in the United Kingdom (UK). In all cases, there appeared to be significant potential for hydrogen adoption and net energetic benefit. Globally, hydrogen has the potential to account for approximately 3% of energy consumption by 2050. In the US, using hydrogen for on-road transportation could enable a reduction in rejected energy of nearly 10%. Also, hydrogen might provide the least cost alternative to decarbonizing space heating in the UK. The research highlights a challenge raised by widespread abandonment of nuclear power. It is currently unclear what the removal of nuclear would do to the cost of energy as nations attempt to limit global greenhouse gas emissions. Nuclear power has also been proposed as a source for large scale production of hydrogen. Finally, this analysis shows that with today's technological maturity making the transition to a hydrogen economy would incur significant costs. Highlights • Explores four case studies of the societal penetration of hydrogen. • Identifies the decarbonizing benefits of hydrogen in transport and heating. • Global model identifies nation specific opportunities for hydrogen penetration. • Cost remains a significant challenge to the ushering in of the hydrogen economy. • Cost reductions in hydrogen production, storage and transmission are necessary. [ABSTRACT FROM AUTHOR]

Abstract In this study, the authors developed an Optimal Power Generation Mix model, which takes into account the supply chain of imported and domestically produced hydrogen, also modeling the intermittency of renewable energy at a 10-min resolution, and applied it to the case of Japan, to investigate quantitatively the possibility of achieving zero emission in 2050. Even if the costs of wind and solar PV decline drastically towards 2050 and the huge potentials that have been assumed in the literature are realized, the total system costs escalate significantly with very high shares of intermittent renewables. Since the use of hydrogen produced by excess electricity from renewable power generation sources can only make a slight contribution to reducing this escalation, it would be invaluable to introduce at least a significant amount of electricity generated by "zero-emission thermal power" technologies, including CO 2 -free imported hydrogen or conventional thermal power generation with carbon capture and sequestration (CCS). Nuclear power is also estimated as being effective in reducing the cost hike associated with achieving zero emissions. The results of this study could contribute to giving insights regarding global deployment of hydrogen-related technologies, as well as to presenting a frame of reference for Japan's future energy policies. Highlights • Variable renewables can contribute greatly to zero emission power in 2050 in Japan. • A very high share of them, however, could escalate the total cost to 20–30 JPY/kWh. • "Zero emission thermal" power generation is a necessity to meet the 2050 target. • Use of imported hydrogen is one possibility for zero emission thermal power. • Use of nuclear power is also an effective way to reduce the cost escalation. [ABSTRACT FROM AUTHOR]

• Estimated the cost of a zero emission power sector with 28-yearly data. • Power storage requirement is decided by the duration of "windless & sunless" periods. • A "cumulative residual load" approach can correctly estimate the storage requirement. • Use of "power to gas" technologies can reduce the total system cost significantly. • Firm capacities are required even in a case with very high renewable penetrations. In recent years, several studies have been published focusing on the economics of the power sector under the high penetration of variable renewable energy (VRE) following the rapid expansion of VRE capacities worldwide. However, detailed analyses of the fluctuations in meteorological conditions have hitherto been scarce, despite the expectation that VRE output will be significantly affected by them. To fill this gap, we investigated the economic likelihood of achieving a zero-emission power system in Japan by 2050, using multi-annual meteorological data from 1990 to 2017. We used a detailed linear programming optimization model, as well as a method that uses cumulative residual loads (CRL), which proved to be useful for estimating required energy storage capacities and for understanding the complex substitution of power generation and storage technologies. The estimated unit cost for a 100% renewable electricity system depends heavily on meteorological conditions, standing at 20.9 JPY/kWh with a standard deviation of 1.2 JPY/kWh, which declines to 18.3 JPY/kWh with a standard deviation of 0.6 JPY/kWh for a system with hydrogen storage. The calculations indicate that the required storage capacity is determined mainly by the duration of "windless and sunless" periods, or "dark doldrums", and the greatest risk under high VRE penetrations is the possibility of supply disruption during such periods. The results also highlight the considerable value of "firm capacities", such as thermal and nuclear power generation, under a high share of VRE, although it should be noted that the profitability of these capacities may differ significantly from current situations, with large VRE outputs with negligible marginal costs. [ABSTRACT FROM AUTHOR]