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Abstract Japan has faced the rapid penetration of solar PV, and specific power service areas actually experience technical difficulty in integrating massive PV into the power grids. By developing an optimal power grid model with 352 buses and 441 power transmission lines in an hourly temporal resolution through 8,760 h, this manuscript aims to analyze the optimal integration of solar PV into a bulk power transmission network in Japan and to identify the best location of PV to be installed in the grid so as to minimize total power system cost. For optimizing PV installation in Japan, computational results recommend the deployment of PV system in the area with sufficient grid capacity and higher solar radiation, because enough grid adequacy is necessary to efficiently control PV output and higher solar insolation leads to reduce required PV capacity and the associated investment cost. In order to realize optimal PV integration in Japan, policy recommendation is to institutionalize the scheme informing preferable locations of PV integration in a power grid, such as developing a PV installable map or implementing a zoning regulation of the grid connection. Highlights • A power grid model with 352 buses and 441 lines is developed to optimize PV install in Japan. • PV is optimally integrated in the area with enough grid capacity and higher solar radiation. • Optimal PV integration reduces the regional gap of wholesale electricity prices. • Policy proposal is to arrange the scheme informing preferable locations of PV integration. [ABSTRACT FROM AUTHOR]

SUMMARY After the Fukushima nuclear accident, Japanese power generation planning needs to be reassessed to reflect technical developments on both the power supply and demand sides. The Fukushima nuclear accident has complicated the position of nuclear energy in Japan's long-term power generation mix due to public acceptance and other associated issues such as nuclear waste management. There is a need for more studies concerning the peak grid integration of variable renewables such as PV and wind power, which are expected to potentially replace nuclear energy. On the power demand side, the anticipated future introduction of electric vehicles (EVs) and plug-in hybrid vehicle (PHEV) will have an impact on grid management in the electric power system. In this context, it is important to develop a computational tool to comprehensively analyze the optimal power generation mix and organize it in a consistent way. This paper develops a dynamic high time-resolution optimal power generation mix model as large-scale linear programming model with 18 million constraints and 8 million endogenous variables. It then analyzes the optimal deployment of variable renewables (VR) and EVs with the future possible nuclear scenario and CO2 regulation policy in Japan taken into consideration. In the calculated optimal solutions, EVs play an important role in integrating variable renewables and treating the imbalance in VR surplus output. [ABSTRACT FROM AUTHOR]

SUMMARY This paper evaluates the impact of an extensive introduction of electric vehicles (EVs) and plug-in hybrid vehicles (PHEVs) on the energy supply mix in Japan. Energy consumption in Japan's transport sector has been dominated by petroleum, and CO2 emissions in this sector account for 20% of Japan's CO2 emissions. Therefore, the deployment of clean energy vehicles, such as EV and PHEV, is expected to play a significant role in tackling energy security and environmental concerns. In order to assess the energy and environmental benefits of EV and PHEV, we develop an energy system model integrating an optimal power generation mix model and a vehicle penetration model, with consideration of the optimal electricity charging profile of those advanced vehicles. The calculated results suggest that massive EV penetration serves as an energy saving measure in Japan's whole energy system due to significant petroleum reductions exceeding the growth of fuel input into the power generation sector derived from significant EV and PHEV penetration. Massive EV deployment is estimated to contribute to CO2 mitigation in the energy system as well. Evaluating CO2 emissions by mileage by automobile, however, carbon emissions by mileage for EVs is almost equivalent to that of gasoline hybrid vehicles (HEVs) in the case of decommissioning of nuclear power plants, which eventually causes a higher carbon intensity of the electricity supply. [ABSTRACT FROM AUTHOR]

SUMMARY This paper investigates Japan's long-term energy outlook to 2050 taking into consideration the massive deployment of solar photovoltaic (PV) systems and wind power generation under a nuclear energy scenario. The extensive introduction of PV systems and wind power systems is expected to play an important role in enhancing electricity supply security after the Fukushima nuclear power accident, which has increased the uncertainty of the future additional construction of nuclear power plants in Japan. Against this background, we develop an integrated energy assessment model composed of both an econometric energy demand and supply model and an optimal power generation mix model. The latter model is able to explicitly analyze the impact of output fluctuations for various renewable energy sources at a detailed time resolution of 10 min on 365 consecutive days, incorporating the role of stationary battery technology. The simulation results reveal that intermittent fluctuations derived from a high penetration level of those renewables are controlled by quick load following operation by natural gas combined cycle power plants, pumped-storage hydro power, stationary battery technology, and output suppression of PV and wind power generation. The results show as well that massive penetration of renewables does not necessarily require a comparable scale of stationary battery capacity. Additionally, in the scenario, which assumes the decommissioning of nuclear power plants with a lifetime of over 40 years, the required PV capacity in 2050 amounts to more than double the PV installation potential in both buildings and abandoned farmland areas. [ABSTRACT FROM AUTHOR]

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]

The objective of this study was to evaluate the various technological options for the future development of China's electric power sector taking into consideration its environmental impact. A baseline case, four sulfur control cases, and two carbon control cases were simulated in the least-cost optimization energy model. The calculated results show that with no environmental constraints coal-fired power plants would remain China's least-cost option to satisfy its rapidly growing electricity demand in the future. Sulfur control alone in China's electric power sector would have a limited impact on the improvement of its overall generation efficiency and carbon emissions, and carbon control would bring not only significant sulfur and carbon emission mitigation but also an improvement in the overall generation efficiency and fuel switching from coal to natural gas. The low marginal costs of carbon mitigation in China's electric power sector show that future possible international cooperation with the sector on climate change issues such as the Clean Development Mechanism under the Kyoto Protocol would be cost-effective. [ABSTRACT FROM AUTHOR]

Recently, many researches aiming at the realization of high-performance and high-precision control of induction motors have been reported, and instantaneous torque control of an induction motor can be regarded as one of the most important topics in this field. In previous works, the authors developed a new method to realize instantaneous torque control of an induction motor with a voltage-source inverter, and demonstrated both its numerical simulations and experimental results. Unfortunately, the mathematically complicated derivation of the control method made it difficult to understand intuitively, and hindered us from analyzing the detailed characteristics of motor speed changes. In this paper, the authors propose a new method to realize instantaneous torque control of an induction motor, which differs from the concept of vector control. The proposed method is a two-degree-of-freedom control which considers the instantaneous torque command and secondary flux command as parameters. The analytical solution reported here is a particular solution of the differential state equation of an induction motor, and can be expressed as a simple explicit function of the instantaneous torque command, secondary flux command, and motor speed. The authors show the validity of the proposed method through numerical simulations and experimental results. This paper aims the realization of high-performance control of an induction motor. The authors propose a new method to realize instantaneous torque control without transient torque with a voltage-source inverter. © 2001 Scripta Technica, Electr Eng Jpn, 137(1): 48–56, 2001 [ABSTRACT FROM AUTHOR]

Many efforts towards a settlement of the CO2 problem have already been made through internationally organized meetings. It is not unlikely that some targets will be set for the reduction of CO2 emissions. If a stringent reduction target should be imposed on CO2 emitted from a national energy system, this cw possibly have as severe an impact upon electric power sectors as the oil price crises experienced in the seventies. It is, however, quite uncertain whether or not political muscles will be used specifically for tackling the CO2 problem in the near future. In such a context, this paper presents a new method for optimal power system planning under uncertain CO2 emissions control policies. The derived optimal expansion plan gives us the minimum expected value of the sum of the total system cost and the total amount of carbon taxes levied on net CO2 emissions from fossil fuel-fired power plants. The stochastic dynamic optimization problem discussed here is formulated as a linear programming problem decomposable into several small subproblems. The proposed method can take into account a specific future scenario of the magnitude of control policy uncertainties, which can be presumably resolved in the first half of the next century due to the increase in scientific wisdom. Ln order to evaluate the usefulness of the method proposed here, the authors also present a simple cue study with the Japanese national power system up to the year 2050. [ABSTRACT FROM AUTHOR]

This paper presents a new method for power system planning which considers uncertainties of various system parameters as a part of the criterion function. The criterion function involves both the expected values of total system costs and the cost variances of different power plants. Previously, the authors proposed that these cost variances be evaluated from the existing power system plans in the form of the solutions to the inverse optimization problem, and then applied this procedure to the planning of power systems in Japan. However, because of the correlation between fuel and facility costs, the cost variances could not be determined as specific values. Here, to overcome this difficulty, the authors now introduce hydropower plants into the model as the so-called nonrisky elements and focus on the expenditure shares rather than the plant capacity shares. As a result, more reasonable results are obtained. This improved methodology is applied and the derived cost variances are shown. Further, using the resultant cost variances, the authors make Pareto-optimal power generation plans and demonstrate also the robustness of the method to price fluctuations. [ABSTRACT FROM AUTHOR]

Although the BBIN (Bangladesh-Bhutan-India-Nepal) sub-region shares identical socio-economic characteristics and secures considerable benefits from energy co-operation and power grid connectivity, it is still far behind to grasp its full potential. This paper reviews existing publications and papers from a viewpoint of resource distribution, energy supply, prospects, and policies related to power sector development and cross-border power trading with a detailed consideration of the spatial variation of the largest country, India. The member countries face similar energy problems and the challenge remains in overcoming growing energy demand by attaining emission reduction targets. Limited production but increasing use of imported fuel have also raised serious environmental and energy security concerns. The wide variation in the energy resource endowments among the countries, particularly with hydropower, coal, and natural gas presents both opportunity and challenge in sub-regional energy collaboration. [ABSTRACT FROM AUTHOR]

This study evaluates the optimal expansion of the electricity sector of the BBIN (Bangladesh, Bhutan, India, and Nepal) sub‐region with a detailed analysis of unevenly distributed resources and electricity demand, by developing a multi‐regional dynamic power sector optimization model, characterized by 27 nodes, 45 fuel transport lines, and 63 transmission lines in hourly temporal resolution. Scenarios developed in this paper assess the impact of 2 °C Paris agreement on production, transportation, and consumption of indigenous resources like coal and gas, the share of renewables and nuclear in the power generation mix, the utilization of huge untapped hydro resources through an expansion of cross‐border transmission lines. The simulation results show that hydro, wind, nuclear, and PV will be the dominant power sources, thus reducing the current share of coal, under carbon regulation scenario. The requirements of PV exceed its estimated commercially exploitable potential in most of the nodes in the nuclear‐restricted scenario. Expanding cross‐border transmission capacity will be an effective way to exploit untapped hydro resources so that Bangladesh and India can import power from Bhutan and Nepal. Although there is a slight increase in coal demand in the future, capacity expansion of fuel networks is not economical under adopted emission levels. © 2020 Institute of Electrical Engineers of Japan. Published by Wiley Periodicals LLC. [ABSTRACT FROM AUTHOR]

SUMMARY This paper investigates the impact of an extensive introduction of electric vehicles ( EV) and plug-in hybrid vehicles ( PHEV) into the global energy system by 2050. The significant growth of automobile ownership in emerging countries is likely to increase world oil demand and the associated carbon dioxide emissions. In order to address these energy, security, and environmental concerns, the deployment of clean energy vehicles, such as EV and PHEV, is expected to play a crucial role due to their high fuel efficiency. Consequently, we develop both a global energy system model and a world vehicle penetration model, which can explicitly analyze the impact of EV introduction into the seasonal daily electric load curve, with consideration of the specific electricity charging profile through 2050. The simulation results confirm that EV deployment contributes to energy conservation, because oil demand reduction outstrips the growth in electricity demand and the associated fuel input into the power generation mix. Concerning carbon dioxide abatement, the magnitude of the impact relies on the carbon intensity of the power generation mix. If the intensity is low enough to guarantee a carbon mitigation effect due to EV fuel saving, emissions reduction is well assured. It should be noted, however, that in regions with high carbon intensity in the power generation mix, carbon emissions per mileage of EVs is almost equivalent to that of efficient gasoline vehicles such as hybrid vehicles, and the figure for PHEV is slightly higher than for hybrid vehicles. © 2013 Wiley Periodicals, Inc. Electr Eng Jpn, 186(4): 20-36, 2014; Published online in Wiley Online Library (wileyonlinelibrary.com). DOI 10.1002/eej.22373 [ABSTRACT FROM AUTHOR]

This paper analyzes Japan's optimal power generation mix considering massive deployment of solar photovoltaic ( PV) systems and wind power generation. The extensive introduction of PV systems and wind power system is expected to play an important role in addressing energy security and climate change concerns in Japan. Considering this expected large-scale deployment of PV systems in the electric power system, it is necessary to investigate the optimal power generation mix which is technologically capable of controlling and accommodating the intermittent output-power fluctuations inherent in PV and wind energy systems. Against these backgrounds, we develop an optimal power generation mix model, explicitly analyzing the impact of output fluctuation in variable renewables in the detailed resolution of time intervals like 10 minutes for 365 consecutive days, with the role of stationary battery technology incorporated. Simulation results reveal that considerable deployment of those variable renewables does not necessarily require a scale of battery capacity similar to that of the variable renewable capacity, due to quick load-following treatment by thermal power plants, pumped-storage hydropower, and battery technology over renewable output fluctuation. [ABSTRACT FROM AUTHOR]

SUMMARY In order to address climate change and energy security issues, intermittent renewable energy sources such as solar photovoltaic (PV) and wind power are gaining considerable attention. However, due to their variability and surplus electricity, the expansion of these renewables is an important challenge for power grid management. Various countermeasures such as rechargeable batteries, suppression, and back-up generators, are considered necessary for the physical integration of intermittent renewables to create an efficient and reliable power generation mix. In this context, we developed a high time-resolution optimal power generation mix model to quantitatively assess the amount of surplus electricity available under the large-scale introduction of PV and wind power in the Hokkaido region of Japan and the potential roles for the countermeasures mentioned above. The main feature of the model is the detailed time resolution at 10 min through a year. This allows us to investigate the impact of variation in various short-cycle renewables on surplus electricity and the deployment of rechargeable batteries. The simulation results suggest that if a proportion of PV and wind power expands more than around 10% and 20% of total demand respectively or if the sum of the proportion of PV and wind power exceeds 20%, the need for suppression grows rapidly. The results also suggest that rechargeable batteries are more economically compatible with PV than wind power is. [ABSTRACT FROM AUTHOR]

SUMMARY This paper evaluates the optimal power generation mix considering massive deployment of variable renewable energy and regional power interchange. Japan has initiated the feed-in-tariff (FIT) and expected the significant introduction of PV and wind power for energy self-sufficiency and climate change. However, wind power resources in Japan are concentrated mainly in Hokkaido and the Tohoku region, which are remote from electricity-consuming areas such as Tokyo, and facilitating the considerable deployment of wind power requires the establishment of inter-regional power transmission lines. Against these backgrounds, we develop an optimal power generation mix model including regional electricity exchange as a large-scale linear programming model with 10 million variables and 30 million constraints. The calculation results show that regional grid expansion encourages wind power installation in the Hokkaido and Tohoku regions for power supply to the Tokyo area, where PV power and stationary batteries are alternatively replaced. Grid expansion too promotes the shift of PV installation to the Kyushu and Shikoku regions, which have longer sunshine duration, and interchangeably mitigates PV deployment in other regions through the transport of PV power from those two regions. [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]

In germinal centers (GCs), B cells are selected through interaction with follicular dendritic cells bearing immune complexes and follicular helper T (Tfh) cells secreting Tfh cytokines, including IL-21. To analyze these cellular interactions, we have explored culture conditions that can simulate GC B cell selection in vitro using a mouse follicular dendritic cell line, FL-YB. FL-YB cells efficiently enhanced viability of cocultured mouse B cells in a BAFF-dependent fashion. Interestingly, we found that addition of IL-21, a major Tfh cytokine, readily induced death of B cells that were cocultured with FL-YB cells, whereas IL-21 alone sustained viability of B cells in the absence of FL-YB cells. The IL-21-induced death was dependent on a low m.w. soluble factor that was released from FL-YB cells, which was finally identified as PGE2. Treatment of B cells with IL-21 plus PGE2, but not either alone, resulted in enhanced expression of a proapoptotic protein Bim and the upstream transcription factor Foxo1. A PGE2 receptor isoform, EP4, was responsible for IL-21/PGE2-induced B cell death. Thus, PGE2 is an endogenous chemical mediator that can switch pleiotropic actions of IL-21 on B cells. IL-21/PGE2-induced B cell death was rescued if B cells were costimulated via CD40. In immunized mice, deficiency of IL-21R in B cells led to a significant decrease in the frequency of activated caspase-3-positive GC B cells concomitant with impaired affinity maturation of Abs. Taken together, results implicate a physiological role of IL-21/PGE2-induced B cell death in GC B cell selection. [ABSTRACT FROM AUTHOR]

In deregulated electricity markets, the role of a distribution company is to purchase electricity from the wholesale electricity market at randomly fluctuating prices and to provide it to its customers at a given fixed price. Therefore, the company has to take risk stemming from the uncertainties of electricity prices and/or demand fluctuation instead of the customers. The way to avoid the risk is to make a bilateral contract with generating companies or install its own power generation facility. This entails the necessity to develop a certain method to make an optimal strategy for electric power procurement. In such a circumstance, this research proposes a mathematical method based on stochastic dynamic programming and considers the characteristics of the start-up cost of an electric power generation facility to evaluate strategies of combination of the bilateral contract and power auto-generation with its own facility for procuring electric power in a deregulated electricity market. In the beginning we proposed two approaches to solve the stochastic dynamic programming, and they are a Monte Carlo simulation method and a finite difference method to derive the solution of a partial differential equation of the total procurement cost of electric power. Finally we discussed the influences of the prime uncertainty on optimal strategies of power procurement. © 2007 Wiley Periodicals, Inc. Electr Eng Jpn, 160(2): 20–29, 2007; Published online in Wiley InterScience (www.interscience.wiley.com). DOI 10.1002/eej.20296 [ABSTRACT FROM AUTHOR]

The player in deregulated electricity markets can be categorized into three groups of GENCO (Generator Companies), TRANSCO (Transmission Companies), and DISCO (Distribution Companies). This research focuses on the role of Distribution Companies, which purchase electricity from the market at randomly fluctuating prices, and provide it to their customers at given fixed prices. Therefore, Distribution Companies have to take the risk stemming from price fluctuation of electricity instead of the customers. This entails the necessity of developing a certain method to make an optimal strategy for electricity procurement. In such a circumstance, this research has the purpose of proposing a mathematical model based on stochastic dynamic programming to evaluate the value of a long-term bilateral contract for electricity trade, and also a project of combination of the bilateral contract and power generation with their own generators for procuring electric power in a deregulated market. © 2006 Wiley Periodicals, Inc. Electr Eng Jpn, 156(2): 32–42, 2006; Published online in Wiley InterScience (www.interscience.wiley.com). DOI 10.1002/eej.20105 [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 cost effective R&D strategy is required especially for large-scale technologies because their development demands a large amount of investment in general. A mixed integer programming model was developed for the optimum technology development strategy in the field of energy systems. The module of the technology development process in the model is based on GERT (Graphical Evaluation and Review Technique). In the module, a target technology is broken down into many elemental technologies. Usually several target technologies are involved for the evaluation of technology development strategy of one field and some of the elemental technologies are used common to a number of target technologies. Since elemental technologies are explicitly modeled, their spillover effects are necessarily evaluated in this model analysis. The proposed method was applied to the evaluation of the development strategy of four types of IGCC (Integrated coal Gasification Combined Cycle) technologies which have different levels of thermal efficiencies. The total investment on both their R&D and practical use is optimized under the constraint of meeting a certain exogenous scenario of electricity demand. The evaluation results include the optimum additional investment allocation among the developments of various elemental technologies; developments of integration technology for IGCC-43%, IGCC-55% and IGCC-48%, coal gasification technology, oxide dispersion strengthened superalloy technology for the gas turbine blade and vane, ceramic matrix composite technology for the gas turbine blade, dry sulfur-removal technology, etc. are cost-effective. [Copyright &y& Elsevier]

An on-site generator, such as CGS (cogeneration system), is considered to be an effective end-use energy system in order to accomplish primary energy conservation, CO2 emissions mitigation, and system cost reduction; these characteristics will eventually improve the complete performance of an existing energy system in the future. Considering the drawback of installing an end-use CGS for a customer possessing small or middle-scale floor space, however, it is difficult to achieve those distinctive features because the thermal-electricity ratio of CGS is not always in agreement with that of customer energy demand. In order to overcome that matching deficiency, it is better to organize an on-site generator network based on mutual electricity and heating transmission. But focusing on some cogenerators underlying their behaviors regarding maximizing their own profits, this on-site network, whose situation corresponds to a grand coalition, is not necessarily established because of each cogenerator's motivation to form a partial coalition and acquire its own profit as much as possible. In this paper, we attempt to analyze the optimal operation of an on-site generator network and identify by applying the nucleolus of cooperative game theory the optimal benefit allocation strategy in order for the cogenerators to construct the network. Regarding the installation site of this network, the center of Tokyo city is assumed; the locational information includes floor space and so forth through a GIS (geographic information system) database. The results from the nucleolus suggest that all districts should impartially obtain benefit from organizing the network for the purpose of jointly attaining system total cost reduction. © 2005 Wiley Periodicals, Inc. Electr Eng Jpn, 150(4): 23–35, 2005; Published online in Wiley InterScience (www.interscience.wiley.com). DOI 10.1002/eej.20052 [ABSTRACT FROM AUTHOR]

Carbon emissions which would cause global warming were agreed to be constrained at COP3 in Kyoto. In addition, carbon emission permits trading was also approved to be introduced. The emission permits trading is expected to achieve efficient carbon emission reduction, equalizing the marginal costs of the emission reduction for the participating countries. In other words, the permits trading allows participants to reduce emissions where it is least expensive to do so. However, the inadequate introduction of the trading systems may impose an unfairly greater burden on some countries, and therefore careful evaluation of the system would be indispensable for its implementation. In this paper, we attempt to analyze emission permits trading, using the theory of cooperative games with a global energy model of optimization type. We assume that seven world regions as players participate in the permits trading system under the condition of the emission reduction target presented at COP3 and so on, and show the nucleolus of the grand coalition games, and the computational results of primary energy supplies and CO2 shadow prices. The insights of this research indicate that in order to stabilize the grand coalition, a noticeable amount of additional transfer of money would be needed besides the payments associated with the emission permits transactions. © 2000 Scripta Technica, Electr Eng Jpn, 131(2): 40–50, 2000 [ABSTRACT FROM AUTHOR]

This research undertakes an investigation of global fuel cell vehicle (FCV) deployment, cognizant of optimal economic deployment and stakeholder preferences in a case study of Japan out to the year 2050. The model is mathematically formulated as a large‐scale linear optimization problem, aiming to minimize system costs, including generation type, fuel, conversion, and carbon reduction, subject to the constraint of carbon dioxide reduction targets. Results show that between ∼0.8 and 2% of global energy consumption needs can be met by hydrogen by 2050, with city gas and transport emerging as significant use cases. Passenger FCVs and hydrogen buses account for most of the hydrogen‐based transportation sector, leading to a global deployment of ∼120 million FCVs by 2050. Hydrogen production is reliant on fossil fuels, and OECD nations are net importers – especially Japan. To underpin hydrogen production from fossil fuels, carbon capture and storage is required in significant quantities when anticipating a large fleet of FCVs. Stakeholder engagement suggests optimism toward FCV deployment while policy issues identified include the necessity for large‐scale future energy system investment and rapid technical and economic feasibility progress for renewables and electrolysers to achieve a hydrogen economy which is not reliant on fossil fuels. [ABSTRACT FROM AUTHOR]

This paper presents a new modeling approach to incorporate operational characteristics of different types of hydropower in long-term power sector models. The existing literature and methods were reviewed, and the mathematical formulation of the developed model is presented. The model is then used to analyze the future power generation mix of Nepal, a country with huge untapped hydro resources, as a case study. The possible power sector development pathway has been assessed through three different electricity demand growth rate scenarios. The optimal deployment of indigenous hydro and renewables is further evaluated by developing zero-emission scenarios as a conceivable policy to strengthen national energy security. The sensitivity analysis of governing parameters and evaluation of simulation results was performed to validate the model. Simulation results for capacity and generation mix along with emission level and total power system costs have been discussed for each scenario. Power dispatch and operation schedule determined as a result of optimization take account of the seasonal variations of river inflow and operational benefits of hydropower. Sensitivity analysis is carried out to examine the impact of construction cost, availability factor and water storage capacity on total cost, capacity requirements and optimal operation of hydropower. • Represented different types of hydropower in dynamic power sector model. • Detailed analysis of the future power generation mix of Nepal. • Optimized the operation schedule and water storage strategy of hydro Pondage run-of-the-river and hydro storage. [ABSTRACT FROM AUTHOR]

Decarbonization of the energy system is a key goal of the Paris Agreements, in order to limit temperature rises to under 2° Celsius. Hydrogen has the potential to play a key role through its versatile production methods, end uses and as a storage medium for renewable energy, engendering the future low-carbon energy system. This research uses a global model cognizant of energy policy, technology learning curves and international carbon reduction targets to optimize the future energy system in terms of cost and carbon emissions to the year 2050. Exploring combinations of four exploratory scenarios incorporating hydrogen city gas blend levels, nuclear restrictions, regional emission reduction obligations and carbon capture and storage deployment timelines, it was identified that hydrogen has the potential to supply approximately two percent of global energy needs by 2050. Irrespective of the quantity of hydrogen produced, the transport sector and passenger fuel cell vehicles are consistently a preferential end use for future hydrogen across regions and modeled scenarios. In addition to the potential contribution of hydrogen, a shift toward renewable energy and a significant role for carbon capture and storage is identified to underpin carbon target achievement by 2050. • Global linear optimization model of hydrogens role in the future energy system. • Cognizant of policy, technology learning curves and carbon targets. • Hydrogen is estimated to account for approximately 2% of energy needs by 2050. • Hydrogen to play a prominent role in the transportation sector. • Perverse incentives of different carbon reduction goals investigated. [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 Japan is the sixth largest greenhouse gas emitter in 2016 and plays an important role to attain the long-term climate goals of the Paris Agreement. One of the key policy issues in Japan's energy and environmental policy arena is the energy system transition to achieve 80% emissions reduction in 2050, a current policy goal set in 2016. To contribute to the ongoing policy debate, this paper focuses on energy-related CO 2 emissions and analyzes such decarbonization scenarios that are consistent with the government goals. We employ six energy-economic and integrated assessment models to reveal decarbonization challenges in the energy system. The modeling results show that Japan's mitigation scenarios are characterized by high marginal costs of abatement. They also suggest that the industrial sector is likely to have a large final energy share and significant residual emissions under the 80% reduction scenario, though it is generally thought that the transport sector would have large decarbonization challenges. The present findings imply that not only energy policy but also industrial policy may be relevant to the long-term environmental target. Given the high marginal costs exceeding those of negative emissions technologies that could place a cost ceiling, further model development would be crucial. Highlights • We analyze the energy system scenarios to achieve 80% reduction in carbon dioxide emissions by 2050. • We employ six integrated assessment models to reveal decarbonization challenges in the energy system. • The model results show that the industrial sector has a large final energy share and significant residual carbon dioxide emissions under the 80% reduction scenario. • We also show that Japan's mitigation scenarios are accompanied with high marginal costs of abatement. [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]

Climate change significantly impacts hydrological systems resulting in hydropower generation uncertainties. In this study, a high-resolution glacio-hydrological model is coupled with an hourly-resolution power grid model to evaluate the climate change influences on hydropower generation across Nepal. Four climate future scenarios namely Cold-Dry, Warm-Dry, Cold-Wet, and Warm-Wet are developed to compare the changes in water availability and optimal power system with historical climate. The total flow increases for the wet scenarios (+11.4% under Cold-Wet for the Koshi basin), compared to the dry scenarios (−24.6% under Warm-Dry for the Karnali basin) for all the major river basins in Nepal. The results illustrate the distribution and magnitude of changes in total water availability and power generation are not proportional for dry and wet scenarios as a ∼20% reduction of water availability in the dry scenarios only results in a ∼2–3% decrease in electricity generation. The capacity requirements of hydro storage decrease by 7.2 GW for Cold-Wet and 6.8 GW for Warm-Wet scenarios compared to historical climate indicating higher capacity requirements in dry scenarios. Larger impacts observed at higher altitudes suggest more attentive adaptation strategies in developing climate-resilient hydropower systems. Results suggest that Nepal should not be entirely focused on exploiting its hydropower potential but rather diversifying the generation mix including solar PV and hydrogen technology. For the least-cost power system expansion, the Warm-Wet climate appears to be the most desirable and a cost savings of about 3.76 billion USD in hydropower development can be realized if better adaptation strategies are employed. [Display omitted] • Climate change impacts on hydro-dominated power systems in a high-mountain country. • Coupling of glacio-hydrological model and a high spatial-temporal power grid model. • Adaptation strategies for surplus electricity management are more critical in wet scenarios. • Storage hydro capacity needs drop by 7.2 in Cold-Wet & 6.8 GW in Warm-Wet scenarios. • Employing adaptation strategies results in cost savings of about 3.76 billion USD. [ABSTRACT FROM AUTHOR]

This paper presents an evaluation of the impact of extensive introduction of photovoltaic (PV) systems and stationary battery technology into the optimal power gen-eration mix in the Kanto and Kinki regions. The introduc-tion of solar PV systems is expected to be extensively deployed in the Japanese household sector and utility com-panies in order to address the concerns of energy security and climate change. Considering this expected large-scale deployment of PV systems in electric power systems, it is necessary to investigate the optimal power generation mix which is technologically capable of controlling and accom-modating the intermittent output-power fluctuations inher-ent in PV systems. Against this background, we develop both a solar photovoltaic power generation model and an optimal power generation mix model, including stationary battery technology, which can be used to explicitly analyze the impact of PV output fluctuations at a detailed time interval resolution such as 10 minutes for 365 consecutive days. Simulation results reveal that PV introduction does not necessarily increase battery technology due to the cost competitiveness of thermal power plants in the load-follow-ing requirement caused by PV systems. Additionally, on the basis of sensitivity analysis on PV system cost, dramatic cost reduction proves to be indispensable for PV to supply bulk electricity similarly to thermal and nuclear power plants. © 2012 Wiley Periodicals, Inc. Electr Eng Jpn, 182(2): 9-19, 2013; Published online in Wiley Online Library (wileyonlinelibrary.com). [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]