Performance analysis of various hybrid renewable energy systems using battery,hydrogen, and pumped hydro‐based storage units

The aim of this research is to analyze the techno‐economic performance of hybrid renewable energy system (HRES) using batteries, pumped hydro‐based, and hydrogen‐based storage units at Sharurah, Saudi Arabia. The simulations and optimization process are carried out for nine HRES scenarios to determine the optimum sizes of components for each scenario. The optimal sizing of components for each HRES scenario is determined based on the net present cost (NPC) optimization criterion. All of the nine optimized HRES scenarios are then evaluated based on NPC, levelized cost of energy, payback period, CO₂ emissions, excess electricity, and renewable energy fraction. The simulation results show that the photovoltaic (PV)‐diesel‐battery scenario is economically the most viable system with the NPC of US$2.70 million and levelized cost of energy of US$0.178/kWh. Conversely, PV‐diesel‐fuel cell system is proved to be economically the least feasible system. Moreover, the wind‐diesel‐fuel cell is the most economical scenario in the hydrogen‐based storage category. PV‐wind‐diesel‐pumped hydro scenario has the highest renewable energy fraction of 89.8%. PV‐wind‐diesel‐pumped hydro scenario is the most environment‐friendly system, with an 89% reduction in CO₂ emissions compared with the base‐case diesel only scenario. Overall, the systems with battery and pumped hydro storage options have shown better techno‐economic performance compared with the systems with hydrogen‐based storage.     

Co-benefit analysis of incentives for energy generation and storage systems; a multi-stakeholder perspective

In this work, we are analyzing the advantages of energy incentives for all the stakeholders in an energy system. The stakeholders include the government, the energy hub operator, and the energy consumer. Two streams of energy incentives were compared in this work: incentives for renewable energy generation technologies and incentives for energy storage technologies. The first type aims increasing the share of renewable energies in the electricity system while the second type aims development of systems which use clean electricity to replace fossil fuels in other sectors of an energy system such as the transportation, residential and industrial sector. In this work, we are analyzing the advantages of energy incentives for all the stakeholders in an energy system. The stakeholders include the government, the energy hub operator, and the energy consumer. Two streams of energy incentives were compared in this work: incentives for renewable energy generation technologies and incentives for energy storage technologies. The first type aims to increase the share of renewable energies in the electricity system while the second type aims the development of systems which use clean electricity to replace fossil fuels in other sectors of an energy system such as the transportation, residential and industrial sector. The results of the analysis showed that replacing fossil fuel-based electricity generation with wind and solar power is a less expensive way for the energy consumer to reduce GHG emissions (60 and 92 CAD/ tonne CO_2e for wind and solar, respectively) compared to investing on energy storage technologies (225 and 317 CAD/ tonne CO_2e for Power-to-Gas and battery powered forklifts, respectively). However, considering the current Ontario's electricity mix, incentives for the Power-to-Gas and battery powered technologies are less expensive ways to reduce emissions compared to replacing the grid with wind and solar power technologies (1479 and 2418 CAD/ tonne CO_2e for wind and solar, respectively). Our analysis also shows that battery storage and hydrogen storage are complementary technologies for reducing GHG emissions in Ontario.     

Design and optimum energy management of a hybrid renewable energy system based on efficient various hydrogen production

Utilizing renewable energy resources is one of the convenient ways to reduce greenhouse gas emissions. However, the intermittent nature of these resources has led to stochastic characteristics in the generation and load balancing of the microgrid systems. To handle these issues, an energy management optimization for microgrids operation should be done to urge the minimization of total system costs, emissions, and fuel consumption. An optimization program for decreasing the operational cost of a hybrid microgrid consisting of photovoltaic array, wind unit, electrolyzer, hydrogen storage system, reformer, and fuel cell is presented. Two different methods of producing hydrogen are considered in this study to ensure the effectiveness of the developed methodology. In the microgrid system with high penetration of renewable energy resources, using storage technologies to compensate for the intermittency of these resources is necessary. To evaluate the functioning of the microgrid system, a mathematical model for each source is developed to coordinate the system operation involving energy conversion between hydrogen and electricity. Particle Swarm Optimization Algorithm is utilized to determine the optimum size and operational energy management within the system. It is evident from the results that there is about a 10% reduction in the amount of CH₄ consumption in reformer when the electrolyzer was employed in the system. It is observed that the CH₄ reduction in summer and fall is higher than other seasons (10.6% and 11.5%, respectively). The reason is that the highest RES production occurs in these seasons during a year. It is also worth mentioning that the electrolyzer technology would play a significant role in decreasing the CH₄ consumption in the microgrid system.     

Five-year technology selection optimization to achieve specific CO2 emission reduction targets

Long-term planning for replacement of fossil fuel energy technologies with renewables is of great importance for achieving GHG emission reduction targets. The current study is focused on developing a five-year mathematical model for finding the optimal sizing of renewable energy technologies for achieving certain CO₂ emission reduction targets. A manufacturing industrial facility which uses CHP for electricity generation and natural gas for heating is considered as the base case in this work. Different renewable energy technologies are developed each year to achieve a 4.53% annual CO₂ emission reduction target. The results of this study show that wind power is the most cost-effective technology for reducing emissions in the first and second year with a cost of 44 and 69 CAD per tonne of CO₂, respectively. Hydrogen, on the other hand, is more cost-effective than wind power in reducing CO₂ emissions from the third year on. The cost of CO₂ emission reduction with hydrogen doesn't change drastically from the first year to the fifth year (107 and 130 CAD per tonne of CO₂). Solar power is a more expensive technology than wind power for reducing CO₂ emissions in all years due to lower capacity factor (in Ontario), more intermittency (requiring mores storage capacity), and higher investment cost. A hybrid wind/battery/hydrogen energy system has the lowest emission reduction cost over five years. The emission reduction cost of such hybrid system increases from 44 CAD per tonne of CO₂ in the first year to 156 CAD per tonne of CO₂ in the fifth year. The developed model can be used for long-term planning of energy systems for achieving GHG emission targets in a regions/country which has fossil fuel-based electricity and heat generation infrastructure.     

Multi-objective optimization model for sustainable Indonesian electricity system: Analysis of economic,environment, and adequacy of energy sources

This paper presents a multi-objective optimization model for a long-term generation mix in Indonesia. The objective of this work is to assess the economic, environment, and adequacy of local energy sources. The model includes two competing objective functions to seek the lowest cost of generation and the lowest CO₂ emissions while considering technology diffusion. The scenarios include the use of fossil reserves with or without the constraints of the reserve to production ratio and exports. The results indicate that Indonesia should develop all renewable energy and requires imported coal and natural gas. If all fossil resources were upgraded to reserves, electricity demand in 2050 could be met by domestic energy sources. The maximum share of renewable energy that can be achieved in 2050 is 33% with and 80% without technology diffusion. The least cost optimization produces lower generation costs than the least CO₂ emissions, as well as the combined scenario. Total CO₂ emissions in 2050 are five to six times as large as current emissions. The least CO₂ emissions scenario can reduce almost half of the CO₂ emissions of the least cost scenario by 2050. The proposed multi-objective optimization model leads some optimal solutions for a more sustainable electricity system.     

Thermodynamic analysis of a novel energy storage system based on compressed CO2 fluid

Because of rapidly growing renewable power capacity, energy storage system is in urgent need to cope with the reliability and stability challenges. CO₂ has already been selected as the working fluid, including thermo‐electrical energy storage or electrothermal energy storage systems and compressed CO₂ energy storage (CCES) systems. In this paper, a CCES system based on Brayton cycle with hot water as the heat storage medium is proposed and analyzed. Thermodynamic model of the system is established for energy and exergy analysis. Sensitivity analysis is then conducted to reveal effects of different parameters on system performances and pursue optimization potential. At a typical transcritical operation condition, round trip efficiency is 60% with energy density of 2.6 kWh/m³. And for the typical supercritical operation condition, the round trip efficiency can reach 71% with energy density of 23 kWh/m³. High round trip efficiency and energy density, which is comparable with those of compressed air energy storage systems, thermo‐electrical energy storage (electrothermal energy storage) systems, and other CCES systems, lead to promising prospect of the proposed system. Copyright © 2017 John Wiley & Sons, Ltd.     

Impact of electric vehicles on a future renewable energy‐based power system in Europe with a focus on Germany

Electric mobility is expected to play a key role in the decarbonisation of the energy system. Continued development of battery electric vehicles is fundamental to achieving major reductions in the consumption of fossil fuels and of CO₂ emissions in the transport sector. Hydrogen can become an important complementary synthetic fuel providing electric vehicles with longer ranges. However, the environmental benefit of electric vehicles is significant only if their additional electricity consumption is covered by power production from renewable energy sources. Analysing the implications of different scenarios of electric vehicles and renewable power generation considering their spatial and temporal characteristics, we investigate possible effects of electric mobility on the future power system in Germany and Europe. The time horizon of the scenario study is 2050. The approach is based on power system modelling that includes interchange of electricity between European regions, which allows assessing long‐term structural effects in energy systems with over 80% of renewable power generation. The study exhibits strong potential of controlled charging and flexible hydrogen production infrastructure to avoid peak demand increases and to reduce the curtailment of renewable power resulting in reduced system operation, generation, and network expansion costs. A charging strategy that is optimised from a systems perspective avoids in our scenarios 3.5 to 4.5 GW of the residual peak load in Germany and leads to efficiency gains of 10% of the electricity demand of plug‐in electric vehicles compared with uncontrolled loading.     

Application,comparative study,and multi-objective optimization of a hydrogen liquefaction system utilizing either ORC or an absorption power cycle

Environmental degradation and global warming are presently two of the most pressing global concerns. According to the (IAE), around 80% of global energy demand has been met by fossil fuels in recent years, resulting in an increase in CO₂ emissions as the primary greenhouse gas. Switching to renewable energy sources and using more energy-efficient energy systems are vital for mitigating environmental challenges and reducing our reliance on fossil fuels, among other things. Hydrogen fuels are primary renewable resources because of their reduced cost and ability to produce net-zero CO₂ emissions. In the present study, a system is designed to generate power and liquid hydrogen from geothermal sources. The generated power by employing either the organic Rankin cycle (ORC) or absorption power cycle (APC) is compared to seek the best cycle performance from power generation standpoint. A comprehensive thermodynamic and economic modeling is carried out for the proposed system. In addition, a parametric study is applied to see which parameters affect the performance of the system. Multi-objective optimization is carried out to find the best operating point of the hydrogen liquefaction energy system. The system demonstrates better performance when APC is applied for power generation. The cost of generated liquid hydrogen by ORC and APC is 3.8 $/kg.LH₂ and 3.6 $/kg.LH₂, respectively. Furthermore, 0.014 $/kWh of electricity cost is reached by ORC compared to 0.012 $/kWh of APC. Parametric analysis shows that the higher the temperature and flow rate of the brine of geothermal fluid, the higher the efficiency and the lower cost. Finally, the multi-objective optimization pinpoints that the system's efficiency and unit product cost at the optimal ORC-based design is 33.85% and 0.0121 $/kWh. In comparison, the APC demonstrates better performance by 34.5% and 0.011 $/kWh.     

Increasing RES penetration through H2 technologies on Flores island,Azores: A techno-economic analysis

On Flores island (Azores, Portugal), energy production depends up to 47% on fossil fuels, namely Diesel. To minimize CO₂ emissions, the dependency on fuel prices, and to mitigate the consequences of variability and intermittency of renewable energy sources, a new energy system, based on H₂ storage was analysed. To achieve the optimal size of the system, a computer model was developed and a multi-objective genetic algorithm function was used to minimize three objectives: the difference of levelised cost of energy (△LCOE), CO₂ emissions and the percentage of renewable energy dumped (R_{RES, dump}). From the set of solutions obtained, one that meets R_{RES, dump} ≤ 1%, lowest CO₂ emissions and lowest △LCOE is chosen and an economical and energetic analysis is performed. The newly proposed system reduces Diesel consumption by 68,7% (1057487 L/year) and CO₂ emissions by 65,9% (2455,1 CO₂ tons/year) achieving a renewable energy sources (RES) penetration of 89% (36% increase), but fails to decrease the levelised cost of energy (56,62 €/MWh increase). However, a way to make the project viable through financial support is presented and an alternative to reduce the levelised cost of energy by commercialising the products of electrolysis, hydrogen and oxygen, is proposed. Finally, it is expected that with further research and development of H₂ technologies, economic and energetic results will get more advantageous, opening up new perspectives for the future.     

Optimization of the design of polygeneration systems for the residential sector under different self-consumption regulations

Polygeneration systems enable natural resources to be exploited efficiently, decreasing CO₂ emissions and achieving economic savings relative to the conventional separate production. However, their economic feasibility depends on the legal framework. Preliminary design of polygeneration systems for the residential sector based on the last Spanish self-consumption regulations RD 900/2015 and RD 244/2019 was carried out in Zaragoza, Spain. Both regulations were applied to individual and collective installations. Several technologies, appropriate for the energy supply to residential buildings, for example, photovoltaics, wind turbines, solar thermal collectors, microcogeneration engines, heat pump, gas boiler, absorption chiller, and thermal and electric energy storage were considered candidate technologies for the polygeneration system. A mixed integer linear programming model was developed to minimize the total annual cost of polygeneration systems. Scenarios with and without electricity sale were considered. CO₂ emissions were also calculated to estimate the environmental impact. Results show that RD 900/2015 discourages the investment in self-consumption systems whereas the RD 244/2019 encourages them, especially in renewable energy technologies. Moreover, in economic terms, it is more profitable to invest in collective self-consumption installations over individual installations. However, this does not necessarily represent a significant reduction of CO₂ emissions with respect to individual installations since the natural gas consumption tends to increase as its unit price decreases because of the increase of its consumption level. Thus, more appropriate pricing of natural gas in residential sector, in which its cost would not be reduced when increasing its consumption, would be required to achieve significant CO₂ emissions reduction. In all cases, the photovoltaic panels (PV) are competitive and profitable without subsidies in self-consumption schemes and the reversible heat pump (HP) played an important role for the CO₂ emissions reduction. In a horizon to achieve zero CO₂ emissions, the net metering scheme could be an interesting and profitable alternative to be considered.     

On the design and optimization of distributed energy resources for sustainable grid-integrated microgrid in Ethiopia

This paper presents a study that focuses on alleviating the impacts of grid outages in Ethiopia. To deal with grid outages, most industrial customers utilize backup diesel generators (DG) which are environmentally unfriendly and economically not viable. Grid-integration of hybrid renewable energy systems (HRES) might be a possible solution to enhance grid reliability and reduce environmental and economic impacts of utilizing DG. In this study, an optimization of grid integrated HRES is carried out for different dispatch and control strategies. The optimal power supply option is determined by performing comparative analysis of the different configurations of grid integrated HRES. The result of the study shows that grid integrated HRES consisting of photovoltaic and wind turbine as renewable energy sources, and battery and hydrogen as hybrid energy storage systems is found to be the optimal system to supply the load demand. From the hydrogen produced on-site, the FC generator and FCEVs consume 143 620 kg/yr of hydrogen which is equivalent to 394 955 kg/yr gasoline fuel consumption. This corresponds to saving 1 184 865 kg/yr of CO₂ emissions and 605 703 $/yr revenue. Besides, this system yields 547 035.4 $/yr revenue by injecting excess electricity to the grid. The study clearly shows the economic and environmental viability of this new technology for implementation.     

Prospects and challenges for green hydrogen production and utilization in the Philippines

The Philippines is exploring different alternative sources of energy to make the country less dependent on imported fossil fuels and to reduce significantly the country's CO₂ emissions. Given the abundance of renewable energy potential in the country, green hydrogen from renewables is a promising fuel because it can be utilized as an energy carrier and can provide a source of clean and sustainable energy with no emissions. This paper aims to review the prospects and challenges for the potential use of green hydrogen in several production and utilization pathways in the Philippines. The study identified green hydrogen production routes from available renewable energy sources in the country, including geothermal, hydropower, wind, solar, biomass, and ocean. Opportunities for several utilization pathways include transportation, industry, utility, and energy storage. From the analysis, this study proposes a roadmap for a green hydrogen economy in the country by 2050, divided into three phases: I–green hydrogen as industrial feedstock, II–green hydrogen as fuel cell technology, and III–commercialization of green hydrogen. On the other hand, the analysis identified several challenges, including technical, economic, and social aspects, as well as the corresponding policy implications for the realization of a green hydrogen economy that can be applied in the Philippines and other developing countries.     

Synergistic planning of an integrated energy system containing hydrogen storage with the coupled use of electric-thermal energy

Regional integrated energy systems (RIES) can economically and efficiently use regional renewable energy resources, of which energy storage is an important means to solve the uncertainty of renewable energy output, but traditional electrochemical energy storage is only single electrical energy storage, and the energy efficiency level is low. Hydrogen energy storage has the advantages of large energy storage capacity, long storage time, clean and pollution-free, and can realize the synergistic and efficient utilization of electricity and thermal power. Based on this, this paper proposes a synergistic planning method for an integrated energy system with hydrogen storage taking into account the coupled use of electric-thermal energy, which effectively reduces the system carbon emission and improves the comprehensive energy efficiency level. Firstly, this paper constructs an electric-thermal coupling model of the hydrogen energy storage unit and proposes an optimization strategy for the integrated energy system containing hydrogen storage taking into account the utilization of electricity and thermal power. Secondly, a planning optimization model with the lowest economy and carbon emission and the highest comprehensive energy efficiency was constructed. Third, the CSPO-GE optimization algorithm is proposed for solving the problem, which significantly improves the solution efficiency. Finally, a planning optimization simulation of RIES for a residential community W in northern China verifies the effectiveness of the model and method proposed in this paper. The comparative analysis of the three schemes shows that compared with the integrated energy system with conventional electrochemical energy storage and heat storage tank as the main form of energy storage and the integrated energy system with only hydrogen storage, the integrated energy system with hydrogen storage and heat storage tank can reduce carbon emissions by 43.8% and 7.61%, respectively, and improve the integrated energy efficiency level by 337.14% and 14.44%.     

Exploring the competitiveness of hydrogen-fueled gas turbines in future energy systems

Hydrogen is currently receiving attention as a possible cross-sectoral energy carrier with the potential to enable emission reductions in several sectors, including hard-to-abate sectors. In this work, a techno-economic optimization model is used to evaluate the competitiveness of time-shifting of electricity generation using electrolyzers, hydrogen storage and gas turbines fueled with hydrogen as part of the transition from the current electricity system to future electricity systems in Years 2030, 2040 and 2050. The model incorporates an emissions cap to ensure a gradual decline in carbon dioxide (CO₂) levels, targeting near-zero CO₂ emissions by Year 2050, and this includes 15 European countries.The results show that hydrogen gas turbines have an important role to play in shifting electricity generation and providing capacity when carbon emissions are constrained to very low levels in Year 2050. The level of competitiveness is, however, considerably lower in energy systems that still allow significant levels of CO₂ emissions, e.g., in Year 2030. For Years 2040 and 2050, the results indicate investments mainly in gas turbines that are partly fueled with hydrogen, with 30–77 vol.-% hydrogen in biogas, although some investments in exclusively hydrogen-fueled gas turbines are also envisioned. Both open cycle and combined cycle gas turbines (CCGT) receive investments, and the operational patterns show that also CCGTs have a frequent cyclical operation, whereby most of the start-stop cycles are less than 20 h in duration.     

On capital utilization in the hydrogen economy: The quest to minimize idle capacity in renewables-rich energy systems

The hydrogen economy is currently experiencing a surge in attention, partly due to the possibility of absorbing variable renewable energy (VRE) production peaks through electrolysis. A fundamental challenge with this approach is low utilization rates of various parts of the integrated electricity-hydrogen system. To assess the importance of capacity utilization, this paper introduces a novel stylized numerical energy system model incorporating the major elements of electricity and hydrogen generation, transmission and storage, including both “green” hydrogen from electrolysis and “blue” hydrogen from natural gas reforming with CO₂ capture and storage (CCS). Concurrent optimization of all major system elements revealed that balancing VRE with electrolysis involves substantial additional costs beyond reduced electrolyzer capacity factors. Depending on the location of electrolyzers, greater capital expenditures are also required for hydrogen pipelines and storage infrastructure (to handle intermittent hydrogen production) or electricity transmission networks (to transmit VRE peaks to electrolyzers). Blue hydrogen scenarios face similar constraints. High VRE shares impose low utilization rates of CO₂ capture, transport and storage infrastructure for conventional CCS, and of hydrogen transmission and storage infrastructure for a novel process (gas switching reforming) that enables flexible power and hydrogen production. In conclusion, all major system elements must be considered to accurately reflect the costs of using hydrogen to integrate higher VRE shares.     

Improving the technical, environmental and social performance of wind energy systems using biomass-based energy storage

A completely renewable baseload electricity generation system is proposed by combining wind energy, compressed air energy storage, and biomass gasification. This system can eliminate problems associated with wind intermittency and provide a source of electrical energy functionally equivalent to a large fossil or nuclear power plant. Compressed air energy storage (CAES) can be economically deployed in the Midwestern US, an area with significant low-cost wind resources. CAES systems require a combustible fuel, typically natural gas, which results in fuel price risk and greenhouse gas emissions. Replacing natural gas with synfuel derived from biomass gasification eliminates the use of fossil fuels, virtually eliminating net CO₂ emissions from the system. In addition, by deriving energy completely from farm sources, this type of system may reduce some opposition to long distance transmission lines in rural areas, which may be an obstacle to large-scale wind deployment.     

Battery control for leveling the amount of electricity purchase in smart‐energy houses

An optimal operation method in smart‐energy houses with photovoltaics (PV) and a storage battery was investigated in a trial production system. In this method, the inverse current of the PV output is not conveyed to the commercial electricity system as operation conditions. Instead, the excess of the consumed PV power is applied to leveling the electricity purchase by appropriately charging and discharging the storage battery. To validate the proposed system, a lithium battery (4 kWh) and PV cell (3 kW) used in average individual houses was installed in a smart‐energy house in a local city (Kitami) in Japan. Another example was introduced into a wider area (Hokkaido, Japan). Accounting for the error between the weather forecast and actual solar radiation, the trial production system reduced the range in the electricity purchase amount by 75.0%, 77.0%, and 73.0% on a representative day in January, April, and July, respectively. The accuracy of the reduction effect in the trial production system, obtained in the proposed optimization analysis, ranged from 1.9% to 7.2%. Moreover, the CO₂ emissions were reduced by 1.990 kg‐CO₂/(Day‐House) in January, 2.910 kg‐CO₂/(Day‐House) in April, and 2.210 kg‐CO₂/(Day‐House) in July.     

CO2 savings of ground source heat pump systems – A regional analysis

In the current study the savings of CO₂ emissions due to the use of ground source heat pump (GSHP) systems was investigated in comparison to conventional heating systems. Based on a subsidy program for GSHP systems in southwest Germany, the regional, average, and total CO₂ savings of 1105 installed GSHP systems were determined on a regional scale. The emitted CO₂ per kWh of heating demand for the studied scenario resulted in 149 g CO₂/kWh for GSHP using the German electricity mix and 65 g CO₂/kWh using the regional electricity mix, which results in CO₂ savings of 35% or 72%, respectively. Similar CO₂ avoidances of GSHP systems were found in American and European studies ranging between 15% and 77% strongly depending on the supplied energy for the heat pumps and the efficiency of installation. The resulting CO₂ savings for one installed GSHP unit in the present study therefore range between 1800 and 4000 kg per year. Nevertheless, the minimum average total annual CO₂ savings of all installed GSHP systems due to the subsidy program amounted to 2000 tons per year. The maximum regional avoided additional CO₂ emissions are primarily associated with the affluent suburbs of the most densely populated area in the region. In 2006 the total contribution of CO₂ savings due to GSHP systems in Germany was only about 3.4% of the total renewable energies. However, continuously rising numbers of installed GSHP units and the increasing use of renewable electricity demonstrate that there is a fine opportunity to substantially avoid additional CO₂ emissions associated with the provision of heating (and cooling) of buildings and other facilities.     

Options for net zero emissions hydrogen from Victorian lignite. Part 1: Gaseous and liquefied hydrogen

This two-part paper investigates the feasibility of producing export quantities (770 t/d) of blue hydrogen meeting international standards, by gasification of Victorian lignite plus carbon capture and storage (CCS). The study involves a detailed Aspen Plus simulation analysis of the entire production process, taking into account fugitive methane emissions during lignite mining. Part 1 focusses on the resources, energy requirements and greenhouse gas emissions associated with production of gaseous and liquefied hydrogen, while Part 2 focusses on production of ammonia as a hydrogen carrier.In this study, the proposed process comprises lignite mining, lignite drying and milling, air separation unit (ASU), dry-feed entrained flow gasification, gas cooling and cleaning, sour water-gas shift reaction, acid gas removal, pressure swing adsorption (PSA) for hydrogen purification, elemental sulphur recovery, CO₂ compression for transport and injection, hydrogen liquefaction, steam and gas turbines to generate all process power, plus an optional post-combustion CO₂ capture step. High grade waste heat is utilised for process heat and power generation. Three alternative process scenarios are investigated as options to reduce resource utilisation and greenhouse gas emissions: replacing the gas turbine with renewable energy from off-site wind turbines, and co-gasification of lignite with either biomass or biochar. In each case, the specific net greenhouse gas intensity is estimated and compared to the EU Taxonomy specification for sustainable hydrogen.This is the first time that a coal-to-hydrogen study has quantified the greenhouse gas emissions across the entire production chain, including upstream fugitive methane emissions. It is found that both gaseous and liquefied hydrogen can be produced from Victorian lignite, along with all necessary electricity, with specific emissions intensity (SEI) of 2.70 kg CO₂-e/kg H₂ and 2.73 kg CO₂-e/kg H₂, respectively. These values conform to the EU Taxonomy limit of 3.0 kg CO₂-e/kg H₂. This result is achieved using a Selexol™ plant for CO₂ capture, operating at 89.5%–91.7% overall capture efficiency. Importantly, the very low fugitive methane emissions associated with Victorian lignite mining is crucial to the low SEI of the process, making this is a critical advantage over the alternative natural gas or black coal processes.This study shows that there are technical options available to further reduce the SEI to meet tightening emissions targets. An additional post-combustion MDEA CO₂ capture unit can be added to increase the capture efficiency to 99.0%–99.2% and reduce the SEI to 0.3 kg CO₂-e/kg H₂. Emissions intensity can be further reduced by utilising renewable energy rather than co-production of electricity on site. Net zero emissions can then be achieved by co-gasification with ≤1.4 dry wt.% biomass, while a higher proportion of biomass would achieve net-negative emissions. Thus, options exist for production of blue hydrogen from Victorian lignite consistent with a ‘net zero by 2050’ target.     

Life cycle CO2 emissions from power generation using hydrogen energy carriers

Hydrogen energy carriers such as liquid hydrogen (LH₂), methylcyclohexane (MCH), and ammonia (NH₃) are promising energy vectors in the clean energy systems currently being developed. However, their effectiveness in mitigating environmental emissions must be assessed by life cycle analyses throughout the supply chain. In this study, while focusing on hydrogen energy carriers, life cycle inventory analyses were conducted to estimate CO₂ emissions from the following types of power generation plants in Japan: a hydrogen (H₂) mono-firing power plant using LH₂ or MCH that originated from overseas renewable electricity; and NH₃ co-firing with fossil fuel and NH₃ mono-firing power plants using hydrogen energy carriers that originated from overseas natural gas or renewable electricity. Parameters related to the supply chains were collected by literature surveys, and the Japanese life cycle inventory database was primarily used to calculate the emissions. From the results, CO₂ hotspots of the target supply chains and potential measures are identified that become necessary to establish low-carbon supply chains.