Hydrogen production from wind energy in Western Canada for upgrading bitumen from oil sands

Hydrogen is produced via steam methane reforming (SMR) for bitumen upgrading which results in significant greenhouse gas (GHG) emissions. Wind energy based hydrogen can reduce the GHG footprint of the bitumen upgrading industry. This paper is aimed at developing a detailed data-intensive techno-economic model for assessment of hydrogen production from wind energy via the electrolysis of water. The proposed wind/hydrogen plant is based on an expansion of an existing wind farm with unit wind turbine size of 1.8 MW and with a dual functionality of hydrogen production and electricity generation. An electrolyser size of 240 kW (50 Nm³ H₂/h) and 360 kW (90 Nm³ H₂/h) proved to be the optimal sizes for constant and variable flow rate electrolysers, respectively. The electrolyser sizes aforementioned yielded a minimum hydrogen production price at base case conditions of $10.15/kg H₂ and $7.55/kg H₂. The inclusion of a Feed-in-Tariff (FIT) of $0.13/kWh renders the production price of hydrogen equal to SMR i.e. $0.96/kg H_2, with an internal rate of return (IRR) of 24%. The minimum hydrogen delivery cost was $4.96/kg H₂ at base case conditions. The life cycle CO₂ emissions is 6.35 kg CO₂/kg H₂ including hydrogen delivery to the upgrader via compressed gas trucks.     

A well to pump life cycle environmental impact assessment of some hydrogen production routes

In the present study, a comparative well to pump life cycle assessment is conducted on the hydrogen production routes of water electrolysis, biomass gasification, coal gasification, steam methane reforming, hydrogen production from ethanol and methanol. The CML 2001 impact assessment methodology is employed for assessment and comparison. Comparatively higher life cycle Carbon dioxide and Sulphur oxide emissions of 27.3 kg/kg H₂ and 50.0 g/kg H₂ respectively are determined for the water electrolysis hydrogen production route via U.S. electricity mix. In addition, the life cycle global warming potential of this route (28.6 kg CO_2eq/kg H₂) is found to be comparatively higher than other routes followed by coal gasification (23.7 kg CO_2eq/kg H₂)_. However, the ethanol based hydrogen production route is estimated to have comparatively higher life cycle emissions of nitrogen dioxide (19.6 g/kg H₂) and volatile organic compounds (10.3 g/kg H₂). Moreover, this route is determined to have a comparatively higher photochemical ozone creation potential of 0.0045 kg-ethene_eq/kg H₂ as well as eutrophication potential of 0.0043 kg PO_4eq/kg H_2. The results of this study are comparatively discussed to signify the importance of life cycle assessment in comparing the environmental sustainability of hydrogen production routes.     

Economic assessment of membrane-assisted autothermal reforming for cost effective hydrogen production with CO2 capture

A recent techno-economic study (Spallina et al., Energy Conversion and Management 120: p. 257–273) showed that the membrane assisted chemical looping reforming (MA-CLR) technology can produce H₂ with integrated CO₂ capture at costs below that of conventional steam methane reforming. A key technical challenge related to MA-CLR is the achievement of reliable solids circulation between the air and fuel reactors at large scale under the high (>50 bar) operating pressures required for optimal performance. This work therefore presents process modelling and economic assessments of a simplified alternative; membrane assisted autothermal reforming (MA-ATR), that inherently avoids this technical challenge. The novelty of MA-ATR lies in replacing the MA-CLR air reactor with an air separation unit (ASU), thus avoiding the need for oxygen carrier circulation. The economic assessment found that H₂ production from MA-ATR is only 1.5% more expensive than MA-CLR in the base case. The calculated cost of hydrogen (compressed to 150 bar) in the base case was 1.55 €/kg with a natural gas price of €6/GJ and an electricity price of €60/MWh. Both concepts show continued performance improvements with an increase in reactor pressure and temperature, while an optimum cost is achieved at about 2 bar H₂ permeate pressure. Sensitivities to other variables such as financing costs, membrane costs, fuel and electricity prices are similar between MA-ATR and MA-CLR. Natural gas prices represent the most important sensitivity, while the sensitivity to membrane costs is relatively small at high reactor pressures. MA-ATR therefore appears to be a promising alternative to achieve competitive H₂ production with CO₂ capture if technical challenges significantly delay scale-up and deployment of MA-CLR technology. The key technical demonstration required before further MA-ATR scale-up is membrane longevity under the high reactor pressures and temperatures required to minimize the cost of hydrogen.     

A life cycle impact analysis of various hydrogen production methods for public transportation sector

Reducing greenhouse gas emissions is an important task to reduce the adverse effects of climate change. A large portion of greenhouse gas emissions apparently originates from the transportation sector. Therefore, adopting cleaner technologies with lower emission footprints has become vital. For this reason, in this study, a life cycle impact analysis of hydrogen production technologies as an alternative to fossil fuels and the utilization of hydrogen in fuel cell electric buses is carried out. According to the results of this study, the operational contributions of internal combustion engines have a significant impact on life cycle impact analysis indicators. The global warming potentials of clean hydrogen production technologies result in much lower results compared to conventional hydrogen production technologies. Also, almost all indicators for biohydrogen production technologiess yield lower results because of the wastewater removal. The global warming potential results of hydrogen production methods are found to be 6.8, 1.9, 2.1, 0.5, 0.2, and 7.9 kg CO₂ eq./kg H₂ for PV electrolysis, wind electrolysis, high temperature electrolysis, dark fermentation, photo fermentation and conventional hydrogen production, respectively. However, the chemicals used in PV and wind turbine production increased the ecotoxicological indicators. On the other hand, hydrogen utilization in buses is a better option environmentally. The global warming potentials for PV electrolysis, wind electrolysis, high temperature electrolysis, dark fermentation, photo fermentation, conventional hydrogen, compressed natural gas bus, and diesel bus are found to be 0.060, 0.016, 0.018, 0.007, 0.006, 0.053, 0.082, and 0.125 kg CO₂ eq./p.km, respectively. The results are especially important in terms of reducing the effects at the source and optimizing the systems.     

Techno-economic assessment of solar steam reforming of methane in a membrane reactor using molten salts as heat transfer fluid

This paper reports the results obtained in a techno-economic analysis of the Steam Methane Reforming (SMR) technology aided with solar heat, developed and demonstrated in the European FCH JU project CoMETHy: a compact membrane reformer heated with molten salt up to 550 °C allowed to simultaneously carry out methane steam reforming, water-gas-shift reaction and hydrogen separation. This reactor can be integrated with new generation Concentrating Solar Thermal (CST) systems to supply the process heat. Experimental validation of the technology has been successfully achieved in a pilot scale plant and the results recently published. In this paper, we introduce a fully-integrated scheme and operation strategies of a plant on the 1500 Nm³/h hydrogen production scale. Then, techno-economic analysis of this new solar-driven process is presented to evaluate its competitiveness. Considering a plant capacity of 1500 Nm³/h (pure hydrogen production) and today's costs for the methane feed and the CST technology, obtained Hydrogen Production Cost (HPC) are in the range of 2.8–3.3 €/kg for a “solar-hybrid” system with high capacity factor (8000 h/year operation) and 4.7 €/kg for a “solar-only” case, while HPC≅1.7 €/kg can be obtained with the conventional route under equivalent assumptions. However, a sensitivity analysis shows that the expected drop of the cost of the CST technology will bring the HPC around 2.4 €/kg for the “solar-hybrid” case and close to 3.4 €/kg for the “solar-only” case, thus making the cost of solar reforming closer to conventional SMR with CO₂ capture and with wind/solar electrolysis in the future. In the “solar-hybrid” case total CO₂ production can be reduced by 13–29% with 58–70% of produced CO₂ recovered as pure stream (at 1.3 bar); in the “solar-only” case total CO₂ production can be reduced by 52% and 100% of produced CO₂ recovered as pure stream (at 1.3 bar). However, compared to the conventional route, CO₂ avoidance costs are still relatively high (≥137 €/ton_CO2) and process optimization measures required. Therefore, optimization measures have been outlined to increase the overall process efficiency and further reduce the HPC.     

Hydrogen production using methane: Techno-economics of decarbonizing fuels and chemicals

In the near-to-medium future, hydrogen production will continue to rely on reforming of widely available and relatively low-cost fossil resources. A techno-economic framework is described that compares the current best practice steam methane reforming (SMR) with potential pathways for low-CO₂ hydrogen production; (i) Electrolysis coupled to sustainable renewable electricity sources; (ii) Reforming of hydrocarbons coupled with carbon capture and sequestration (CCS) and; (iii) Thermal dissociation of hydrocarbons into hydrogen and carbon (pyrolysis). For methane pyrolysis, a process based on a catalytic molten Ni-Bi alloy is described and used for comparative cost estimates. In the absence of a price on carbon, SMR has the lowest cost of hydrogen production. For low-CO₂ hydrogen production, methane pyrolysis is significantly more economical than electrochemical-based processes using commercial renewable power sources. At a carbon price exceeding $21 t^?1 CO₂ equivalent, pyrolysis may represent the most cost-effective means of producing low-CO₂ hydrogen and competes favorably to SMR with carbon capture and sequestration. The current cost disparity between renewable and fossil-based hydrogen production suggests that if hydrogen is to fulfil an expanding role in a low CO₂ future, then large-scale production of hydrogen from methane pyrolysis is the most cost-effective means during the transition period while infrastructure and end-use applications are deployed.     

CO2-free hydrogen production via microwave-driven methane pyrolysis

Hydrogen will play an integral role in achieving net-zero emissions by 2050. Many studies have been focusing on green hydrogen, but this method is highly electricity intensive. Alternatively, methane pyrolysis can produce hydrogen without direct CO₂ emissions and with modest electricity inputs, serving as a bridge from fossil fuels to renewable energies. Microwaves are an efficient method of adding the required energy for this endothermic reaction. This study introduces a new method of CO₂-free hydrogen production via non-plasma methane pyrolysis using microwaves and carbon products of this process. Carbon particles in the fluidized bed absorb microwave energy and create a hot medium (>1200 °C) in contact with flowing methane. As a result, methane decomposes into hydrogen and solid carbon achieving over 90% hydrogen selectivity with ∼500 cumulative hours of experiments This modular pyrolysis system can be built anywhere with access to natural gas and electricity, enabling distributed hydrogen production.     

Curtailed electricity and hydrogen in Association of Southeast Asian Nations and East Asia Summit: Perspectives form an economic and environmental analysis

This study examines how well producing hydrogen via electrolysis from curtailed electricity from renewables could fulfil environmental benefits against the cost of producing hydrogen via electrolysis in the context of the Association of Southeast Asian Nations (ASEAN) and the East Asia Summit (EAS). The cost of producing hydrogen via electrolysis ranges from less than USD² per kgH₂ when the electrolyser load factor is 1500 h or above to USD10 per kgH₂ or even higher when the electrolyser load factor is 500 h or lower. The amount of CO₂ emissions abated by hydrogen produced from curtailed electricity from renewables ranges from about 130 million tonnes to about 150 million tonnes for ASEAN and from about 18,000 million tonnes to about 19,000 million tonnes for EAS. Applying prevailing carbon prices to the CO₂ emissions abated, the possible monetised benefits of hydrogen produced via electrolysis from curtailed electricity from renewables range from about USD0.25 per kgH₂ to about USD9.00 per kg H₂ for ASEAN and from about USD0.50 per kgH₂ to about USD15.00 per kg H₂ for EAS. The results of the cost-benefit analysis suggest that the price of carbon needs to be about USD15 per tonne of CO₂ to justify hydrogen produced via electrolysis from curtailed electricity from renewables for both ASEAN and EAS. The results also suggest that high electrolyser load factors make hydrogen produced via electrolysis from curtailed electricity from renewables cost-competitive even under low carbon prices.     

Technoeconomic analysis for hydrogen and carbon Co-Production via catalytic pyrolysis of methane

Catalytic Methane Pyrolysis (CMP) is an innovative method to convert gaseous methane into valuable H₂ and carbon products. The catalytic approach to methane pyrolysis has the potential to decrease the required operating temperature for methane decomposition from >1000 °C to under 700 °C. In this work, a novel inexpensive catalyst is discussed that displays low operating temperatures, while still maintaining high reactivity and long proven lifetimes. The kinetics associated with the catalyst's performance are modeled and a correlation was developed for use with practical simulation tools. A techno-economic assessment was conducted applying experimentally determined kinetics for the CMP reaction with the specific catalyst. Two process concepts that utilize CMP using the novel catalyst are presented in this work. Optimizations were considered in these processes and the CO₂ emissions and cost of hydrogen production of the two optimized cases, CMP with H₂ combustion (CMP-H₂) and CMP with CH₄ Combustion (CMP-CH₄), are compared to that of the current industrial standard for hydrogen production, Steam Methane Reforming with carbon capture and sequestration (SMR-CCS). Both of the proposed concepts convert methane into gaseous hydrogen and valuable carbon products, graphitic carbon to carbon Nano fibers. The carbon price was treated as a variable to determine the sensitivity of hydrogen production cost to the carbon price. The analysis indicates that cost of hydrogen production is highly dependent on the recovery and sale of carbon byproducts. Based on Aspen modeling of these two concepts for large scale hydrogen production (216 tons/day), the cost of hydrogen production, without considering carbon sales, was estimated to be $<3.25/kg, assuming a natural gas price of $7/MMBTU and conservative catalyst cost of $8/kg. Assuming 100% recovery of carbon, the price can be reduced to $0/kg by selling the carbon at <$1/kg. A market assessment suggests that values of graphitic carbon and carbon fibers range from ~$10/kg and ~$25–113/kg, respectively. The cost of H₂ production via conventional SMR is ~$2.2/kg when accounting for the cost of CO₂ sequestration. The proposed processes produce a maximum of 0–2 kg CO₂/kg H₂ in contrast to the 10 kg CO₂/kg H₂ produced via conventional SMR-CCS. The process displays an enormous potential for competitive economics accompanied by reduced greenhouse gas emissions.     

Environmental impacts of a standalone solar water splitting system for sustainable hydrogen production: A life cycle assessment

Hydrogen is broadly utilized in various industries. It can also be considered as a future clean energy carrier. Currently, hydrogen is mainly produced from typical fuels such as coal; however, there exist some other clean alternatives which use water decomposition techniques. Water splitting via the copper-chlorine (Cu–Cl) thermochemical cycle is a superb option for producing clean carbon-free fuel. Here, the life cycle assessment (LCA) technique is used to investigate the environmental consequences of an integrated solar Cu–Cl fuel production facility for large-scale hydrogen production. The impact of varying important input parameters including irradiation level, plant lifetime, and solar-to-hydrogen efficiency on various environmental impacts are investigated next. For instance, an improve in the solar-to-hydrogen efficiency from 15% to 30%, results in a reduction in the GWP from 1.25 to 6.27E-01 kg CO₂ eq. An uncertainty analysis using Monte Carlo simulation is conducted to deal with the study uncertainties. The results of the LCA show that the potential of acidification and global warming potential (GWP) of the current system are 8.27E-03 kg SO₂ eq. and 0.91 kg CO₂ eq./kg H₂, respectively. According to the sensitivity analysis, the plant lifetime has the highest effect on the total GWP of the plant with a range of 0.63–1.88 kg of CO₂ eq./kg H₂. Results comparison with past thermochemical-based studies shows that the GWP of the current integrated system is 7% smaller than that of a solar sulfur-iodine thermochemical cycle.     

Life cycle environmental impact comparison of solid oxide fuel cells fueled by natural gas,hydrogen, ammonia and methanol for combined heat and power generation

This study aims to provide a comprehensive environmental life cycle assessment of heat and power production through solid oxide fuel cells (SOFCs) fueled by various chemical feeds namely; natural gas, hydrogen, ammonia and methanol. The life cycle assessment (LCA) includes the complete phases from raw material extraction or chemical fuel synthesis to consumption in the electrochemical reaction as a cradle-to-grave approach. The LCA study is performed using GaBi software, where the selected impact assessment methodology is ReCiPe 1.08. The selected environmental impact categories are climate change, fossil depletion, human toxicity, water depletion, particulate matter formation, and photochemical oxidant formation. The production pathways of the feed gases are selected based on the mature technologies as well as emerging water electrolysis via wind electricity. Natural gas is extracted from the wells and processed in the processing plant to be fed to SOFC. Hydrogen is generated by steam methane reforming method using the natural gas in the plant. Methanol is also produced by steam methane reforming and methanol synthesis reaction. Ammonia is synthesized using the hydrogen obtained from steam methane reforming and combined with nitrogen from air in a Haber-Bosch plant. Both hydrogen and ammonia are also produced via wind energy-driven decentralized electrolysis in order to emphasize the cleaner fuel production. The results of this study show that feeding SOFC systems with carbon-free fuels eliminates the greenhouse gas emissions during operation, however additional steps required for natural gas to hydrogen, ammonia and methanol conversion, make the complete process more environmentally problematic. However, if hydrogen and ammonia are produced from renewable sources such as wind-based electricity, the environmental impacts reduce significantly, yielding about 0.05 and 0.16 kg CO₂ eq., respectively, per kWh electricity generation from SOFC.     

Well-to-wheel analysis of hydrogen fuel-cell electric vehicle in Korea

This study provides methodologies, data collection and results of well-to-wheel greenhouse gas analysis of various H₂ production pathways for fuel-cell electric vehicle (FCEV) in Korea; naphtha cracking, steam methane reforming, electrolysis and coke oven gas purification. The well-to-wheel (WTW) greenhouse gas emissions of FCEV are calculated as 32,571 to 249,332 g-CO₂ eq./GJ or 50.7 to 388.0 g-CO₂ eq./km depending on the H₂ production pathway. The landfill gas (on-site) pathway has the lowest GHG emissions because the carbon credit owing to use landfill gas. The electrolysis with Korean grid mix (on-site) pathway has the highest GHG emissions due to its high emission factor of the power generation process. Furthermore, the results are compared with other powertrain vehicles in Korea such as internal combustion engine vehicle (ICEV), hybrid electric vehicle (HEV) and electric vehicle (EV). The averaged WTW result of FCEV is 35% of ICEV, is 47% of HEV, and is 63% of EV.     

Techno-economic analysis of processes with integration of fluidized bed heat exchangers for H2 production – Part 2: Chemical-looping combustion

This work covers a techno-economic assessment for processes with inherent CO₂ separation, where a fluidized bed heat exchanger (FBHE) is used as heat source for steam reforming in a hydrogen production plant. This article builds upon the work presented in Part 1 of this study by Stenberg et al. [1], where a process excluding CO₂ capture was examined. Part 2 suggests two process configurations integrating steam reforming with a chemical-looping combustion (CLC) system, thus providing inherent CO₂ capture. The first system (case CM) uses natural gas as supplementary fuel whereas the second system (case CB) uses solid biomass, which enables net negative CO₂ emissions. In both systems, the reformer tubes are immersed in a bubbling fluidized bed where heat for steam reforming is efficiently transferred to the tubes. The processes include CO₂ compression for pipeline transportation, but excludes transport and storage. The CLC system is designed based on key parameters, such as the oxygen carrier circulation rate and oxygen transport capacity. The first system displays a process with net zero emissions and a hydrogen production efficiency which is estimated to 76.2%, which is almost 8% higher than the conventional process. The levelized production cost is 1.6% lower at below 2.6 €/kg H₂. The second system shows the possibility to reduce the emissions to ?34.1 g CO₂/MJ_H2 compared to the conventional plant which emits 80.7 g CO₂/MJ_H2. The hydrogen production efficiency is above 72% and around 2% higher than the conventional process. The capital investments are higher in this plant and the levelized hydrogen production cost is estimated to around 2.67 €/kg. The cost of CO₂ avoidance, based on a reference SMR plant with CO₂ capture, is low for both cases (?4.3 €/ton_CO2 for case CM and 2.7 €/ton_CO2 for case CB).     

Plasma steam methane reforming (PSMR) using a microwave torch for commercial-scale distributed hydrogen production

Although large-scale hydrogen production through conventional steam methane reforming (SMR) is available at an affordable cost, there is a shortage of hydrogen pipeline infrastructure between production plants and fueling stations in most places where hydrogen is needed. Due to the difficulties of transporting and storing hydrogen, onsite hydrogen production plants are desirable. Microwave plasma torch-based methods are among the most promising approaches to achieving this goal.The plasma steam methane reforming (PSMR) method discussed here has many benefits, including a high energy yield, a small carbon footprint, real-time fueling because of the short start-up time (<10 min), and the absence of expensive metal-based catalysts. Methane reforming and water gas shift reaction (WGSR) co-occur in the method advanced without a separate WGSR to achieve a high H₂ yield.This study examines an experimental investigation of commercial-scale hydrogen production through PSMR utilizing a microwave torch system. The optimum results obtained showed that the hydrogen production rate was 2247 [g(H₂)/h], and energy yield was 70 [g(H₂)/kWh] of the absorbed microwave power. An assessment of the results indicated a similar trend to that of simulated data (ASPEN Plus). The experimental results presented in this paper demonstrate the potential of a catalyst-free PSMR for commercial-scale hydrogen production.     

Hydrogen-rich syngas production and carbon dioxide formation using aqueous urea solution in biogas steam reforming by thermodynamic analysis

Biogas is a renewable biofuel that contains a lot of CH₄ and CO₂. Biogas can be used to produce heat and electric power while reducing CH₄, one of greenhouse gas emissions. As a result, it has been getting increasing academic attention. There are some application ways of biogas; biogas can produce hydrogen to feed a fuel cell by reforming process. Urea is also a hydrogen carrier and could produce hydrogen by steam reforming. This study then employes steam reforming of biogas and compares hydrogen-rich syngas production and carbon dioxide with various methane concentrations using steam and aqueous urea solution (AUS) by Thermodynamic analysis. The results show that the utilization of AUS as a replacement for steam enriches the production of H₂ and CO and has a slight CO₂ rise compared with pure biogas steam reforming at a temperature higher than 800 °C. However, CO₂ formation is less than the initial CO₂ in biogas. At the reaction temperature of 700 °C, carbon formation does not occur in the reforming process for steam/biogas ratios higher than 2. These conditions led to the highest H₂, CO production, and reforming efficiency (about 125%). The results can be used as operation data for systems that combine biogas reforming and applied to solid oxide fuel cell (SOFC), which usually operates between 700 °C to 900 °C to generate electric power in the future.     

Techno-economic feasibility assessment of sorption enhanced gasification of municipal solid waste for hydrogen production

Waste-to-fuel coupled with carbon capture and storage is forecasted to be an effective way to mitigate the greenhouse gas emissions, reduce the waste sent to landfill and, simultaneously, reduce the dependence of fossil fuels. This study evaluated the techno-economic feasibility of sorption enhanced gasification, which involves in-situ CO₂ capture, and benchmarked it with the conventional steam gasification of municipal solid waste for H₂ production. The impact of a gate fee and tax levied on the fossil CO₂ emissions in economic feasibility was assessed. The results showed that the hydrogen production was enhanced in sorption enhanced gasification, that achieved an optimum H₂ production efficiency of 48.7% (T = 650 °C and SBR = 1.8). This was 1.0% points higher than that of the conventional steam gasification (T = 900 °C and SBR = 1.2). However, the total efficiency, which accounts for H₂ production and net power output, for sorption enhanced gasification was estimated to be 49.3% (T = 650 °C and SBR = 1.8). This was 4.4% points lower than the figure estimated for the conventional gasification (T = 900 °C and SBR = 1.2). The economic performance assessment showed that the sorption enhanced gasification will result in a significantly higher levelised cost of hydrogen (5.0 €/kg) compared to that estimated for conventional steam gasification (2.7 €/kg). The levelised cost of hydrogen can be reduced to 4.5 €/kg on an introduction of the gate fee of 40.0 €/t_MSW. The cost of CO₂ avoided was estimated to be 114.9 €/tCO₂ (no gate fee and tax levied). However, this value can be reduced to 90.1 €/tCO₂ with the introduction of an emission allowance price of 39.6 €/tCO₂. Despite better environmental performance, the capital cost of sorption enhanced gasification needs to be reduced for this technology to become competitive with mature gasification technologies.     

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.     

Comparative environmental impact assessment of various fuels and solar heat for a combined cycle

In the present study, a comparative life cycle assessment (LCA) for evaluation of the environmental impacts of different fuels to generate electricity through a combined cycle is carried out. For this purpose, various heat sources including solar thermal, lignite, natural gas, oil, and hydrogen are investigated with LCA methods. The methods considered for the study include CML 2001 and ReCiPe Endpoint. The results of the present LCA study for both methods show that the hydrogen is the best fuel option according to the environmental impacts. The impact categories obtained from CML 2001 are the depletion of abiotic resources, eutrophication, global warming, marine sediment, and aquatic ecotoxicity, freshwater aquatic ecotoxicity and the competition of land. Furthermore, the human health, ecosystems and resource availability are investigated with the ReCiPe Endpoint method. The greenhouse gas emissions per kWh electricity generation are 0.19 kg CO₂ eq for solar, 1.21 kg CO₂ eq for lignite, 0.53 kg CO₂ eq for natural gas, 1.11 kg CO₂ eq for oil and 0.04 kg CO₂ eq for hydrogen according to the CML 2001 method.     

There are hydrogen production pathways with better than green hydrogen economic and environmental costs

While the present hydrogen (H₂) is mostly grey, from steam reforming of methane (CH₄) with direct carbon dioxide (CO₂) emission, different pathways have been proposed to produce H₂ more environmentally friendly. Blue H₂, adopting carbon capture and storage (CCS), has no direct CO₂ emission, but the additional cost to capture and store the CO₂. Thus, green H₂, from the electrolysis of the water (H₂O) molecule, is becoming the preferential pathway for future H₂ production. Two additional pathways are proposed for reduced economic and environmental costs, both free of direct CO₂ emissions, based on the use of concentrated solar energy (CSE). White H₂ is produced from the catalytic solar thermochemical splitting of the H₂O molecule. Aquamarine H₂ is produced from solar thermochemical CH₄ pyrolysis with a carbon catalyst. Here we provide an estimation of costs by 2030 of white and aquamarine H₂ lower than the cost of not only green H₂ but also grey H₂ disregarding the CO₂ emission.     

Hydrogen production from biogas reforming and the effect of H2S on CH4 conversion

Biogas produced during anaerobic decomposition of plant and animal wastes consists of high concentrations of methane (CH₄), carbon dioxide (CO₂) and traces of hydrogen sulfide (H₂S). The primary focus of this research was on investigating the effect of a major impurity (i.e., H₂S) on a commercial methane reforming catalyst during hydrogen production. The effect of temperature on CH₄ and CO₂ conversions was studied at three temperatures (650, 750 and 850 °C) during catalytic biogas reforming. The experimental CH₄ and CO₂ conversions thus obtained were found to follow a trend similar to the simulated conversions predicted using ASPEN plus. The gas compositions at thermodynamic equilibrium were estimated as a function of temperature to understand the intermediate reactions taking place during biogas dry reforming. The exit gas concentrations as a function of temperature during catalytic reforming also followed a trend similar to that predicted by the model. Finally, catalytic reforming experiments were carried out using three different H₂S concentrations (0.5, 1.0 and 1.5 mol%). The study found that even with the introduction of small amount of H₂S (0.5 mol%), the CH₄ and CO₂ conversions dropped to about 20% each as compared to 65% and 85%, respectively in the absence of H₂S.