A solar and wind driven energy system for hydrogen and urea production with CO2 capturing

A novel solar PV and wind energy based system is proposed in this study for capturing carbon dioxide as well as producing hydrogen, urea and power. Both Aspen Plus and EES software packages are employed for analyses and simulations. The present system is designed in a way that PEM electrolyzer is powered by the wind turbines for hydrogen production, which is further converted into ammonia and then synthesizes urea by capturing CO₂ and additional power is supplied to the community. The solar PV is employed to power the cryogenic air separation unit and the additional power is used for the industrial purpose. In the proposed system, ammonia does not only capture CO₂ but also synthesizes urea for fertilizer industry. The amount of electrical power produced by the system is 2.14 MW. The designed system produces 518.4 kmol/d of hydrogen and synthesizes 86.4 kmol/d of urea. Furthermore, several parametric studies are employed to investigate the system performance.     

Life cycle assessment of clean ammonia synthesis from thermo-catalytic solar cracking of liquefied natural gas

Ammonia is considered a sustainable energy storage medium with zero carbon content. In this work, thermal catalytic cracking of liquefied natural gas (LNG) at elevated temperatures employing concentrated solar tower is considered to produce clean hydrogen (CO₂-free) and studied in terms of life cycle emissions. The generated hydrogen is utilized for clean ammonia synthesis in a Haber-Bosch reactor. The proposed system is initially assessed from a thermodynamic perspective, considering energy and exergy analyses emphasizing optimization of operating conditions. Then, the proposed system's life cycle assessment (LCA) is performed to analyze ammonia synthesis's environmental impacts. The aggregate environmental impact of the proposed system is quantified and compared with conventional production processes. Through the utilization of solar energy resources, ammonia production can be attained, avoiding high harmful emissions. The LCA study is carried out in GaBi software, and the selected impact assessment methodology is ReCiPe. The impact categories studied in this work are global warming potential (GWP), terrestrial acidification, human toxicity, and particulate matter formation potential. Considering 30 years of use phase and allocation, the predicted GWP is approximately 0.616 kg CO₂ (eq.)/kg NH₃, showing the potential to reduce up to 69.2% of the GWP compared to the global average value. Concerning human toxicity and fine particulate matter formation impact categories, the system produces about 3.32E-2 kg 1,4-DB (eq.) and 5.96E-4 kg PM2.5 (eq.), respectively, per kg NH₃. The results are further analyzed by dominance, break-even, and variation analyses in detail.     

Wind-hydrogen utilization for methanol production: An economy assessment in Iran

This study investigates the feasibility to synthesis methanol from its flue gas and wind hydrogen. The concept is to mitigate CO₂ emission through flue gas recovery. Synthesizing methanol, on the other hand requires hydrogen at the rate of 3 kmol/kmol of carbon dioxide. Electrolysis is one method by which hydrogen can be produced cleanly from renewable source. Here it is assumed that the electrolysis unit is fed with the electricity from neighbor wind farms. Oxygen will be produced as a byproduct in electrolysis unit. However, electrolytic oxygen could be utilized for partial oxidation of methane in autothermal reactor (ATR). Onboard water electrolysis facilitates the oxygen and hydrogen storage, delivery and marketing. This study focuses on an integrated system of methanol production which enables green methanol synthesis through a system with zero carbon emission. Green methanol synthesis is comprised of CO₂ capturing and recycling along with renewable hydrogen generation. The produced hydrogen and CO₂ will be directed to methanol synthesis unit. By employing the integrated system for methanol synthesis, we could reduce the cost of using renewable energy technology.     

Thermodynamic analysis of solar energy use for reforming fuels to hydrogen

In this paper, a method is proposed for reforming fuels to hydrogen using solar energy at distributed locations (industrial sites, residential and commercial buildings fed with natural gas, remote settlements supplied by propane etc). In order to harness solar energy a solar concentrator is used to generate high temperature heat to reform fuels to hydrogen. A typical fuel such as natural gas, propane, methanol, or an atypical fuel such as ammonia or urea can be transported to distributed locations via gas networks or other means. The thermodynamic analysis of the process shows the general reformation reactions for NH₃, CH₄ and C₃H₈ as the input fuel by comparison through operational fuel cost and CO₂ mitigation indices. Through a cost analysis, cost reduction indices show fuel-usage cost reductions of 10.5%, 22.1%, and 22.2% respectively for the reformation of ammonia, methane, and propane. CO₂ mitigation indices show fuel-usage CO₂ mitigations of 22.1% and 22.3% for methane and propane respectively, where ammonia reformation eliminates CO₂ emission at the fuel-usage stage. The option of reforming ammonia is examined in further detail as proposed cycles for solar energy capture are considered. A mismatch of specific heats from the solar dish is observed between incoming and outgoing streams, allowing a power production system to be included for a more complete energy capture. Further investigation revealed the most advantageous system with a direct expansion turbine being considered rather than an external power cycle such as Brayton or Rankine type cycles. Also, an energy efficiency of approximately 93% is achievable within the reformation cycle.     

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.     

Methanol synthesis from renewable H2 and captured CO2 from S-Graz cycle – Energy,exergy, exergoeconomic and exergoenvironmental (4E) analysis

Thermodynamic, economic and environmental analyses of a combined CO₂ capturing system, including, geothermal driven dual fluid organic Rankine cycle (ORC), proton exchange membrane electrolyzer (PEME), S-Graz cycle and methanol synthesis unit (MSU) were carried out. The presented zero emission system was designed based on the oxy-fuel combustion carbon capturing to produce power, hydrogen and methanol, while released CO₂ can be captured. Generated renewable power by the ORC was utilized by the PEME to produce renewable hydrogen. Part of the produced hydrogen is fed to the MSU, while the rest was stored in hydrogen tanks. In fact, CO₂ hydrogenation to produce methanol suggested via direct methanol synthesis in order to utilize the captured CO₂ from the S-Graz cycle. Exergy efficiency of the system defined to analyze the system thermodynamically, while SPECO method utilized to evaluate system economically. Results revealed that the most important part of the system is the S-Graz cycle, from the viewpoint of capital investment. Also, the average product unit cost of 24.88 $/GJ obtained for the whole system.     

Integrated adsorption steam gasification for enhanced hydrogen production from palm waste at bench scale plant

The generation of hydrogen-enriched synthesis gas from catalytic steam gasification of biomass with in-situ CO₂ capture utilizing CaO has a high perspective as clean energy fuels. The present study focused on the process modeling of catalytic steam gasification of biomass using palm empty fruit bunch (EFB) as biomass for hydrogen generation through experimental work. Experiment work has been carried out using a fluidized bed gasifier on a bench-scale plant. The established model integrates the kinetics of EFB catalytic steam gasification reactions, in-situ capturing of CO₂, mass and energy balance calculations. Chemical reaction constants have been calculated via the parameters fitting optimization approach. The influence of operating parameters, mainly temperature, steam to biomass, and sorbent to biomass ratio, was investigated for the hydrogen purity and yield through the experimental study and developed model. The results predicted approximately 75 vol% of the hydrogen purity in the product gas composition. The maximum H₂ yield produced from the gasifier was 127 gH₂/kg of EFB via experimental setup. The increase in both steam to biomass ratio and temperature enhanced the production of hydrogen gas. Comparing the results with already published literature showed that the current system enables to produce a high amount of hydrogen from EFB.     

Hydrogen production from solar energy powered supercritical cycle using carbon dioxide

A hydrogen production method is proposed, which utilizes solar energy powered thermodynamic cycle using supercritical carbon dioxide (CO₂) as working fluid for the combined production of hydrogen and thermal energy. The proposed system consists of evacuated solar collectors, power generating turbine, water electrolysis, heat recovery system, and feed pump. In the present study, an experimental prototype has been designed and constructed. The performance of the cycle is tested experimentally under different weather conditions. CO₂ is efficiently converted into supercritical state in the collector, the CO₂ temperature reaches about 190 °C in summer days, and even in winter days it can reach about 80 °C. Such a high-temperature realizes the combined production of electricity and thermal energy. Different from the electrochemical hydrogen production via solar battery-based water splitting on hand, which requires the use of solar batteries with high energy requirements, the generated electricity in the supercritical cycle can be directly used to produce hydrogen gas from water. The amount of hydrogen gas produced by using the electricity generated in the supercritical cycle is about 1035 g per day using an evacuated solar collector of 100.0 m² for per family house in summer conditions, and it is about 568.0 g even in winter days. Additionally, the estimated heat recovery efficiency is about 0.62. Such a high efficiency is sufficient to illustrate the cycle performance.     

The environmental impact of post-combustion CO2 capture with MEA, with aqueous ammonia, and with an aqueous ammonia-ethanol mixture for a coal-fired power plant

In this paper the authors compare monoethanolamine (MEA) to aqueous ammonia (AA) and a solvent mixture of aqueous ammonia and ethanol (EAA) with respect to their post-combustion CO₂ capture performance and their environmental impact. Simulation of all processes was carried out with Aspen Plus^® and compared to experimental results for CO₂ scrubbing with ammonia. Of special interest was the formation of stable salts, which could be observed in the experimental CO₂ capture with both ammonia solvents. If CO₂ can be captured in the form of ammonium salts, energy requirements are greatly reduced, since no energy is required for solvent regeneration and CO₂ compression. The environmental impact of CO₂ capture was investigated for a 500 MW pulverised coal power plant employing Life Cycle Assessment (LCA) using the software SimaPro^®. For a comprehensive evaluation of this impact, influencing factors such as solvent production and solvent emissions were included. With kinetics taken into account, no salt formation could be observed in CO₂ removal with aqueous ammonia. The necessary reduction of ammonia emissions leads to further energy requirements, and solvent production as well as the remaining ammonia losses to the environment have a more significant environmental impact than CO₂ removal with MEA.     

Environmental evaluation of hydrogen production via thermochemical water splitting using the Cu-Cl Cycle: A parametric study

Variations of environmental impacts with lifetime and production capacity are reported for nuclear based hydrogen production plants using the three-, four- and five-step (copper-chlorine) Cu-CI thermochemical water decomposition cycles. Life cycle assessment is utilized which is essential to evaluate and to decrease the overall environmental impact of any system and/or product. The life cycle assessments of the hydrogen production processes indicate that the four-step Cu-Cl cycle has lower environmental impacts than the three- and five-step cycles due to its lower thermal energy requirement. Parametric studies show for the four-step Cu-Cl cycle that acidification and global warming potentials can be reduced from 0.0031 to 0.0028 kg SO₂-eq and from 0.63 to 0.55 kg CO₂-eq, respectively, if the lifetime of the system increases from 10 to 100 years.     

Low-carbon hydrogen production via electron beam plasma methane pyrolysis: Techno-economic analysis and carbon footprint assessment

Electron beam plasma methane pyrolysis is a hydrogen production pathway from natural gas without direct CO₂ emissions. In this work, two concepts for a technical implementation of the electron beam plasma pyrolysis in a large-scale hydrogen production plant are presented and evaluated in regards of efficiency, economics and carbon footprint. The potential of this technology is identified by an assessment of the results with the benchmark technologies steam methane reforming, steam methane reforming with carbon capture and storage as well as water electrolysis. The techno-economic analysis shows levelized costs of hydrogen for the plasma pyrolysis between 2.55 €/kg H₂ and 5.00 €/kg H₂ under the current economic framework. Projections for future price developments reveal a significant reduction potential for the hydrogen production costs, which support the profitability of plasma pyrolysis under certain scenarios. In particular, water electrolysis as direct competitor with renewable electricity as energy supply shows a considerably higher specific energy consumption leading to economic advantages of plasma pyrolysis for cost-intensive energy sources and a high degree of utilization. Finally, the carbon footprint assessment indicates the high potential for a reduction of life cycle emissions by electron beam plasma methane pyrolysis (1.9 kg CO₂ eq./kg H₂ – 6.4 kg CO₂ eq./kg H₂, depending on the electricity source) compared to state-of-the-art hydrogen production technology (10.8 kg CO₂ eq./kg H₂).     

Investigation of an integrated system with industrial thermal management options for carbon emission reduction and hydrogen and ammonia production

A new integrated energy system employing the cement slag waste heat is uniquely proposed in this study. The core focus of the proposed system is to generate clean hydrogen thermochemically and convert it into ammonia. The designed system consists of the copper–chlorine (Cu–Cl) cycle, a cryogenic air separation unit and a steam Rankine cycle while the useful commodities produced by the proposed system are hydrogen, ammonia, oxygen, hot water and electricity. A CO₂ emission analysis is also conducted to calculate the emissions which can be avoided by recovering this waste heat. The Aspen Plus simulation software is utilized to model and simulate the proposed integrated system. A thermochemical water splitting process is incorporated into the system for hydrogen production. The cryogenic air separation unit is integrated in order to separate nitrogen from the air. This proposed system also reduces the environmental effects of the flue gas emitted by the cement industry. Multiple parametric studies are performed to investigate the system performance by varying operating conditions and state properties. The energy analysis is implemented on each component of the designed system. The overall energy efficiency of the system is concluded as 30.1%. The amount of CO₂ emissions which can be avoided by utilizing this waste heat is 29.64 ktonne/5 years.     

Using three chemical looping reactors in ammonia production process – A novel plant configuration for a green production

Production of three pure streams of H₂, N₂ and CO₂ makes the chemical looping reactors as an attractive intermediate technology to provide the feedstock of ammonia synthesis loop. As a goal of paper, for the first time, a novel and green plant configuration using three chemical looping reactors is proposed for ammonia production in which needed hydrogen and nitrogen are produced by means of a process simpler than the conventional technologies. Due to the reduction in plant units and also 30% increase in production ratio and simultaneously production of economically valuable by-products of H₂, N₂ and CO₂, significant potential for investment cost reduction along with CO₂ capture and storage can be anticipated. Moreover, the proposed plant for ammonia production is very flexible in terms of adjusting the desired main products.     

Enhanced coal gasification heated by unmixed combustion integrated with an hybrid system of SOFC/GT

For clean utilization of coal, enhanced gasification by in situ CO₂ capture has the advantage that hydrogen production efficiency is increased while no energy is required for CO₂ separation. The unmixed fuel process uses a sorbent material as CO₂ carrier and consists of three coupled reactors: a coal gasifier where CO₂ is captured generating a H₂-rich gas that can be utilized in fuel cells, a sorbent regenerator where CO₂ is released by sorbent calcination and it is ready for capture and a reactor to oxidize the oxygen transfer material which produces a high temperature/pressure vitiated air. This technology has the potential to eliminate the need for the air separation unit using an oxygen transfer material. Reactors' temperatures range from 750 °C to 1550 °C and the process operates at pressure around 7.0 bar. This paper presents a global thermodynamic model of the fuel processing concept for hydrogen production and CO₂ capture combined with fuel and residual heat usage. Hydrogen is directly fed to a solid oxide fuel cell and exhaust streams are used in a gas turbine expander and in a heat recovery steam generator. This paper analyzes the influence of steam to carbon ratio in gasifier and regeneration reactor, pressure of the system, temperature for oxygen transfer material oxidation, purge percentage in calciner, average sorbent activity and oxidant utilization in fuel cell. Electrical efficiency up to 73% is reached under optimal conditions and CO₂ capture efficiencies near 96% ensure a good performance for GHG's climate change mitigation targets.     

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).     

Assessment of CO2 capture options from various points in steam methane reforming for hydrogen production

Steam methane reforming (SMR) is currently the main hydrogen production process in industry, but it has high emissions of CO₂, at almost 7 kg CO₂/kg H₂ on average, and is responsible for about 3% of global industrial sector CO₂ emissions. Here, the results are reported of an investigation of the effect of steam-to-carbon ratio (S/C) on CO₂ capture criteria from various locations in the process, i.e. synthesis gas stream (location 1), pressure swing adsorber (PSA) tail gas (location 2), and furnace flue gases (location 3). The CO₂ capture criteria considered in this study are CO₂ partial pressure, CO₂ concentration, and CO₂ mass ratio compared to the final exhaust stream, which is furnace flue gases. The CO₂ capture number (N_cc) is proposed as measure of capture favourability, defined as the product of the three above capture criteria. A weighting of unity is used for each criterion. The best S/C ratio, in terms of providing better capture option, is determined. CO₂ removal from synthesis gas after the shift unit is found to be the best location for CO₂ capture due to its high partial pressure of CO₂. However, furnace flue gases, containing almost 50% of the CO₂ in produced in the process, are of great significance environmentally. Consequently, the effects of oxygen enrichment of the furnace feed are investigated, and it is found that this measure improves the CO₂ capture conditions for lower S/C ratios. Consequently, for an S/C ratio of 2.5, CO₂ capture from a flue gas stream is competitive with two other locations provided higher weighting factors are considered for the full presence of CO₂ in the flue gases stream. Considering carbon removal from flue gases, the ratio of hydrogen production rate and N_cc increases with rising reformer temperature.     

Process design and optimization of green processes for the production of hydrogen and urea from glycerol

To address the production of hydrogen and urea from glycerol, a green process of a glycerol-to-green chemicals chain (GTGC) named Scheme-1 is presented, where the glycerol is a green feedstock from the production of biodiesel and the carbon capture and utilization (CCU) is involved to reuse captured carbon. The major processes in the GTGC include that (i) the glycerol steam reforming (GSR), the water gas shift reactor, and the ammonia synthesis reactor are integrated to enhance the yields of hydrogen and ammonia, (ii) the pressure swing adsorption (PSA) is added to capture CO₂ and produce the high-purity hydrogen, and (iii) CO₂ is converted into urea by means of the urea synthesis reactor. The optimal operating conditions of GSR such as glycerol (GLY) conversion and cold gas efficiency are determined by using the response surface methodology. To address the lower CO₂ emissions of GTGC, the heat integration of GTGC named Scheme-2 and the heat integration/combined cycle power generation of GTGC named Scheme-3 are proposed. For the comparisons of total CO₂ emissions of the three schemes, Scheme-2 is lower than other schemes due to using the heat integration method for reducing hot/cold utilities. For the comparisons of net CO₂ emissions of the three schemes, Scheme-3 is superior to other schemes due to no use of external utilities.     

Significance of CO2-free hydrogen globally and for Japan using a long-term global energy system analysis

In this paper, the significance of CO₂-free hydrogen is discussed using a long-term global energy system. The energy demand–supply system including CO₂-free hydrogen was assumed, though there are still large uncertainties as to whether a global CO₂-free hydrogen energy system will be deployed. System analysis was conducted using the global and long-term intertemporal optimization energy model GRAPE under severe CO₂ emission constraints. Applied global CO₂ constraints for 2050 were a 50% reduction from 1990 levels. CO₂ constraints accounting for Intended Nationally Determined Contributions (INDCs) in each region were also considered. A variety of energy resources and technologies were considered in this model. Hydrogen can be produced from low-grade coal or natural gas with CO₂ capture and electricity from renewable energy. The hydrogen CIF (cost, insurance, and freight) price for Japan was about 3.2 cents/MJ in 2030. Hydrogen demand technologies considered in this paper are hydrogen-fired power plants, direct combustion, combined heat and power (fuel cells, gas engines, and gas turbines), fuel cell vehicles, and hydrogen internal combustion engine vehicles. The majority of CO₂-free hydrogen was deployed in the transportation sector. CO₂-free hydrogen was utilized in the power sector, where deployment of other zero emission technology has some constraints. From an economic viewpoint, CO₂-free hydrogen can reduce the global energy system cost. From the viewpoint of a localized region, such as Japan, deployment of CO₂-free hydrogen can improve energy security and environmental indicators.     

Production of hydrogen for export from wind and solar energy,natural gas,and coal in Australia

Hydrogen production for export to Japan and Korea is increasingly popular in Australia. The theoretically possible paths include the use of the excess wind and solar energy supply to the grid to produce hydrogen from natural gas or coal. As a contribution to this debate, here I discuss the present contribution of wind and solar to the electricity grid, how this contribution might be expanded to make a grid wind and solar only, what is the energy storage needed to permit this supply, and what is the ratio of domestic total primary energy supply to electricity use. These factors are required to determine the likeliness of producing hydrogen for export. The wind and solar energy capacity, presently at 6.7 and 11.4 GW, have to increase almost 8 times up to values of 53 and 90 GW respectively to support a wind and solar energy only electricity grid for the southeast states only. Additionally, it is necessary to build-up energy storage of actual power >50 GW and stored energy >3000 GW h to stabilize the grid. If the other states and territories are considered, and also the total primary energy supply (TPES) rather than just electricity, the wind and solar capacity must be increased of a further 6–8 times. It is concluded that it is extremely unlikely that hydrogen for export could be produced from the splitting of the water molecule by using excess wind and solar energy, and it is very unlikely that wind and solar may fully cover the local TPES needs. The most likely scenario is production hydrogen via syngas from either natural gas or coal. Production from natural gas and coal needs further development of techniques, to include CO₂ capture, a way to reuse or store CO₂, and finally, the better energy efficiency of the conversion processes. There are several challenges for using natural gas or coal to produce hydrogen with near-zero greenhouse gas emissions. Carbon capture, utilization, and storage technologies that ensure no CO₂ is released in the production process, and new technologies to separate the oxygen from the air, and in case of natural gas, the water, and the CO₂ from the combustion products, are urgently needed to make sense of the fossil fuel hydrogen production. There is no benefit from producing hydrogen from fossil fuels without addressing the CO₂ issue, as well as the fuel energy penalty issue during conversion, that is simply translating in a net loss of fuel energy with the same CO₂ emission.     

Analysis and assessment of a geothermal based cogeneration system and lithium extraction

This paper presents the thermodynamic analyses for a double flash-binary based integrated geothermal power plant which consists of two steam turbines and one expander in the organic Rankine cycle that uses ammonia as the working fluid and a lithium extraction sub system. The main useful outputs of the plant are electricity, heat for floor heating and lithium carbonate (Li₂CO₃). The aim of this study is to assess the overall system performance energetically and exergetically. Based on the results obtained from this study, the overall energy and exergy efficiencies are 58.41% and 66.63%, respectively. The present results also show that the Li₂CO₃ is produced at the rate of 9.52 × 10⁻³ kg/s. In addition, the effects of changing several important operating parameters and ambient conditions on the energy and exergy efficiencies and the performance of the subsystems are investigated.