Global warming consequences of replacing natural gas with hydrogen in the domestic energy sectors of future low-carbon economies in the United Kingdom and the United States of America

Hydrogen has a potentially important future role as a replacement for natural gas in the domestic sector in a zero-carbon economy for heating homes and cooking. To assess this potential, an understanding is required of the global warming potentials (GWPs) of methane and hydrogen and of the leakage rates of the natural gas distribution system and that of a hydrogen system that would replace it. The GWPs of methane and hydrogen were estimated using a global chemistry-transport model as 29.2 ± 8 and 3.3 ± 1.4, respectively, over a 100-year time horizon. The current natural gas leakage rates from the distribution system have been estimated for the UK by the ethane tracer method to be about 0.64 Tg CH₄/year (2.3%) and for the US by literature review to be of the order of 0.69–2.9 Tg CH₄/year (0.5–2.1%). On this basis, with the inclusion of carbon dioxide emissions from combustion, replacing natural gas with green hydrogen in the domestic sectors of both countries should reduce substantially the global warming consequences of domestic sector energy use both in the UK and in the US, provided care is taken to reduce hydrogen leakage to a minimum. A perfectly sealed zero-carbon green hydrogen distribution system would save the entire 76 million tonnes CO₂ equivalent per year in the UK.     

A comparative study of odorants for gas escape detection of natural gas and hydrogen

Decarbonising the residential heating and cooking sector is essential to meet national and international carbon emission reduction targets. Hydrogen has been identified by the scientific community, industry, and policy makers as part of the solution to this challenge. Hydrogen has been used for decades in many industries, formerly making up approximately 50% of the Town Gas used for heating and cooking in UK homes in the mid 20th century. It is now crucial to ensure safety regulations are met, and public acceptance gained, before hydrogen can start being used for residential heating. Demonstration projects require hydrogen distribution networks to be odorised. This study examines the use of sulphur-based odorants, which are currently in use in the UK and Europe to odorise Natural Gas, to be used in a 100% hydrogen gas demonstration network in the UK. We undertook a comparative testing programme to evaluate the escape detection properties of odorised hydrogen against odorised methane and natural gas. This comparative approach will help address the question asked by UK and EU regulators: is hydrogen ‘as safe as’ natural gas? The results show that untrained participants can identify an escaping gas odorised with Odorant New Blend and standby odorant 2, in hydrogen, natural gas or methane, at the regulatory threshold of 1% gas in air. These results contribute to the safety-case of H100 led by SGN.     

Assessing the viability of the ACT natural gas distribution network for reuse as a hydrogen distribution network

The Australian Capital Territory (ACT) has legislated and aims to be net zero emissions by 2045. Such ambitious targets have implications for the contribution of hydrogen and its storage in gas distribution networks Therefore, we need to understand now the impacts on the gas distribution network of the transition to 100% hydrogen. Assessment of the viability of decarbonising the ACT gas network will be partly based on the cost of reusing the gas network for the safe and reliable distribution of hydrogen. That task requires each element of the natural gas safety management system to be evaluated.This article describes the construction of a test facility in Canberra, Australia used to identify issues raised by 100% hydrogen use in the medium pressure distribution network, consisting of nylon and polyethylene (PE) as a means of identifying measures necessary to ensure ongoing validity of the network's regulatory safety case.Evoenergy (the ACT's gas distribution company) have constructed a Test Facility, incorporating an electrolyser, a gas supply pressure reduction and mixing skid a replica gas network and a domestic installation with gas appliances. Jointly with Australian National University (ANU) and Canberra Institute of Technology (CIT) the Company has commenced a program of “bench testing”, initially with 100% hydrogen to identify gaps in the safety case specifically focusing on the materials, work practices and safety systems in the ACT.The facility is designed to assess: ? Materials in use including aged network materials and components ? Construction and installation techniques both greenfield and live gas work ? Purging and filling techniques ? Leak detection both underground and above ground ? Emergency response and make safe techniques ? Issues associated with use of hydrogen in light commercial and domestic appliances.To educate and train: ? Technicians and gas fitters on infrastructure installation and management ? Emergency response services on responding to hydrogen related emergencies in a network environment; and ? manage public perceptions of hydrogen in a network environment.Australia has an enviable safety record for the safe and reliable transport, distribution and use of natural gas. The ACT natural gas network owned and operated by Evoenergy is one of the newest in Australia and has leveraged off the best materials and practices in Australia to build its network.The paper addresses major safety issues relating to the production/storage, distribution and consumer end use of hydrogen injected into existing gas distribution networks. The analysis is guided by the Safety Management System. The Hydrogen Testing Facility described in the paper provide tools for evaluation of hydrogen safety matters in the ACT and Australia-wide.Testing to date has confirmed that polyethylene and nylon pipe and their respective jointing techniques can contain 100% hydrogen at pressures used for the distribution of natural gas. Testing has also confirmed that current installation work practices on polyethylene and nylon pipe and joints are suitable for hydrogen service. This finding is subject to variation attributable to staff training and skill levels and further testing has been programmed as outlined in this paper.Testing of gas isolation by clamping and simulated repair on the hydrogen network has established that standard natural gas isolation techniques work with 100% hydrogen at natural gas pressures.     

The integration of hybrid hydrogen networks for refinery and synthetic plant of chemicals

Hydrogen is the core source to both refinery and synthetic plant of chemicals. Refinery consumes high purity hydrogen while synthetic plant of chemicals needs syngas consists of hydrogen and carbon oxides. As main hydrogen production technologies, industrial coal gasification and steam methane reforming based pathways generate H₂, CO and CO₂, which is actually the mixture of hydrogen and carbon oxides. Hence, the gases demand of refinery and synthetic plant of chemicals and their supply from hydrogen production can form hybrid hydrogen networks. On the basis of complementary reuse, this paper firstly proposes integration of hybrid hydrogen network for refinery and synthetic plant of chemicals. Superstructures of individual and hybrid hydrogen networks are employed as problem illustration and corresponding linear programming (LP) mathematical models are formulated. Practical refinery and synthetic plant of chemicals cases are employed to demonstrate its application. Compared with individual networks, the natural gas conservation case can recover 8660.4 Nm³·h^-1 hydrogen in purge gas, reduce 1386.6 Nm³·h^-1 CO₂ emission, equaling to reduction of 278.11 kmol·h^-1 natural gas feedstock and 14.8% of total gas production load; the coal conservation case can even waive the total coal consumption and extra 104.1 kmol·h^-1 natural gas, recover 8660.4 Nm³·h^-1 hydrogen in purge gas, reduce 5255.8 Nm³·h^-1 of CO₂ emission and decrease 21.2% of the total gas production load. Furthermore, economic evaluation is also placed to account for the economic advantage of hybrid network.     

Fossil fuels substitution by the solar energy utilization for the hot water production in the heating plant “Cerak” in Belgrade

The main objective of this paper is to evaluate energy and environmental benefits of the large-scale solar heating system connection with district heating system. The assessment of fossil fuels substitution by the solar energy for the hot water production for domestic use, during the summer period, is done. Hot water for district heating and domestic use is produced in heating plant “Cerak” placed in the suburb of Belgrade. The existing production and distribution system are based on fossil fuel energy, mainly on the natural gas. In the first phase of the project plan was to install about 10,000 m² of solar collectors to substitute nearly 25% of natural gas consumption. During the summer period, the saving of natural gas calculated for presented system is approximately 430,000 m³ and in this way 900 t of the CO₂ emissions would be reduced.     

Experimental study of hydrogen explosion in repeated pipe congestion – Part 2: Effects of increase in hydrogen concentration in hydrogen-methane-air mixture

Hydrogen is seen as an important energy carrier for the future which offers carbon free emissions. At present it is mainly used in refueling hydrogen fuel cell cars. However, it can also be used together with natural gas in existing gas fired equipment with the benefit of lower carbon emissions. This can be achieved by introducing hydrogen into existing natural gas pipelines. These pipelines are designed, constructed and operated to safely transport natural gas, which is mostly methane. Because hydrogen has significantly different physical and chemical properties than natural gas, any addition of hydrogen my adversely affect the integrity of the pipeline network, increasing the likelihood and consequences of an accidental leak. Since it increases the likelihood and consequences of an accidental leak, it increases the risk of explosion. In order to address various safety issues related to addition of hydrogen in to a natural gas pipeline a EU project NATURALHY was introduced. A major objective of the NATURALHY project was to identify how much hydrogen could be introduced into the natural gas pipeline network. Such that it does not adversely impact the safety of the pipeline network and significantly increase the risk to the public. This paper reports experimental work conducted to measure the explosion overpressure generated by ignition of hydrogen-methane-air mixture in a highly congested region consisting of interconnected pipes. The composition of the methane/hydrogen mixture used was varied from 0% hydrogen (100% methane) to 100% hydrogen (0% methane) to understand its effect on generated explosion overpressure. It was observed that the maximum overpressures generated by methane-hydrogen mixtures with 25% (by volume) or less hydrogen content are not likely to be significantly greater than those generated by methane alone. Therefore, it can be concluded that the addition of less than 25% by volume of hydrogen into pipeline networks would not significantly increase the risk of explosion.     

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.     

Experimental and numerical study of hydrogen addition in a natural gas heavy duty engine for a bus vehicle

Hydrogen added to natural gas improves the process of combustion with the possibility to develop engines with higher performance and lower environmental impact. In this paper experimental and numerical analyses on a multi cylinder stoichiometric heavy duty engine, fuelled with natural gas–hydrogen blends, are reported. Some constrains on hydrogen content and maximum load achievable have limited the scope of investigation. A specific modelling of the reference engine was developed to extend the study at full load condition and at higher hydrogen content. The results showed a higher combustion speed when hydrogen content in the fuel is increased. However, the positive effect of shorter combustion duration on thermal efficiency is mitigated by higher wall heat loss, due to higher combustion temperatures. Therefore lower CO₂ emissions are due only to the substitution of natural gas with hydrogen, making crucial the way of hydrogen producing to have a benefit on well-to-wheel CO₂ emissions.     

Optimal design of sustainable hydrogen networks

Hydrogen is widely used in modern oil refineries to remove the sulfur, nitrogen and aromatic contents of fuels. The existence of such contents would aggravate the greenhouse gas (GHG) emission of petrol fuels. The ultimate goal of massive hydrogen consumption in refineries is to cut down the GHG emission. However, current researches on hydrogen networks are focusing on reducing the cost of hydrogen consumption. The environmental impact of hydrogen consumption, especially the GHG emission, has not been considered yet. If the hydrogen supply network itself discharges too much CO₂, then the significance of the hydrogen consumption will be discounted considerably. It is of great importance to design a sustainable hydrogen network. This paper presents a systematic mathematical modeling methodology for the optimal synthesis of sustainable refinery hydrogen networks. The proposed mixed integer nonlinear programming (MINLP) model accounts for both the economic and the environmental aspect of the hydrogen network. Total annual cost (TAC) is employed to evaluate the economic efficiency of the network, while the environmental performance is assessed by the total CO₂ emission of the network. Two types of fresh fuels are investigated in the case studies. A multi-objective optimization is carried out via the Pareto front generation, which is obtained by an adaptive weighted-sum method. The economic–environmental Pareto front will allow for determining the most promising options for the reuse, purification and combustion of hydrogen streams. The numerical example has shown the proposed approach to be efficient and powerful.     

Comparing prospective hydrogen pathways with conventional fuels and grid electricity in India through well-to-tank assessment

The present study uses Greenhouse Gases, Regulated Emissions, and Energy Use in Technologies Model (GREET), to compare hydrogen generated via multiple pathways (Natural gas, methanol reforming; coal, petcoke, biomass gasification etc) with the conventional fuels like diesel and compressed natural gas and grid electricity under Indian context through a comprehensive well to tank assessment based on net CO₂ equivalent emission and energy consumption. Limited availability of customized studies comparing hydrogen production and supply with other energy options in India distinguishes the present work as it provides a fresh insight into potential pathways for hydrogen production while assessing feedstock availability and raw water consumption. The study reveals that biomass gasification and solar electrolysis are among the least GHG emitting pathways to fill one unit of energy equivalent in the tank. Hydrogen produced through natural gas reforming is 70% less emission intensive and 38% more energy efficient than Indian grid electricity.     

Recycling a hydrogen rich residual stream to the power and steam plant

The benefits of using a residual hydrogen rich stream as a clean combustion fuel in order to reduce Carbon dioxide emissions and cost is quantified. A residual stream containing 86% of hydrogen, coming from the top of the demethanizer column of the cryogenic separation sector of an ethylene plant, is recycled to be mixed with natural gas and burned in the boilers of the utility plant to generate high pressure steam and power. The main advantage is due to the fact that the hydrogen rich residual gas has a higher heating value and less CO₂ combustion emissions than the natural gas. The residual gas flowrate to be recycled is selected optimally together with other continuous and binary operating variables. A Mixed Integer Non Linear Programming problem is formulated in GAMS to select the operating conditions to minimize life cycle CO₂ emissions.     

Political,economic and environmental impacts of biomass-based hydrogen

The purpose of this study is to assess the political, economic and environmental impacts of producing hydrogen from biomass. Hydrogen is a promising renewable fuel for transportation and domestic applications. Hydrogen is a secondary form of energy that has to be manufactured like electricity. The promise of hydrogen as an energy carrier that can provide pollution-free, carbon-free power and fuels for buildings, industry, and transport makes it a potentially critical player in our energy future. Currently, most hydrogen is derived from non-renewable resources by steam reforming in which fossil fuels, primarily natural gas, but could in principle be generated from renewable resources such as biomass by gasification. Hydrogen production from fossil fuels is not renewable and produces at least the same amount of CO₂ as the direct combustion of the fossil fuel. The production of hydrogen from biomass has several advantages compared to that of fossil fuels. The major problem in utilization of hydrogen gas as a fuel is its unavailability in nature and the need for inexpensive production methods. Hydrogen production using steam reforming methane is the most economical method among the current commercial processes. These processes use non-renewable energy sources to produce hydrogen and are not sustainable. It is believed that in the future biomass can become an important sustainable source of hydrogen. Several studies have shown that the cost of producing hydrogen from biomass is strongly dependent on the cost of the feedstock. Biomass, in particular, could be a low-cost option for some countries. Therefore, a cost-effective energy-production process could be achieved in which agricultural wastes and various other biomasses are recycled to produce hydrogen economically. Policy interest in moving towards a hydrogen-based economy is rising, largely because converting hydrogen into useable energy can be more efficient than fossil fuels and has the virtue of only producing water as the by-product of the process. Achieving large-scale changes to develop a sustained hydrogen economy requires a large amount of planning and cooperation at national and international alike levels.     

Evaluation of hydrogen storage technology in risk-constrained stochastic scheduling of multi-carrier energy systems considering power,gas and heating network constraints

The operation of energy systems considering a multi-carrier scheme takes several advantages of economical, environmental, and technical aspects by utilizing alternative options is supplying different kinds of loads such as heat, gas, and power. This study aims to evaluate the influence of power to hydrogen conversion capability and hydrogen storage technology in energy systems with gas, power, and heat carriers concerning risk analysis. Accordingly, conditional value at risk (CVaR)-based stochastic method is adopted for investigating the uncertainty associated with wind power production. Hydrogen storage system, which can convert power to hydrogen in off-peak hours and to feed generators to produce power at on-peak time intervals, is studied as an effective solution to mitigate the wind power curtailment because of high penetration of wind turbines in electricity networks. Besides, the effect constraints associated with gas and district heating network on the operation of the multi-carrier energy systems has been investigated. A gas-fired combined heat and power (CHP) plant and hydrogen storage are considered as the interconnections among power, gas and heat systems. The proposed framework is implemented on a system to verify the effectiveness of the model. The obtained results show the effectiveness of the model in terms of handling the risks associated with multi-carrier system parameters as well as dealing with the penetration of renewable resources.     

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.     

Life cycle energy and environmental analysis of a microgrid power pavilion

Microgrids—generating systems incorporating multiple distributed generator sets linked together to provide local electricity and heat—are one possible alterative to the existing centralized energy system. Potential advantages of microgrids include flexibility in fuel supply options, the ability to limit emissions of greenhouse gases, and energy efficiency improvements through combined heat and power (CHP) applications. As a case study in microgrid performance, this analysis uses a life cycle assessment approach to evaluate the energy and emissions performance of the NextEnergy microgrid Power Pavilion in Detroit, Michigan and a reference conventional system. The microgrid includes generator sets fueled by solar energy, hydrogen, and natural gas. Hydrogen fuel is sourced from both a natural gas steam reforming operation and as a by‐product of a chlorine production operation. The chlorine plant receives electricity exclusively from a hydropower generating station. Results indicate that the use of this microgrid offers a total energy reduction potential of up to 38%, while reductions in non‐renewable energy use could reach 51%. Similarly, emissions of CO₂, a key global warming gas, can be reduced by as much as 60% relative to conventional heat and power systems. Hydrogen fuels are shown to provide a net energy and emissions benefit relative to natural gas only when sourced primarily from the chlorine plant. Copyright © 2006 John Wiley & Sons, Ltd.     

A multi-objective model for optimizing hydrogen injected-high pressure natural gas pipeline networks

The paper develops a statistical model for optimizing the Hydrogen-injected Natural gas (H-NG) high-pressure pipeline network. Gas hydrodynamic principles are utilized to construct the pipeline and compressor station model. The model developed is implemented on a pipeline grid that is supposed to carry Hydrogen as an energy carrier in a natural gas-carrying pipeline. The paper aims to optimize different objectives using ant colony optimization (ACO). The first objective includes a single objective optimization problem that evaluates the maximum permissible hydrogen amounts blended with natural gas (NG) for a set of pipeline constraints. We also evaluated the variations in operational variables on injecting Hydrogen into the natural gas pipeline networks at varying fractions. The study further develops a multi-objective optimization model that includes bi-objective and tri-objective problems and is optimized using ACO. Traditional studies have focused on single-objective optimization with minimal bi-objective issues. In addition, none of the earlier research has shown the effect of introducing Hydrogen to the NG network using tri-objective function evaluations. The bi-objective and tri-objective functions help evaluate the effect of injecting Hydrogen on different operational parameters. The study further attempts to fill the gap by detailing the modelling equations implemented through a bi-objective and tri-objective function for the H-NG pipeline network and optimized through ACO. Pareto fronts that show the tradeoff between the different objectives for the multi-objective problem have been generated. The primary objective of the bi-objective and tri-objective optimization problems is maximizing hydrogen mole percent in natural gas. The other objective chosen is minimizing compressor fuel consumption and maximizing delivery pressure, throughput, and power delivered at the delivery station. The findings will serve as a roadmap for pipeline operators interested in repurposing natural gas pipeline networks to transport hydrogen and natural gas blend (H-NG) and seeking to reduce carbon intensity per unit of energy-delivered fuel.     

Development of Oshawa hydrogen hub in Canada: A case study

Consumption of fossil fuels, which makes an immense contribution to greenhouse gas emissions, must be reduced. Hydrogen emerges as a unique solution to serve as fuel, energy carrier and feedstock because it is a clean, abundant, environmentally friendly and energy intensive gas. This study aims to investigate the development of a potential hydrogen hub located in Oshawa, Canada, which is aimed to provide a hydrogen infrastructure for future hydrogen economy. Numerous life cycle assessment and cost assessment studies are conducted to investigate what benefits such a hydrogen will bring to the city. The results show that fuel cell electric buses emit 89% fewer pollutants. Also, 60% of overall CO₂ reduction is possible with a gradual transition to fuel cell technology within 20 years. However, in order for hydrogen infrastructure and costs to compete with fossil fuels, high-scale projects need to be developed with governmental incentives.     

Investigation of a novel & integrated simulation model for hydrogen production from lignocellulosic biomass

Process simulation and modeling works are very important to determine novel design and operation conditions. In this study; hydrogen production from synthesis gas obtained by gasification of lignocellulosic biomass is investigated. The main motivation of this work is to understand how biomass is converted to hydrogen rich synthesis gas and its environmentally friendly impact. Hydrogen market development in several energy production units such as fuel cells is another motivation to realize these kinds of activities. The initial results can help to contribute to the literature and widen our experience on utilization of the CO₂ neutral biomass sources and gasification technology which can develop the design of hydrogen production processes. The raw syngas is obtained via staged gasification of biomass, using bubbling fluidized bed technology with secondary agents; then it is cleaned, its hydrocarbon content is reformed, CO content is shifted (WGS) and finally H₂ content is separated by the PSA (Pressure Swing Adsorption) unit. According to the preliminary results of the ASPEN HYSYS conceptual process simulation model; the composition of hydrogen rich gas (0.62% H₂O, 38.83% H₂, 1.65% CO, 26.13% CO₂, 0.08% CH₄, and 32.69% N₂) has been determined. The first simulation results show that the hydrogen purity of the product gas after PSA unit is 99.999% approximately. The mass lower heating value (LHV_mass) of the product gas before PSA unit is expected to be about 4500 kJ/kg and the overall fuel processor efficiency has been calculated as ～93%.     

The economic feasibility study of a 100-MW Power-to-Gas plant

Power-to-Gas (PtG) is a grid-scale energy storage technology by which electricity is converted into gas fuel as an energy carrier. PtG utilizes surplus renewable electricity to generate hydrogen from Solid-Oxide-Cell, and the hydrogen is then combined with CO₂ in the Sabatier process to produce the methane. The transportation of methane is mature and energy-efficient within the existing natural gas pipeline or town gas network. Additionally, it is ideal to make use of the reverse function of SOC, the Solid-Oxide-Fuel-Cell, to generate electricity when the grid is weak in power. This study estimated the cost of building a hypothetical 100-MW PtG power plant with energy storage and power generation capabilities. The emphasis is on the effects of SOC cost, fuel cost and capacity factor to the Levelized Cost of Energy of the PtG plant. The net present value of the plant is analyzed to estimate the lowest affordable contract price to secure a positive present value. Besides, the plant payback period and CO₂ emission are estimated.     

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.