Publications

An understanding of heating technologies from the consumers’ perspective is critical to ensure low-carbon technologies are adopted for reducing their current associated emissions. Existing studies from the consumers’ perspective do not compare and optimise the full range and combinations of potential heating systems. There is also little consideration of how spatiotemporal and dwelling variations combined alter the economic and environmental effectiveness of technologies. The novelty of this paper is the creation and use of a new comprehensive framework to capture the range of heating technologies and their viability for any specific dwelling’s traits and climate from customers’ perspective which is missing from current studies. The model optimises combinations of prime heaters energy sources ancillary solar technologies and sizes thermal energy storage sizes and tariffs with hourly heating simulation across a year and compares their operation capital and lifetime costs alongside emissions to realise the true preferential heating systems for customers which could be used by various stakeholders. Using the UK as a case study the results show electrified heating is generally the optimum lifetime cost solution mainly from air source heat pumps coupled with photovoltaics. However direct electrical heating becomes more economically viable as dwelling demands reduce from smaller dwellings or warmer climates as shorter durations of the ownership are considered or with capital cost constraints from lower income households. Understanding this is of high importance as without correctly targeted incentives a larger uptake of direct electrical heating may occur which will burden the electrical network and generation to a greater extent than more efficient heat pumps.

The transformation of hydrogen metallurgy is a principal means of promoting the iron and steel industry (ISI) in reaching peak and deep emissions reduction. However the environmental impact of different hydrogen production paths on hydrogen metallurgy has not been systemically discussed. To address this gap based on Long-range Energy Alternatives Planning System (LEAP) this paper constructs a bottom-up energy system model that includes hydrogen production iron and steel (IS) production and power generation. By setting three hydrogen production structure development paths namely the baseline scenario business-as-usual (BAU) scenario and clean power (CP) scenario the carbon dioxide (CO2) emissions impact of different hydrogen production paths on hydrogen metallurgy is carefully evaluated from the perspective of the whole industry and each IS production process. The results show that under the baseline scenario the hydrogen metallurgy transition will help the CO2 emissions of ISI peak at 2.19 billion tons in 2024 compared to 2.08 billion tons in 2020 and then gradually decrease to 0.78 billion tons in 2050. However different hydrogen production paths will contribute to the reduction or inhibit the reduction. In 2050 the development of electrolysis hydrogen production with renewable electricity will reduce CO2 emissions by an additional 48.76 million tons (under the CP scenario) while the hydrogen production mainly based on coal gasification and methane reforming will increase the additional 50.04 million tons CO2 emissions (under the BAU scenario). Moreover under the hydrogen production structure relying mainly on fossil and industrial by-products the technological transformation of blast furnace ironmaking with hydrogen injections will leak carbon emissions to the upstream energy processing and conversion process. Furthermore except for the 100% scrap based electric arc furnace (EAF) process the IS production process on hydrogen-rich shaft furnace direct reduced iron (hydrogen-rich DRI) have lower CO2 emissions than other processes. Therefore developing hydrogen-rich DRI will help the EAF steelmaking development to efficiently reduce CO2 emissions under scrap constraints.

This episode examines how we are tackling a sustainable future – with Net Zero hurtling towards us at great pace. We’re around a year on from the pledges made at COP26 the UK’s Green Recovery initiative is well under way and by next year Britain is aiming to blend up to 20 per cent hydrogen into its gas networks. So now is the time to continue to unlock new insight and understand further the realities of both the challenges and opportunities ahead.

The podcast can be found here.

Worldwide energy systems are experiencing a transition to more sustainable systems. According to the Hydrogen Roadmap Europe (FCH EU 2019) hydrogen will play an important role in future energy systems due to its ability to support sustainability goals and will account for approximately 13% of the total energy mix in the coming future. Correct hydrogen supply chain (HSC) planning is therefore vital to enable a sustainable transition. However due to the operational characteristics of the HSC its planning is complicated. Renewable hydrogen supply can be diverse: Hydrogen can be produced de-centrally with renewables such as wind and solar energy or centrally by using electricity generated from a hydro power plant with a large volume. Similarly demand for hydrogen can also be diverse with many new applications such as fuels for fuel cell electrical vehicles and electricity generation feedstocks in industrial processes and heating for buildings. The HSC consists of various stages (production storage distribution and applications) in different forms with strong interdependencies which further increase HSC complexity. Finally planning of an HSC depends on the status of hydrogen adoption and market development and on how mature technologies are and both factors are characterised by high uncertainties. Directly adapting the traditional approaches of supply chain planning for HSCs is insufficient. Therefore in this study we develop a planning matrix with related planning tasks leveraging a systematic literature review to cope with the characteristics of HSCs. We focus only on renewable hydrogen due to its relevance to the future low-carbon economy. Furthermore we outline an agenda for future research from the supply chain management perspective in order to support HSC development considering the different phases of HSCs adoption and market development.

Kazakhstan has long been regarded as a major exporter of fossil fuel energy. As the global energy sector is undergoing an unprecedented transition to low-carbon solutions new emerging energy technologies such as hydrogen production require more different resource bases than present energy technologies. Kazakhstan needs to consider whether it has enough resources to stay competitive in energy markets undergoing an energy transition. Green hydrogen can be made from water electrolysis powered by low-carbon electricity sources such as wind turbines and solar panels. We provided the first resource assessment for green hydrogen production in Kazakhstan by focusing on three essential resources: water renewable electricity and critical raw materials. Our estimations showed that with the current plan of Kazakhstan to keep its water budget constant in the future producing 2–10 Mt green hydrogen would require reducing the water use of industry in Kazakhstan by 0.6–3% or 0.036–0.18 km3/year. This could be implemented by increasing the share of renewables in electricity generation and phasing out some of the water- and carbon-intensive industries. Renewable electricity potential in South and West Kazakhstan is sufficient to run electrolyzers up to 5700 and 1600 h/year for wind turbines and solar panels respectively. In our base case scenario 5 Mt green hydrogen production would require 50 GW solar and 67 GW wind capacity considering Kazakhstan's wind and solar capacity factors. This could convert into 28652 tons of nickel 15832 tons of titanium and many other critical raw materials. Although our estimations for critical raw materials were based on limited geological data Kazakhstan has access to the most critical raw materials to support original equipment manufacturers of low-carbon technologies in Kazakhstan and other countries. As new geologic exploration kicks off in Kazakhstan it is expected that more deposits of critical raw materials will be discovered to respond to their potential future needs for green hydrogen production.

The existing literature on the hydrogen supply chains has knowledge gaps. Most studies focus on hydrogen production storage transport and utilisation but neglect ports which are nexuses in the supply chains. To fill the gap this paper focuses on ports' readiness for the upcoming hydrogen international trade. Potential hydrogen exporting and importing ports are screened. Ports' readiness for hydrogen export and import are reviewed from perspectives of infrastructure risk management public acceptance regulations and standards and education and training. The main findings are: (1) liquid hydrogen ammonia methanol and LOHCs are suitable forms for hydrogen international trade; (2) twenty ports are identified that could be first movers; among them twelve are exporting ports and eight are importing ports; (3) ports’ readiness for hydrogen international trade is still in its infancy and the infrastructure construction or renovation risk management measures establishment of regulations and standards education and training all require further efforts.

Hydrogen is regarded as a flexible energy carrier with multiple applications across several sectors. For instance it can be used in industrial processes transports heating and electrical power generation. Green hydrogen produced from renewable sources can have a crucial role in the pathway towards global decarbonization. However the success of green hydrogen production ultimately depends on its economic sustainability. In this context this work evaluates the economic performance of a hydrogen power plant participating in the electricity market and supplying multiple hydrogen consumers. The analysis includes technical and economical details of the main components of the hydrogen power plant. Its operation is simulated using six different scenarios which admit the production of either grey or green hydrogen. The scenarios used for the analysis include data from the Iberian electricity market for the Portuguese hub. An important conclusion is that the combination of multiple services in a hydrogen power plant has a positive effect on its economic performance. However as of today consumers who would wish to acquire green hydrogen would have to be willing to pay higher prices to compensate for the shorter periods of operation of hydrogen power plants and for their intrinsic losses. Nonetheless an increase in green hydrogen demand based on a greater environmental awareness can lead to the need to not only build more of these facilities but also to integrate more services into them. This could promote the investment in hydrogen-related technologies and result in changes in capital and operating costs of key components of these plants which are necessary to bring down production costs.

The blending of hydrogen gas into natural gas pipelines is an effective way of achieving the goal of carbon neutrality. Due to the large differences in the calorific values of natural gas from different sources the calorific value of natural gas after mixing with hydrogen may not meet the quality requirements of natural gas and the quality of natural gas entering long-distance natural gas and urban gas pipelines also has different requirements. Therefore it is necessary to study the effect of multiple gas sources and different pipe network types on the differences in the calorific values of natural gas following hydrogen admixing. In this regard this study aimed to determine the quality requirements and proportions of hydrogen-mixed gas in natural gas pipelines at home and abroad and systematically determined the quality requirements for natural gas entering both long-distance natural gas and urban gas pipelines in combination with national standards. Taking the real calorific values of the gas supply cycle of seven atmospheric sources as an example the calorific and Wobbe Index values for different hydrogen admixture ratios in a one-year cycle were calculated. The results showed that under the requirement of natural gas interchangeability there were great differences in the proportions of natural gas mixed with hydrogen from different gas sources. When determining the proportion of hydrogen mixed with natural gas both the factors of different gas sources and the factors of the gas supply cycle should be considered.

Steam methane reforming (SMR) is the dominant process for hydrogen production which produce large amount of carbon dioxide (CO2) as a by-product. To address concerns about carbon emissions there is an increasing focus on blue hydrogen to mitigate carbon emissions during hydrogen production. However the commercialization of blue hydrogen production (BHP) is hindered by the challenges of high cost and energy consumption. This study proposes a new configuration to address these challenges which is characterized by: (a) the use of piperazine (PZ) as a solvent which has a high CO2 absorption efficiency; (b) a more efficient heat exchange configuration which recovers the waste exergy from flue gas; (c) the advanced flash stripper (AFS) was adopted to reduce the capital cost due to its simpler stripper configuration. In addition the technical and economic performance of the proposed energy and cost-saving blue hydrogen production (ECSB) process is investigated and compared with the standard SMR process. The detailed models of the SMR process and the post-combustion carbon capture (PCC) process were developed and integrated in Aspen plus® V11. The results of the technical analysis showed that the ECSB process with 30 wt.% PZ achieves a 36.3 % reduction in energy penalty when compared to the standard process with 30 wt.% Monoethanolamine (MEA). The results of the economic analysis showed that the lowest levelized cost of blue hydrogen (LCBH) was achieved by the ECSB process with 30 wt.% PZ. Compared to the BHP process with 30 wt.% MEA the LCBH was reduced by 19.7 %.

This paper introduces the concept of a thermal management system (TMS) with integrated on-board power generation capabilities for a Mach 8 hypersonic aircraft powered by liquid hydrogen (LH2). This work developed within the EU-funded STRATOFLY Project aims to demonstrate an opportunity for facing the challenges of hypersonic flight for civil applications mainly dealing with thermal and environmental control as well as propellant distribution and on-board power generation adopting a highly integrated plant characterized by a multi-functional architecture. The TMS concept described in this paper makes benefit of the connection between the propellant storage and distribution subsystems of the aircraft to exploit hydrogen vapors and liquid flow as the means to drive a thermodynamic cycle able on one hand to ensure engine feed and thermal control of the cabin environment while providing on the other hand the necessary power for other on-board systems and utilities especially during the operation of high-speed propulsion plants which cannot host traditional generators. The system layout inspired by concepts studied within precursor EU-funded projects is detailed and modified in order to suggest an operable solution that can be installed on-board the reference aircraft with focus on those interfaces impacting its performance requirements and integration features as part of the overall systems architecture of the plane. Analysis and modeling of the system is performed and the main results in terms of performance along the reference mission profile are discussed.