Publications

The necessity for transitioning to renewable energy sources and the intermittent nature of the natural variables lead to the integration of storage units into these projects. In this research paper wind turbines and solar modules are combined with pumped hydro storage batteries and green hydrogen. Energy management strategies are described for five different scenarios of hybrid renewable energy systems based on single or hybrid storage technologies. The motivation is driven by grid stability issues and the limited access to fresh water in the Greek islands. A RES-based desalination unit is introduced into the hybrid system for access to low-cost fresh water. The comparison of single and hybrid storage methods the exploitation of seawater for the simultaneous fulfillment of water for domestic and agricultural purposes and the evaluation of different energy economic and environmental indices are the innovative aspects of this research work. The results show that pumped hydro storage systems can cover the energy and water demand at the minimum possible price 0.215 EUR/kWh and 1.257 EUR/m3 while hybrid storage technologies provide better results in the loss of load probability payback period and CO2 emissions. For the pumped hydro– hydrogen hybrid storage system these values are 21.40% 10.87 years and 2297 tn/year respectively.

In light of offshore wind expansions in the North and Baltic Seas in Europe further ideas on using offshore space for renewable-based energy generation have evolved. One of the concepts is that of energy islands which entails the placement of energy conversion and storage equipment near offshore wind farms. Offshore placement of electrolysers will cause interdependence between the availability of electricity for hydrogen production and for power transmission to shore. This paper investigates the trade-offs between integrating energy islands via electricity versus hydrogen infrastructure. We set up a combined capacity expansion and electricity dispatch model to assess the role of electrolysers and electricity cables given the availability of renewable energy from the islands. We find that the electricity system benefits more from connecting close-to-shore wind farms via power cables. In turn electrolysis is more valuable for far-away energy islands as it avoids expensive long-distance cable infrastructure. We also find that capacity investment in electrolysers is sensitive to hydrogen prices but less to carbon prices. The onshore network and congestion caused by increased activity close to shore influence the sizing and siting of electrolysers.

Traditional charging stations have a single function which usually does not consider the construction of energy storage facilities and it is difficult to promote the consumption of new energy. With the gradual increase in the number of new energy vehicles (NEVs) to give full play to the complementary advantages of source-load resources and provide safe efficient and economical energy supply services this paper proposes the optimal operation strategy of a PV-charging-hydrogenation composite energy station (CES) that considers demand response (DR). Firstly the operation mode of the CES is analyzed and the CES model including a photovoltaic power generation system fuel cell hydrogen production hydrogen storage hydrogenation and charging is established. The purpose is to provide energy supply services for electric vehicles (EVs) and hydrogen fuel cell vehicles (HFCVs) at the same time. Secondly according to the travel law of EVs and HFCVs the distribution of charging demand and hydrogenation demand at different periods of the day is simulated by the Monte Carlo method. On this basis the following two demand response models are established: charging load demand response based on the price elasticity matrix and interruptible load demand response based on incentives. Finally a multi-objective optimal operation model considering DR is proposed to minimize the comprehensive operating cost and load fluctuation of CES and the maximum–minimum method and analytic hierarchy process (AHP) are used to transform this into a linearly weighted single-objective function which is solved via an improved moth–flame optimization algorithm (IMFO). Through the simulation examples operation results in four different scenarios are obtained. Compared with a situation not considering DR the operation strategy proposed in this paper can reduce the comprehensive operation cost of CES by CNY 1051.5 and reduce the load fluctuation by 17.8% which verifies the effectiveness of the proposed model. In addition the impact of solar radiation and energy recharge demand changes on operations was also studied and the resulting data show that CES operations were more sensitive to energy recharge demand changes.

Hydrogen will be important in decarbonized energy systems. The primary ways to produce low emission hydrogen are from renewable electricity using electrolyzers called green hydrogen and by reforming natural gas and capturing and storing the CO2 known as blue hydrogen. In this study the degrees to which blue and green hydrogen are complementary or competitive are analyzed through a sensitivity analysis on the electrolyzer costs and natural gas price. This analysis is performed on four bases: what is the cost-effective relative share between blue and green hydrogen deployment how their deployment influences the price of hydrogen how the price of CO2 changes with the deployment of these two technologies and whether infrastructure can economically be shared between these two technologies. The results show that the choice of green and blue hydrogen has a tremendous impact where an early deployment of green leads to higher hydrogen costs and CO2 prices in 2030. Allowing for blue hydrogen thus has notable benefits in 2030 giving cheaper hydrogen with smaller wider socioeconomic impacts. In the long term these competitive aspects disappear and green and blue hydrogen can coexist in the European market without negatively influencing one another.

The utilization of hydrogen fuel in gas turbines brings significant changes to the thermophysical properties of flue gas including higher specific heat capacities and an enhanced steam content. Therefore hydrogen-fueled gas turbines are susceptible to health degradation in the form of steam-induced corrosion and erosion in the hot gas path. In this context the fault diagnosis of hydrogen-fueled gas turbines becomes indispensable. To the authors’ knowledge there is a scarcity of fault diagnosis studies for retrofitted gas turbines considering hydrogen as a potential fuel. The present study however develops an artificial neural network (ANN)-based fault diagnosis model using the MATLAB environment. Prior to the fault detection isolation and identification modules physics-based performance data of a 100 kW micro gas turbine (MGT) were synthesized using the GasTurb tool. An ANN-based classification algorithm showed a 96.2% classification accuracy for the fault detection and isolation. Moreover the feedforward neural network-based regression algorithm showed quite good training testing and validation accuracies in terms of the root mean square error (RMSE). The study revealed that the presence of hydrogen-induced corrosion faults (both as a single corrosion fault or as simultaneous fouling and corrosion) led to false alarms thereby prompting other incorrect faults during the fault detection and isolation modules. Additionally the performance of the fault identification module for the hydrogen fuel scenario was found to be marginally lower than that of the natural gas case due to assumption of small magnitudes of faults arising from hydrogen-induced corrosion.

Beyond its role as an energy vector a growing number of natural hydrogen sources and reservoirs are being discovered all over the globe which could represent a clean energy source. Although the hydrogen amounts in reservoirs are uncertain they could be vast and they could help decarbonize energy-intensive economic sectors and facilitate the energy transition. Natural hydrogen is mainly produced through a geochemical process known as serpentinization which involves the reaction of water with low-silica ferrous minerals. In favorable locations the hydrogen produced can become trapped by impermeable rocks on its way to the atmosphere forming a reservoir. The safe exploitation of numerous natural hydrogen reservoirs seems feasible with current technology and several demonstration plants are being commissioned. Natural hydrogen may show variable composition and require custom separation purification storage and distribution facilities depending on the location and intended use. By investing in research in the mid-term more hydrogen sources could become exploitable and geochemical processes could be artificially stimulated in new locations. In the long term it may be possible to leverage or engineer the interplay between microorganisms and geological substrates to obtain hydrogen and other chemicals in a sustainable manner.

This report presents an analysis of how hydrogen and battery technologies are likely to be utilised in different sectors within the UK including transportation manufacturing the built environment and power. In particular the report compares the use of hydrogen and battery technology across these sectors. In addition it evaluates where these technologies will be in competition where one technology will dominate and where a combination of the two may be used. This sector analysis draws on DNV’s knowledge and experience within both the battery and hydrogen industries along with a review of studies available in the public domain. The analysis has been incorporated into DNV’s Energy Transition Outlook model an integrated system-dynamics simulation model covering the energy system which provides an independent view of the energy outlook from now until 2050. The modelling which includes data on costs demand supply policy population and economic indicators enables the non-linear interdependencies between different parameters to be considered so that decisions made in one sector influence the decision made in another.

A compact wireless near-field hydrogen gas sensor is proposed which detects leaking hydrogen near its source to achieve fast responses and high reliability. A semiconductor-type sensing element is implemented in the sensor which can provide a significant response in 100 ms when stimulated by pure hydrogen. The overall response time is shortened by orders of magnitude compared to conventional sensors according to simulation results which will be within 200 ms compared with over 25 s for spatial concentration sensors under the worst conditions. Over 1 year maintenance intervals are enabled by wireless design based on the Bluetooth low energy protocol. The average energy consumption during a single alarm process is 153 µJ/s. The whole sensor is integrated on a 20 × 26 mm circuit board for compact use.

Ever more stringent emission regulations for vehicles encourage increasing numbers of battery electric vehicles on the roads. A drawback of storing electric energy in a battery is the comparable low energy density low driving range and the higher propensity to deplete the energy storage before reaching the destination especially at low ambient temperatures. When the battery is depleted stranded vehicles can either be towed or recharged with a mobile recharging station. Several technologies of mobile recharging stations already exist however most of them use fossil fuels to recharge battery electric vehicles. The proposed novel zero emission solution for mobile charging is a combined high voltage battery and hydrogen fuel cell charging station. Due to the thermal characteristics of the fuel cell and high voltage battery (which allow only comparable low coolant temperatures) the thermal design for this specific application (available heat exchanger area zero vehicle speed air flow direction) becomes challenging and is addressed in this work. Experimental methods were used to obtain reliable thermal and electric power measurement data of a 30 kW fuel cell system which is used in the Mobile Hydrogen Powersupply. Subsequently simulation methods were applied for the thermal design and optimisation of the coolant circuits and heat exchangers. It is shown that an battery electric vehicle charging power of 22 kW requires a heat exchanger area of 1 m2 of which 60 % is used by the fuel cell heat exchanger and the remainder by the battery heat exchanger to achieve steady state operation at the highest possible ambient temperature of 436 °C. Furthermore the simulation showed that when the charging power of 22 kW is solely provided by the high voltage battery the highest possible ambient temperature is 42 °C. When the charging power is decreased operation up to the maximum ambient temperatures of 45 °C can be achieved. The results of maximum charging power and limiting ambient temperature give insights for further system improvements which are: sizing of fuel cell or battery trailer design and heat exchanger area operation strategy of the system (power split between high voltage battery and fuel cell) as well as possible dynamic operation scenarios.

The Paris Agreement aims to limit global warming and one of the most polluting sectors is heavy industry where cement production is a significant contributor. This work briefly explores some alternatives recycling reducing clinker content waste heat recovery and carbon capture discussing their advantages and drawbacks. Then it examines the economic viability and benefits of increasing oxygen concentration in the primary burning air from 21 to 27 vol.% which could improve clinker production by 7% and the production of hydrogen through PEM electrolysis to make up 5% of the fuel thermal fraction considering both in a cement plant producing 3000 tons of clinker per day. This analysis used reference values from Secil an international company for cement and building materials to determine the required scale of the oxygen and hydrogen production respectively and calculate the CAPEX of each approach. It is concluded that oxygen enrichment can provide substantial fuel savings for a relatively low cost despite a possible significant increase in NOx emissions. However hydrogen production at this scale is not currently economically viable.