Techno-economic assessment of dispatchable hydrogen production by multiple electrolysers in Libya

With the worldwide growth of renewable energy generation, the value of hydrogen production by electrolysis as a demand management tool for electricity networks is likely to increase. Electrolytic hydrogen can be sold as a fuel, chemical feedstock or injected into pipelines to lower the carbon content of natural gas. The main obstacle to hydrogen's use as a fuel or energy storage method is the price. The highest costs are in the capital expenditure and the consumption of feedstock (electricity and water). In this paper, three major techno-economic aspects of the system are investigated, including technical analyses of both the energy absorbed by the process in the provision of electricity demand management services and in its meeting of fuel demand, plus an economic assessment of the hydrogen price at the at the point of sale. Thus, the study investigates how only off-peak electricity is used to produce hydrogen via onsite electrolysis at a number of garage forecourts. In a simulated case study, six garage forecourts are assumed to be sited in Darnah, a small city on the east coast of Libya. An electricity pricing mechanism is devised to allow the energy producer (utility company) and energy consumer (garage forecourt operator) to make a profit. Short term (2015) and long term (2030) cost scenarios are applied. Matlab software was used to simulate this process. Without any government support or changes in regulation and policy, hydrogen prices were 10.00 pound/kg, 9.80 pound/kg, 9.60 pound/kg, 10.00 pound/kg, 9.40 pound/kg and 10.30 pound/kg for forecourts 1-6 respectively under the 2015 cost scenario. The electricity price represents around 17% of the total hydrogen cost, whereas, due to the investment cost reduction in 2030, the average prices of hydrogen dropped to 6.50 pound/kg, 6.60 pound/kg, 6.30 pound/kg, 6.40 pound/kg, 6.20 pound/kg and 6.50 pound/kg for stations 1-6 respectively. The feedstock cost share became 44% in the 2030 cost scenario. Nearly 53.91% and 53.77% of available energy is absorbed in short and long term scenarios respectively. Under the long term cost scenario, 65% of hydrogen demand can be met, whereas less than 60% of hydrogen demand is met under the short term scenario. The system reliability (i.e. the meeting of hydrogen fuel demand) is quite low due to the operational mode of the system. Increasing the system size (mainly electrolyser production capacity) can clearly improve the system reliability. (C) 2018 Elsevier Ltd. All rights reserved.