ӣ��Ӱ��

Topic

Regenerative green hydrogen energy storage modelling for remote northern microgrids

Department of Mechanical Engineering

Date & location

• Tuesday, November 25, 2025

• 10:00 A.M.

• MacLaurin Building, room D202h

• And Virtual Defence

Reviewers

Supervisory Committee

• Dr. Curran Crawford, Mechanical Engineering, ӣ��Ӱ�� (Supervisor)

• Dr. Michael Ross, Faculty of Applied Science and Management, UVic (Non-Unit Member)

• Dr. Martha Lenio, Solvest Inc. (Non-Unit Member) 

External Examiner

• Dr. Andrew Rowe, Department of Mechanical Engineering, ӣ��Ӱ�� 

Chair of Oral Examination

• Dr. Kathy Gaul, School of Exercise Science, Physical and Health Education, UVic 

Abstract

Remote Arctic communities in Canada face significant challenges in transitioning from diesel-dependent energy systems to renewable alternatives. While wind, solar, and battery technologies enable successful renewable energy integration, exceeding penetration levels above approximately 60% often requires long-duration energy storage beyond the capabilities of battery technologies. This thesis presents a comprehensive modelling framework for regenerative green hydrogen energy storage within microgrids, addressing critical gaps in energy planning for Arctic communities. This model is then employed to evaluate the potential of green hydrogen energy storage to support Arctic microgrids on the pathway to 100% REP using a community case study based on the Hamlet of Sanirajak, Nunavut.

The model demonstrates the feasibility and performance characteristics of hydrogen storage in this Arctic context. Key findings include: (1) significant thermal resilience of the modeled hydrogen system with 40 hours of thermal autonomy, substantial waste heat generation (284,206 kWh annually), and advantages of operation in Arctic climates compared to warm climates; (2) dynamics-based degradation pre dictions of 3.2% and 1.7% annually for the electrolyzer and fuel cell respectively which are comparable to manufacturer estimates; and (3) water demand of hydro gen storage representing less than 1% of projected 2035 community water consumption. Further, comparative analysis across different modelling timescales indicated that while hourly modelling may miss some of the operational nuances of this storage technology, operational constraints largely compensate for dispatch discrepancies. Case study simulations then evaluated the least-cost designs for REP targets from 50% to 100%, comparing scenarios with and without hydrogen energy storage. The analysis incorporated operational limitations including minimum load ratio, ramping, and compression requirements, as well as a cost sensitivity analysis. Results demonstrate that hydrogen energy storage becomes economically attractive above 65% REP, providing substantial cost savings at high REP by reducing renewable generation over-sizing requirements. However, the model showed that technological limitations such as minimum loading of fuel cells, may limit cost-effective achievement of 100% REP. Beyond economic benefits, this research also identifies practical implementation challenges including harsh environmental conditions, logistical constraints, and local capacity.

The model provides community planners and energy operators with novel insights into hydrogen technology performance and operational considerations specific to Arc tic microgrid applications. The high level analysis offers contributions to the field by uncovering hydrogen’s potential role in Arctic microgrid decarbonization and identifying key technological and practical barriers that must be addressed for successful implementation.