Tekno-ekonomisk modellering och optimering av ett vätgastransmissionssystem med integrerad lagring i norrbotten

Sammanfattning

The green transition of Sweden's energy system requires extensive electrification and the development of new infrastructure for the production, storage, and distribution of energy. Green hydrogen has been identified as a key component in this transition, particularly within sectors that are difficult to electrify directly. To enable the cost-effective and safe use of hydrogen, both transmission systems and storage solutions are needed that are technically feasible and economically viable. This master's thesis aim was to investigate the need for storage capacity within a hydrogen transmission system and to analyze which storage technology was the most cost-effective from a technical and economic perspective. The case study used for achieving these objectives was informed by the Power2Earth-project in the north of Sweden. The Power2Earth-project consists of a whole hydrogen value chain, in which green hydrogen is produced via electrolysis and transported through a pipeline to a fossil-free ammonia and fertilizer plant. To answer the research questions, a literature review was conducted on hydrogen storage technologies and the components of a transmission system for hydrogen. A techno-economic model was developed in Python that simulated hydrogen production with electricity from a wind farm and the power grid, hydrogen compression, hydrogen storage and transmission of hydrogen over a year with hourly resolution. The storage module was designed to allow users to select the preferred storage technology. The model was designed to optimize the installed capacities within the transmission system and the hourly dispatch of hydrogen flows using the optimization tool Gurobi. The objective function of the model was to minimize the Net Present Cost of the transmission system over the project period. The results were also presented as Levelized Cost of Transmission (LCOT) and Levelized Cost of Storage (LCOS). Two storage technologies were selected for the techno-economic analysis: Lined Rock Cavern (LRC) and Unlined Rock Cavern (URC). The results showed that the scenario with URC yielded both the lowest LCOT and LCOS, mainly because the hydrogen could be injected into the storage without additional compression. The LRC scenario required higher operating pressure in the storage, leading to an increased electricity consumption and higher compressor costs. The results also indicated that the linepack flexibility were used as a short-term buffer, while the external hydrogen storage were primarily used for long-term hydrogen storage. The model demonstrated that the choice of storage technology significantly impacted the total system cost. The results provided a possible decision basis for future investments in hydrogen infrastructure and the conclusion highlighted the importance of dimensioning storage capacity in relation to electricity prices, hydrogen production availability and consumption patterns.