Investigating Cost Effective Pathways for Blue Hydrogen Production in Alberta

Large amounts of hydrogen are used in many industries in Alberta, the most significant of which is upgrading of bitumen into synthetic crude oil. Hydrogen also plays a large role in the recent Natural Gas Strategy, which aims to support diversification of the Alberta economy by growing the low carbon intensity energy sector. Because current hydrogen (H2) production is responsible for a substantial share of the greenhouse emissions from oil sands operations in Alberta, applying carbon capture and storage (CCS) to H2 production to make what is becoming known as “blue H2” would both significantly reduce the province’s emissions and unlock new opportunities for the current industry. In this thesis, I evaluate the trade-offs between location and scale of blue H2 production to decarbonize Oil Sands mining operations under different future emissions prices. I develop new cost models for steam-methane reforming (SMR) and autothermal reforming (ATR) units incorporating CCS that allow estimation of production cost and life-cycle emissions for facilities in Alberta. I also expand an existing CO2 pipeline model to be usable for H2 pipelines, and use this to estimate the cost and environmental trade-offs between moving CO2 and H2. I apply these models to compare the cost of production of blue H2 near Edmonton (with transport of H2 north and local CO2 storage) to production in Fort MacMurray (and transport of CO2 south for storage) for two different demand scenarios. Results from these models show that SMR and ATR plants capturing upwards of 90% of total direct emissions have a comparable production cost of $1.6/kgH2 (USD) at a scale of 350 tH2/day. This represents a 60% increase in cost compared to an SMR without capture. However, considering the full life cycle, the estimated cost of CO2 avoided for the SMR plant ($80/tCO2eq) are lower than for the ATR (90 $/tCO2eq) due to the Alberta electricity grid. The unit cost of moving H2 is several times that of CO2, owing to the lower (gaseous) density of H2. However, normalized to production of one kilogram of hydrogen, the costs of transport are comparable for an optimized system. The scenario analysis suggests constructing SMR with post-combustion capture in Fort MacMurray is the lowest cost option when a 170 $/tCO2 (CAD) carbon tax is applied to the full chain life cycle emissions.

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