Poster Session

Category: Transport and Storage

Depleted Reservoir Storage: Mixing of Hydrogen and Cushion Gas

Depleted reservoir storage offers potentially game-changing cost savings relative to salt cavern storage. However, before depleted reservoir storage may be attempted at commercial or even pilot scales, de-risking efforts must be pursued. In particular, H2 storage in depleted reservoirs entails a number of possible loss mechanisms. These include geochemical reaction, biological conversion, leakage and mixing with resident cushion gas. In this research project, we consider the latter two mechanisms focusing, in particular, on their interconnection. We thereby develop a theoretical fluid mechanics-based model that considers the buoyancy-driven flow of an injectate (H2 plume) into a uniform, saturated porous medium. Mimicking punctured cap-rock, the porous medium is supposed to be bounded above by a barrier containing discrete fissures. Leakage and vertical migration therefore ensue when the H2 plume encounters these fissures. As H2 draining becomes more severe, there develops, at the leading edge of the plume, a mixed region consisting of H2 and cushion gas intermingled through process of porous media dispersion. Thick mixed regions are economically-disadvantageous because they represent irreversible losses of H2 to the formation. It is imperative, therefore, that mixed region thicknesses be quantified. Through our developed model, we demonstrate that these thicknesses are strong functions of the H2 injection conditions, the slope of the barrier layer and the fissure permeability, width and length.

Predictions made by our theoretical model are confirmed by comparison against numerical simulations. The simulations in question are performed using COMSOL and provide a detailed dynamical description of the flow that is unencumbered by the limiting assumptions of the theoretical model. Thus are we able to determine parametric regimes where the theoretical model does (small to moderate leakage) vs. does not (large leakage) yield reliable predictions.

Our study concludes by making estimates of the rate of H2 loss by dispersive mixing for a possible H2 storage project in Europe that has been the subject of previous numerical study. We estimate that the dispersion loss fraction can easily exceed 5%, particularly for sufficiently large source injection flow rates and for sufficiently large fissure permeabilities.

Funding source: NSERC (Discovery Grant program)

Presented by:

Morris Flynn

Professor

University of Alberta 

Category: Transport & Storage

From Analytical instruments to a Net-Zero Economy in Canada

in Canada that have been serving research and development into the monitoring of CO2 storage.
The isotopic composition of the CO2 (δ13CCO2) has been demonstrated to be able to quantify CO2 trapping in numerous scenarios[2]. The Thermo Fisher Delta V isotope ratio mass spectrometer generates δ13CCO2 measurements at the highest precision. However, δ13CCO2 on its own can yield to ambiguous scientific results due to possible multiple sources of CO2 of different origins, making fingerprinting of the CO2 difficult[3].

Noble gas isotopes (He, Ne Ar, Kr, Xe) combined with δ13CCO2 to trace the fate of injected CO2 in large industrial settings have been first used in the Cranfield EOR field (MS, USA) in 2015[4]. Mass spectrometers such as the Thermo Fisher Helix SFT, the Helix MC and the ARGUS VI are top instruments for noble gas isotope ratio determinations. The Helix SFT has been used to quantify CO2/3He ratio of gases to establish the origin of CO2[5]. Elsewhere, high precision Ne isotope ratios carried by the CO2 obtained using a Thermo Fisher ARGUS VI suggested recent degassing of large amount of CO2[6].

Clumped isotopologue data of CO2 and CH4 are representative of the formation temperature of those molecules. The Thermo Fisher Ultra isotope ratio mass spectrometer can determine the clumped isotopologue of CH4. Clumped methane isotope data in combination with both stable and noble gas isotopes has been successfully used to identify quick microbial methanogenesis in hydrocarbon reservoirs during CO2 storage[5].

The state-of-the-art analytical instruments available for Canadian customers for the establishment of the isotopic fingerprint of CO2 stored in large-scale industrial CO2 projects, can contribute to preserving the global leadership of Canada in achieving a Net-Zero Economy by midcentury.

References
[1] Dion et al., 2021, Canadian Institute for Climate Choices.
[2] Raistrick et al., 2006, ACS 40(21).
[3] Gilfillan et al. 2008, GCA 72(4).
[4] Gyore et al., 2015, IJGGC 42.
[5] Tyne et al. 2021 Nature 600.
[6] Gyore et al. 2022, Goldschmidt Conf. paper 11393.

Presented by:

Domokos Gyore

Field Service Representative      

Isomass Scientific Inc

Category: End User

Hydrogen Diesel Dual Fuel Engine Efficiency and Emission Characterization

Globally, the need for clean combustion systems is gaining significant interest from both governments and individuals. This has resulted in the long standing norm use of fossil fuels as the primary source of energy for the transportation sector being challenged by many zero-carbon energy sources including battery electric, fuel cell and many alternative fuels. While electric passenger vehicles may seem like a viable alternative, in the heavy duty sector alternative fuels are desirable as they allow for increased energy density and vehicle range. By utilizing a dual fuel combustion method, a smooth transition from traditional diesel combustion to hydrogen combustion can be achieved. Allowing hydrogen infrastructure to naturally grow with demand. Even with the direct reduction in carbon dioxide emissions with increasing hydrogen amounts it is necessary to evaluate the hydrogen-diesel combustion process for not only current emissions regulations but also future reduction targets. Additionally, the combustion characteristics must be determined and compared to the baseline diesel combustion.

This work experimentally investigates hydrogen-diesel dual fuel combustion in a production diesel engine to explore how a retrofitted diesel engine may perform under dual-fuel operation.

The purpose of this study is to analyze the effect of a varied hydrogen-air fuel ratio on the steady-state combustion properties and emissions of a hydrogen-diesel dual fuel engine with a non-optimized combustion chamber geometry at various loads. NOx, soot, UHC and hydrogen slip emissions are investigated as well as the combustion stability, efficiency, and knock intensity. A production unthrottled Cummins 4.5 litre diesel Tier 3 Offroad engine was modified with a hydrogen port injector. No changes were made to the engine’s rotating assembly. The engine is operated from loads of 1 bar to 15 bar indicated mean effective pressure (IMEP) at 1500 rpm, at up to 1 bar of intake boost pressure. At high loads, hydrogen combustion is initiated with a pilot injection using the stock diesel direct injection system. At low loads, partially-premixed combustion is explored as a high-efficiency, low-emissions operation mode by early injection of diesel fuel. Hydrogen energy fraction is varied from 0 to 90%, at cycle fuel energies up to 3000 Joules. All operating points with hydrogen replacement were found to result in a CO2 emissions reduction relative to the amount of diesel fuel replaced. It was found that extremely lean hydrogen mixtures coupled with low diesel injection amounts resulted in low thermal efficiency and increased conversion of NO to NO2, but with a significant reduction in soot emissions as compared to pure diesel. As the mixture was enriched with increasing hydrogen amounts, efficiency increased significantly. Indicated efficiencies up to 10% greater than pure diesel operation were observed under high load hydrogen-enriched operation. At these high efficiency points, specific NOx emissions were increased up to 30% versus the comparable diesel operating point. At higher hydrogen replacement, the engine was able to exceed Tier 4 soot emissions without aftertreatment. With highly advanced diesel injection to promote premixed combustion, near-zero NOx emissions were achieved at loads up to 6 bar IMEP, with greatly increased CO and unburnt hydrocarbon emissions.

Presented by:

Jakub McNally  

Graduate Student Researcher    

University of Alberta

Category: Environment and Trade

Modelling of Production and Transportation Constraints on Future Hydrogen Pathways

There is a growing global consensus around the need to reduce greenhouse gas emissions to net zero by 2050 to address climate change. Many countries, including Canada, are making investments in building out low carbon hydrogen infrastructure as a pathway to decarbonize power, heat, and transportation domestically and for export.

Two likely methods for low carbon hydrogen production are via natural gas with carbon capture and storage and electrolysis of water with electricity generated from renewable energy, commonly referred to as blue and green, respectively. Currently, blue hydrogen is cheaper, but decreasing costs are expected to make green hydrogen competitive in the future. In Alberta, the possibility of creating blue hydrogen for export is an enticing opportunity because of the available carbon storage space and low natural gas costs. Despite this opportunity, there are gaps in the research for direct comparison between this hydrogen export pathway to other likely options. While several existing studies evaluate specific pathways, comparability across results requires harmonization of assumptions.

This research addresses this gap through a technoeconomic analysis of two scenarios: blue hydrogen production in Alberta compared to green hydrogen production in Australia, with a final export target in Japan. Australia is currently considered one of the best options in providing hydrogen for export, making it a good example for comparison to see if Alberta blue hydrogen is viable. Japan is the export target because of its high local hydrogen production cost and declared intent to import hydrogen. This technoeconomic model was created in Python. The data required for both pathways were mainly found from Canadian and Australian government sources, as well as academic literature. The cost of each pathway is analyzed in the present as well as up to 2050 with sensitivity analyses to determine how external factors address competitiveness.

For both pathways, this technoeconomic analysis includes the production of hydrogen and subsequent conversion to ammonia for transport. The ammonia is then transported by train to a port and then shipped to Japan for use. The full costs are included, and the biggest cost differences come from hydrogen production, train transportation distance, and policy differences between Canada and Australia.
Overall, the costs of blue hydrogen export from Canada were found to be lower currently compared to green hydrogen export from Australia. However, this changes in the future, with the Australia pathway reaching lower costs by 2050. This suggests that blue hydrogen export from Alberta may not be able to economically compete in the long term with other options and may only be a short-term solution to immediate energy needs. This conclusion will depend on the policy choices of respective governments, as certain policies may be created to reduce costs in one of the pathways.

Presented by:

Julian Palandri  

Graduate Student           

University of Calgary

Category: End User

Modelling the Future Net-Zero Transition of Western Canada's Heavy-Duty Freight

The objective of this technical poster will be to highlight our ongoing investigation into the net-zero transition of the heavy-duty trucking sector in Western Canada. Through the creation of two stock and flow models, one to track future registered heavy-duty trucks and another to track vehicle kilometres travelled, we can project Western Canada's heavy-duty trucking sector toward 2050. These projections will help to determine if Western Canada can meet the federal government's target of 35% zero-emission vehicle sales by 2030, both in how that transition will affect future zero-emission fuel types, and the economics surrounding this. Through creating different scenarios for the two models, we will test different transition strategies and compare the resulting transitions through metrics like cost to government and industry, investment requirements for infrastructure, total cost of CO2e emissions from carbon tax and savings from CO2e emissions abated. These calculations will be done through obtaining both government data on Western Canada's heavy trucking fleet and further research into the technical aspects of new zero-emission heavy-duty fuel types for GHG emission comparisons. This research aims to help inform both government policy and industry on the future transition of heavy-duty vehicles in Western Canada, if federal targets can be met, and which scenarios provide the best economic advantage for future transition.

Presented by:

Zachary Redick 

Master's Student            

University of Calgary

Category: End User

Preliminary Winter Performance Results of AZEHT Project in Edmonton, Alberta

The Alberta Zero Emission Hydrogen Transit (AZEHT) project is the first of its kind in Canada to trial two hydrogen fuel cell electric transit buses (FCEB) under the real-world climate condition of Alberta and demonstrate a credible zero-emission bus fleet transition pathway. The project is led by the City of Edmonton in partnerships with the AZEHT transit partners. Edmonton Transit Service and Strathcona County Transit are the two main stakeholders. Other project partners are Suncor Energy, New Flyer, The Transition Accelerator, and the University of Alberta.

The project will start in January 2023 and end in January 2025. The Transition Accelerator is a key partner in this project to perform data collection, analysis, and reporting for the project, including different drive trains performance monitoring and comparison under a wide range of conditions, in collaboration with the University of Alberta. Fuel consumption data is also collected to calculate GHG emissions associated with lifecycle of the demonstration project. The first two full winter months performance results will be presented at the 2023 Canadian Hydrogen Convention to showcase the project and share knowledge learned.

Results of this 23-month demonstration will help to inform not only the GHG costs and benefits of the FCEBs compared to other alternatives, but also an assessment of the total cost of ownership, as it is critical in serving as a test model to enable each municipality to incorporate the FCEBs within their daily operations and gain real-time operational data on the bus performance in real world applications, understand the full environmental benefits, and define the best fit for the application of the technology.

Presented by:

Junan (Jacob) Rao          

Project Analyst 

The Transition Accelerator

Category: Transport and Storage

Safe Transportation of Blended Hydrogen through Pipelines

Hydrogen is key to achieving the nation’s 2050 net-zero emissions goal and calls for research to enable safe transportation. Compared to trucks and rails, long-distance transportation and distribution of hydrogen through pipelines are safe and economical. Pipelines already exist, including long-distance and distribution networks of natural gas pipelines in which hydrogen can be transported efficiently by blending with natural gas. However, hydrogen is a very light and highly combustible substance, creating transportation safety challenges. Many studies and projects have researched general issues with blended hydrogen transportation through existing gas pipelines and addressed potential risks from operation to failure events. The most critical question in transporting blended hydrogen is whether one can safely use existing natural gas pipelines. This study investigates the flow behaviour of blended hydrogen for safe transportation through pipelines through judicious combinations of experimental and modeling investigations. Developing new leak detection strategies of blended hydrogen and monitoring of hydrogen behaviour in pipelines are critically important in hydrogen safety. Continuous monitoring will replace pipeline inspection’s current reactive behaviour. The critical problem of blended hydrogen, especially with odorants, is that the gas mixture can become stratified due to different densities. This issue is predominant in distribution pipelines (for example, during a summer evening there may be no gas consumption) where a no flow condition could exist for a long period of time. Hence, when a leak event occurs near the top of a pipeline with a stratified blended gas, the potential for the release of more buoyant hydrogen molecules exists leading to a higher safety risk from the perspective of both detectability and flammability. We have examined the blended hydrogen behaviour including stratification and leaks for distribution pipelines. When a leak event occurs near the top of a pipeline with a stratified blended gas, the potential for the release of more buoyant hydrogen molecules exists leading to a higher safety risk from the perspective of both detectability and flammability. We have been developing unique nanocomposite sensors for hydrogen leak detection. The newly developed leak detection sensors can be integrated with existing and new pipelines. The project is timely and critically important for reaching the hydrogen economy that would benefit Albertans while ensuring the net zero energy transition.

Presented by:

Simon Park        

Professor

University of Calgary

Category: Production

Waste to Hydrogen: A Techno-economic Analysis of Hydrogen Production

“What if waste wasn’t” is a popular phrase and laudable goal for our society. The idea being that all waste could be eliminated by having a circular economy through the conversion of biomass, plastics and other waste streams to other valuable products such as hydrogen. Waste is heterogeneous with an inconsistent composition, which impacts its energy content (heating value) and processing (clean-up requirements). To be economically and environmentally feasible, the plant in which the waste is converted to hydrogen must be located where there are: i. sufficient feedstock, ii. a low carbon energy source to operate the process, iii. a means to use or transport the hydrogen, and iv. a means for carbon capture and sequestration (CCS) for the CO2 produced in the process.

In this study, a process model is built for the distributed production of hydrogen with and without CCS from a variety of a waste streams using ASPEN Plus Simulation Software. The model is used to document energy and material flows, as well as the emissions and costs of hydrogen production with a particular focus on plastic and biomass residues. Using the model, we evaluate the optimum size of the plant as a function of the feedstock mix, CCS availability (e.g., Alberta Carbon Trunkline or geological storage in the North), and regional hydrogen demand (e.g., fueling stations for heavy-duty trucks).

The model is validated from published data describing a mixed feedstock of 638 t/day of dry coal and 521 t/day of dry torrefied biomass per day with a gasifier of a thermal capacity of 356 MW (30,743 GJ/day lower heating value, LHV). This plant produces 129 t/day H2 (purity 99.9%), equivalent to a H2 conversion efficiency of approximately 0.505 GJLHV of H2 per GJLHV from the total feedstock, which compares favourably with a reported value of 0.511 GJLHV of H2 per GJLHV feedstock. The plant produces 2,664 t/day of pure CO2 at 153 bar ready to be transported and stored permanently, which is equivalent to a CO2 capture rate of ~93%. A carbon intensity is 1.63 kg CO2/kg H2 (13.5 gCO2/GJLHV), which is below the CertifHy low emission H2 limit of 4.37 kg CO2/kg H2. Results show that the levelized cost of hydrogen tends to be higher than that from steam methane reforming. However, it is reduced if tipping fees are paid to the operator for waste disposal, and if capital tax credits can be claimed for low carbon hydrogen production. We also assess the value of producing hydrogen at the scale needed to match local demand, and compare this to the cost of centralized hydrogen production where there is also substantial cost to transport the fuel to remote fueling stations.

Presented by:

Josephine Hill   

Professor           

University of Calgary