Low-Carbon Hydrogen produced from Natural Gas is a key component of a net-zero future.

This presentation will present some of the leading technologies for the syngas generation that can be used for Blue Hydrogen production and explore the difference between these technologies.

Technologies to be discussed are:

• Steam Methane Reforming (SMR)
o pre-combustion CO2 removal
o post-combustion CO2 removal
• Auto Thermal Reforming (ATR)
• Partial Oxidation (POx)
• Heat Exchange Reforming (HXR)
o Parallel configuration
o Series configuration

In the last year, the hydrogen industry in Canada has started to proliferate, gaining momentum globally. Canada is becoming a leader worldwide in hydrogen production and related technology development. Regional strategies have been developed to promote a hydrogen economy across Canada, aiming to produce 20 Mt of hydrogen by 2050. The objective of this market study is to provide a state-of-the-art of the hydrogen industry in Canada for companies that are looking for investment and partnership opportunities as well as for governments. This study covers three fundamental aspects: first, an overview of the existing Federal and Provincial policies affecting the development of the hydrogen industry. Then, a classification of critical players in the Canadian hydrogen value chain, including potential end clients, project owners, upcoming projects, and research organizations. And finally, the main trends and most recent announcements on hydrogen in Canada, including challenges, developments, and future direction of the hydrogen economy. This was achieved by initially conducting a detailed review of the hydrogen strategies and roadmaps developed across the country and identifying the key aspects subject of this work. Later, an exhaustive literature review was conducted to classify the stakeholders depending on their role in the hydrogen sector. Finally, representative players identified were interviewed to understand their perspective on the direction of the hydrogen industry in Canada and the challenges, opportunities, and trends. The most relevant findings from this study are that hydrogen hubs are being formed around Vancouver, Edmonton, Calgary, and Toronto to promote the development of hydrogen fuel cells, electrolyzers, steam reforming, and carbon capture, utilization, and storage technologies. The corresponding provinces, British Columbia, Alberta, and Ontario, are leading the development of a hydrogen economy in their regions. Canadian businesses are collaborating mainly with Northern European and Chinese companies, and potential niches for future collaborations with other countries have also been identified in this report. To the extent of our knowledge, this Canadian hydrogen market study is the first of its kind that any company or country can use as a reference for establishing collaborations, partnerships, or investments with the hydrogen industry in Canada.

Low carbon hydrogen and methanol together form the lynchpins of the clean energy economy. The low emissions impact of electrolytic hydrogen produced from renewables (eHydrogen) makes it an excellent starting point for the eFuels economy, however price parity with steam methane reforming (SMR) has remained elusive. Methanol, when produced from Green Hydrogen and captured CO2 (eMethanol) enables a fully circular green energy economy. Not only is methanol an excellent storage and transportation medium for hydrogen, it is an emerging solution to decarbonize maritime transport, a petrochemical feedstock for making olefins, and the gateway to higher carbon eFuels. These eFuels include CO2-neutral synthetic gasoline and sustainable aviation fuels (SAF), which are drop-in solutions to decarbonize transportation. The economics of eMethanol production are extremely sensitive to hydrogen cost, which is 95% of the OPEX. Thus, the key to favourable production economics for both eHydrogen and eMethanol is at its heart a materials challenge - both processes require highly efficient catalysts that must withstand severe service conditions, including resistance to chemical, thermal and mechanical attack. Quantiam’s catalysts and coatings for water electrolysis deliver hydrogen at a levelized cost of hydrogen (LCOH) that rivals that of SMR. We target the three main cost drivers: catalyst efficiency, electrode surface area, and electrode reliability. The increased efficiency and surface area reduce plant power consumption, increase hydrogen production rates, and reduce required stack sizes. The stack reliability produces more hydrogen over a longer lifetime and reduces operational and maintenance costs. In addition, our durable, earth abundant, non-supply chain limited materials and highly automated and scalable coatings process significantly reduce both catalyst and stack assembly costs. Our catalysts may be applied onto most electrode / membrane configurations and constitute an effective drop-in solution for electrolyzer OEMs. Quantiam’s CO2-to-Methanol catalyst and process is optimized for a direct hydrogenation of carbon dioxide-to-methanol (a one-step process) with CO2-only feed. This provides a significant advantage against many incumbent catalyst and process solutions involving multistep processes or mixed (CO/CO2) feeds. Our methanol catalysts have been designed to withstand oxidation-based deactivation mechanisms. The catalyst has been engineered from the ground up to maximize single pass conversion, methanol selectivity, and reliability, without requiring excess hydrogen above the minimum stoichiometric ratio. These improvements minimize hydrogen consumption, recycle requirements which significantly reduce plant CAPEX and OPEX. Quantiam Technologies Inc. is a is global leader in the development of advanced materials, coatings and catalyst coatings for severe service conditions, and in coating of complex shaped components.

The growing concern that anthropogenic greenhouse gas emissions are causing irreparable impacts on our planet’s climate has driven the development of policies and regulations to reduce emissions, and many industries are taking on the challenge of moving toward net-zero emissions. NOVA Chemicals has begun the decarbonization journey through an exploration of various technological pathways to support the decarbonization of their petrochemical facilities. Through the evolution of the NOVA Chemicals decarbonization roadmap, we’ve identified that a variety of technologies will be required to achieve net-zero, however clean hydrogen has emerged as one of the most promising pathways to reach net-zero within our facilities. The concept of converting our fuels to 100% clean hydrogen provides significant decarbonization potential, however discussions with key subject matter experts across our organization have also identified several existing hurdles that will require further technical innovation to support this fuel conversion. The objective of this presentation will be to describe both the opportunities and challenges of using clean hydrogen to support decarbonization of the petrochemicals industry.

To combat the effects of climate change, governments, the energy industry, and consumers globally have accepted that there is an urgent need to transition into cleaner sources of energy such as blue hydrogen. Blue hydrogen is an energy carrier derived from natural gas that presents an opportunity for decarbonisation as well as a potential source of more environmental damage if not implemented correctly. The United Kingdom like many other countries has invested vast resources into planned blue hydrogen projects for various end-use applications and this development has received pessimistic opinions on the impact of blue hydrogen towards net zero largely on the environmental perspective. In this presentation, we will present our work on blue hydrogen lifecycle assessment study with a link to policy development and implementation. The detailed study was carried out using the LCA cradle to gate approach in compliance with ISO 14044 and covers production to utilisation stages using a case study plant. The study results demonstrate how the proposed blue hydrogen projects for instance in the UK can meet the emissions standard of 20gCO2-eq/MJ H2 given by the UK Government while using evidence-based lifecycle assessment process. This study’s findings on evaluation of blue hydrogen with its complexities as an energy vector for decarbonization suggests that blue hydrogen can be environmentally sustainable if energy consumption is managed and material production and use is efficient. Further findings will be discussed, conclusions drawn, and future perspective outlined. The study will have impact on moving towards a firm consensus on the production scale limits of sustainable blue hydrogen production locally, regionally and globally as well as aligning policy development and implementation with environmental goals such as the net zero.

EverWind is North America‘s leading independent green hydrogen and green ammonia developer, building a 1 million tonne per annum green ammonia facility at Point Tupper, NS, Canada. The first phase of the Project has received environmental permit and is set to produce and export 200,000 tonnes of green ammonia per annum starting in 2025 and then achieve the full 1 million tonnes per annum production by 2026. EverWind owns and operates the deepest ice-free berth on the East Coast of North America, with world class access to rail, roads and pipelines. ILF Consulting Engineers is the Project’s Owner’s Engineer and will provide an overview of the project and its exciting multi-phase plan.

As per Environment and Climate Change Canada’s 2022 report on Greenhouse Gas Emissions, Canada's total GHG emissions in 2020 were 672 megatonnes of carbon dioxide equivalent. The transportation sector accounts for 24% of the total emissions. Between 1990 and 2020, GHG emissions from the transportation sector grew by 32%. This growth was mostly driven by increases from freight and light trucks, as per the report. It is abundantly clear that decarbonizing the medium-and heavy-duty transportation sector will significantly propel Canada’s drive towards its net-zero goals. HTEC, Canada’s leading clean hydrogen solutions company, helps medium and heavy-duty transportation transition towards a low carbon future through hydrogen powered vehicle supply solutions and adoption support. This presentation will outline the environmental case for hydrogen adoption by the medium- and heavy-duty transportation sector including the application of FCEV, its financial viability, and the working legitimacy of transitioning Canadian fleets to hydrogen. HTEC has been working on several projects in varied capacities to support this transition. Alberta-based AZETEC project features the development of two long-range fuel cell electric trucks (FCET) for operation between Edmonton and Calgary. HTEC is providing fuel supply solutions, including a compression and purification system: HTEC’s PowerCube modular storage system and PowerFill high-volume gas transfer module, enabling the heavy-duty transportation market’s move towards a low-carbon future. The presentation will also discuss how HTEC completed Zero Emissions Bus (ZEB) rollout plans for three transit agencies in California: SunLine Transit, Golden Empire Transit (GET), and Fresno Area Express (FAX). Each plan incorporated a mix of fuel cell and battery electric buses that ensure the agencies will be able to maintain their current level of service while minimizing the transition cost. Current geopolitics and climate agreements is accelerating the commitment and enthusiasm for this transition. HTEC’s modeling and analysis shows that the future of the medium- and heavy-duty transportation sector will need to be reliant on hydrogen to achieve our net-zero goals.

Objectives/Scope: Blue hydrogen has attracted a lot of interest, especially in countries with abundant fossil fuel reserves such as Canada. Currently, there is a good understanding of the techno-economic and GHG emission performance of natural gas-based technologies for hydrogen production with carbon capture and storage. However, there is very limited information in the literature regarding the impact of carbon capture and storage on water demand. Methods, Procedures, Process: We studied the water demand in hydrogen production via steam methane reforming, auto-thermal reforming, and natural gas decomposition with and without carbon capture and storage. We assumed that CO2 is captured via commercialized amine scrubbing. Captured CO2 is transported meeting the Alberta Trunk Line’s operating conditions for subsequent underground storage. Results, Observations, Conclusions: The main output of this study is water demand coefficients for different stages, hydrogen production, CO2 capture, CO2 transportation, and CO2 storage. Water demand includes water withdrawal, water consumption, and water discharge back to the water source. Novel/Additive Information: The results of this study provide an understating of the impact of low-carbon hydrogen on the freshwater resources. It can be helpful for policy- and decision-makers to identify opportunities and areas of improvement in hydrogen deployment as a pathway to attain the Paris agreement goal of net-zero carbon emissions by 2050.

Over 90% of TCE’s current emission comes from stationary combustion by turbines used in power plants and compressor stations. The object of this talk is to evaluate the technical-economic viability of using methane pyrolysis to decarbonize compressor stations. TC energy has been investigating various technology pathways to decarbonize compressor stations such as electrification, carbon capture, utilization, and storage (CCUS), fuel switching with hydrogen or RNG as well as carbon offsets. Methane pyrolysis provides a potential alternative solution to generate hydrogen on-site at a compressor station when other options are not feasible duo resources limitations with CO2 think, power or water. Methane pyrolysis uses electrical or thermal energy to decompose methane into hydrogen gas and solid carbon, providing a CO2 emission-free pathway for making hydrogen from natural gas transported in the transmission system. Solid carbon can be either sold as a by-product or, when at scale, disposed as solid waste. There are three major types of technologies: plasma, thermal and catalytic processes. The technical attributes of the three processes are detailed in the presentation. Plasma and thermal technologies are considered for two case studies due to their advancement and momentum to the market. Case 1 is based on a generic 30MW brownfield compressor station and Case 2 is for a generic 100 MW greenfield application. The energy consumption, order-of-magnitude Capex and Opex are presented. Overall, methane pyrolysis is a promising technology as some of the developers are getting close to early adoption, especially plasma technology. It provides an alternative solution particularly when access to sequestration, water, or electricity are challenged. Without carbon sales, the levelized cost of turquoise hydrogen is not competitive against blue hydrogen but it is competitive against green hydrogen. Carbon sales even at the lowest market price would enable turquoise to compete against blue hydrogen. As with any emerging technologies, the commercial costs of methane pyrolysis at scale need to be further refined with early demonstration and adoption. The developers also need to address some key technical challenges with scale-up such as key equipment sizing, efficient heating, carbon fouling as well as integration of the system. Reliability of key equipment needs to be confirmed with longer testing and operation. In addition, market and logistics for large quantities of solid carbon need to be developed, especially for using methane pyrolysis in remote compressor stations.

Currently, Canada’s Northwest Territories (NWT) imports 89% of its energy as fossil fuel-based energy carriers to meet the demands of 45,132 people living in 33 communities. Consequently, per capita emissions are 1.8 times the Canadian average. To meet Canada's 2050 net-zero goal, the energy systems of the NWT must transition to zero-emission energy carriers like electricity, bioenergy, hydrogen and ammonia, all produced with minimal or no fossil-based carbon emissions. To understand the nature of the challenge, government data was used to quantify the energy systems of the NWT in 2019. Of the total 21.5 PJs of energy demand in the NWT: 1. Freight transportation was the largest consumer (39%), compared with buildings (28%), passenger transport (18%), and industry (12%). 2. Freight Transport energy demand was dominated by diesel use in on-road heavy-duty trucks, which made up 30% of the NWT’s total CO2 emissions. 3. Building energy demand is supplied by diesel (54%), biomass (21%), electricity (15%), propane (8%), and natural gas (1%). 4. Passenger travel energy demand for jet fuel to support passenger aircraft (58%) has more energy demand than gasoline use in personal vehicles. 5. Industry energy use is comprised of mining activity (82%) and oil and gas recovery. Diesel fuel imported from Alberta is the dominant energy carrier consumed in the NWT, estimated at 350 million litres or 7750 L diesel per capita per year. At the current wholesale price for diesel ($1.41/L ), the cost to the NWT is $493 million or $10,935 per capita per year. If diesel and other fuel demands could be met by zero-emission energy carriers produced in the NWT, the environmental benefits could coincide with substantial economic benefits and job creation. To explore whether the NWT’s vast undeveloped hydro resources (11,520 MW) could power a net-zero NWT energy system, literature sources were used to quantify the useful energy and energy losses for both existing and alternative net-zero technologies serving various sectors of the economy. By assigning zero-emission energy carriers (electricity, biomass, hydrogen, ammonia) to each sector and assuming that hydrogen and ammonia were made from water electrolysis, we calculated that 3,623 GWh of additional electricity is required. This included direct use of electricity for light-duty vehicles and heating (231 MWh), production of hydrogen for direct usage in heavy-duty vehicles (846 GWh), and production of hydrogen and then ammonia for transport and storage to service remote communities (2,546 GWh). Given a capacity factor of 53%, the NWT would require 780 MW of additional hydroelectric capacity to be net zero and near energy self-sufficient. Further work is needed to explore the economic feasibility and social acceptability of this scenario and others focused on transitioning the NWT to net zero emission energy systems.

Currently, most hydrogen production operations are centralized, large-scale steam methane reforming (SMR) units dedicated to providing hydrogen for refining or petrochemical operations. These operations are dedicated to specific processes without any need for long-distance transmission and distribution. But what if the hydrogen economy moves toward utilizing hydrogen as one of the mainstream energy vectors? In that case, a delivery and distribution network will be required, bringing several technical challenges that will need time to develop solutions. Some of these challenges will include inefficiency and energy loss during the transportation of hydrogen, capital and operational cost of transportation, practicality from a safety perspective and scalability and time required for development and delivery to market. As much as hydrogen has the highest specific energy on a mass basis, which makes it one of the best energy vectors for broad use, it has a very low energy density on a volume basis and hence many challenges and costs associated with transporting and delivering hydrogen to the end user. This drives hydrogen projects to be planned as big as possible to take advantage of the economy of scale. Such a large-scale deployment of hydrogen production and distribution will require time to gain investors' trust in market size, availability, and adaptation of new end-use products for relying on hydrogen as a clean energy vector. The decentralized turquoise hydrogen production unit has the advantage of delivering on-demand hydrogen wherever there is the availability of electricity and natural gas. A network of on-site modular turquoise hydrogen production units can enable faster adoption of the hydrogen economy and make hydrogen available for retail consumers without dealing with hydrogen transportation challenges and costs. This will assist with the more rapid adoption of the transition to the hydrogen economy and will create confidence in investors for market size and availability to invest in large-scale hydrogen production technologies. InnoTech Alberta has developed a decentralized hydrogen technology to enable on-site turquoise hydrogen production for retail consumers, such as trucks and fuel cell electric vehicles (FCEVs). The elemental carbon produced during this process can be stored underground and removed for disposal or post-processing off-site. The design of the process is intended for the unit's operation with minimum dependency on the on-site personnel and has the potential for fast process start-up and shut down. The system will be designed to include a compression system for both 700 and 350 bars to make it suitable for fueling small cars and large trucks and buses.

One potential carbon footprint reduction measure that many industrial facility owners are currently contemplating is the firing or co-firing of non-carbon-based fuels like hydrogen and ammonia in their steam generation equipment. However, the addition of different gaseous fuels to an existing boiler has ramifications that need careful consideration. Proper evaluation is needed to determine necessary system modifications for the concept to be implemented successfully and safely. During this presentation, B&W will discuss the various system and equipment design considerations for hydrogen firing and look at a few case studies of package boilers where hydrogen was added as a fuel.

ATCO Gas and Pipelines Ltd., through partnership with Emissions Reduction Alberta has undertaken a pilot project within the city of Fort Saskatchewan, Alberta to blend up to 20% hydrogen into a portion of the City’s existing natural gas distribution utility grid. This project aims to demonstrate that blending hydrogen into the natural gas distribution system is a feasible and sensible solution to decarbonization, especially within jurisdictions with extreme climates, such as Alberta’s. The project includes localized hydrogen production, storage, blending and distribution to approximately 2100 customers. As of the date of commissioning (October 26th, 2022), this project delivers the highest blend of hydrogen to the most customers in Canada. This project involved the design, procurement, construction, and commissioning of high (4,000 kPa) and intermediate (550 kPa) pressure pure hydrogen and blended gas piping systems. Due to lagging industry guidance in the form of normative codes and standards related to hydrogen piping systems, ATCO established project specific design requirements and philosophies. ATCO proactively undertook a wide scale Organizational Change Management (OCM) process, ensuring that challenges within all areas of the natural gas utility business that would be impacted by introducing hydrogen were understood and thoroughly solutioned prior to commissioning. This effort will allow ATCO to execute on future blending projects rapidly. Additionally, ATCO was committed to extensive engagement with impacted customers, and the public to ensure that customers, regulators, and governmental bodies were comfortable with the scope of the pilot project prior to commissioning. This presentation examines the strategy, planning, and execution that ATCO undertook related to design, construction, corporate MOC and public engagement to make the Fort Saskatchewan Hydrogen Blending project a success.

Hydrogen production is set for huge growth in the next five years with hundreds of projects from small, “over the fence” supplies to complex, regional-based, generation and delivery networks. These larger projects, using multiple varieties of hydrogen, delivered in various forms, will grow as companies and governments invest to meet their net-zero commitments. Joint venture and collaborative projects will also become increasingly prevalent as large hydrogen networks gain momentum to meet demand in the major global industrial hubs. These projects, by their very nature and size, need to be carefully managed to ensure that all parties work effectively and collaboratively, delivering the necessary cost and timescales that will make these capital-intensive projects cost effective for their Investors.
This presentation highlights a lifecycle, digital approach to deliver and manage a hydrogen network from end-to-end. This approach uses digital technology and best practices to incorporate existing hydrogen production with new capacity, which helps ensure project delivery at the right time and price, while:

• Still meeting the overall net-zero commitment for the network.
• Maintaining a strict CAPEX budget and minimizing risk and cost overruns.
• Leveraging the engineering and construction phases to deliver an overall operational infrastructure and data management that drives OPEX optimisation and hence improves the overall project’s time to break even.

The generation of green hydrogen through electrolysis requires a large amount of plentiful, cheap and stable, green energy. The levelized cost of both onshore wind and solar energy have steadily decreased over the years to the point where both forms of generation are the most cost competitive in many jurisdictions. However, both solar and wind energy have high intermittency, which can significantly impact the performance of the electrolysis of hydrogen especially for applications where stable and consistent hydrogen production is required (e.g. green ammonia synthesis). The intermittency of the renewable energy system can be mitigated through parallel optimization of the power generation profiles with the sizing and operation of hydrogen production and storage system. A temporally consistent timeseries methodology will be presented, with quantified techniques to optimize the design and utilization of hydrogen plant to minimize the levelized cost of green hydrogen for specific demand scenarios. After the presentation, the audience should have a clear understanding of the optimal integration of a modern renewable energy generation system with a green electrolysis facility for low-cost green hydrogen production.

Technical Course pass holders will be able to enjoy a delicious lunch before visiting the exhibition floor.

Access to the Technical Delegate Lounge is only available to technical course pass holders only.

Low-Carbon Hydrogen is a key component of a net-zero future. Organizations are working on production technology and the supply chain. At the same time, uses for low-carbon hydrogen are being solidified. The needed infrastructure is being identified. Traditionally, market forces would balance the supply and demand side, but will this traditional approach grow both the production and use side of the equation fast enough to meet ambitious targets to decarbonize economies by the middle of the century?

Will technology providers build huge new manufacturing facilities without firm orders, or will they only take small steps at a time? Will potential producers place equipment orders and start construction without a firm offtake agreement? Will users on the demand side sign long term offtake agreements, and build the infrastructure to use the hydrogen, while uncertainty remains with production technology, timing of supply and long-term pricing?

Complicating the situation is that the Hydrogen Production and Hydrogen Demand may be in different countries, requiring international cooperation and added infrastructure for storage and transportation.

This presentation will further explore the importance of the synchronization of Supply, Demand, and Infrastructure, then discuss methods to ensure this synchronization happens, during this decade, so we set the stage and stay on pace to meet our global goals in the coming decades.

Transitioning the heavy-duty transportation sector to low- or zero-carbon operations is not a simple task. For a smooth transition, zero-emission vehicle options need to offer the performance range and customization as do traditional fossil-based (usually diesel) trucks today. The quickest and optimal transition to zero-emission trucks necessitates utilizing technology that can sustain existing trucking business models with minimal operational disruption. Hydrogen fuel meets the varied needs of the heavy-duty freight sector. Although battery electric vehicles (BEVs) are farther down the technology readiness path, some early rollouts of hydrogen fuel cell electric vehicles (FCEVs) in the US and Europe already surpass BEVs in terms of payload capacity, range, and fueling time, and thus offer the most convincing one-to-one solution for diesel replacement. And hydrogen/diesel dual technology already offers a cost competitive option in the transition period. Successful deployments of fuel cell electric buses, trains, and fuel cell electric forklifts have already proven this capability. But for the heavy-duty transportation to comfortably adopt hydrogen to meet government decarbonization targets, The Transition Accelerator (The Accelerator) argues that the pace and scale of adoption and integration of new technologies need to match the ambitious goals. To achieve scalability and right market conditions for the transition, The Accelerator is proposing that at least two Canadian Hydrogen Corridors are needed. Corridors are envisaged as a network of hydrogen refueling stations or nodes that would enable trucking companies to operate hydrogen-powered trucks to achieve decarbonization in the heavy-duty transportation along major transportation routes in Western and Eastern parts of the country. These Corridors will also accelerate economic development opportunities by linking supply and demand regions with fueling stations and trucks on the road and providing a regional opportunity to adopt hydrogen as a clean energy source in concentrated demand areas such as regional and local public transit, space and water heating, and power generation that could also accelerate development of regional hydrogen Hubs. Our Approach is to first develop a business case with aligned interests for Western Canadian Corridor. This involves: a) Working with early adopters along the TransCanada highway from Winnipeg, Manitoba to Vancouver, British Columbia to accelerate and enable economic development opportunities for local and provincial stakeholders such as public sector, economic development agencies, transportation companies, fuel suppliers and others b) Developing a Western Canadian Corridor Roadmap c) Enabling a build-out of hydrogen refueling assets d) Assessing regional opportunities for hydrogen adoption e) Sharing lessons learned, best practices, challenges, risks, and barriers f) Realizing similar opportunities in Eastern Canada. The Accelerator is gauging interest and building the momentum and support to flesh out details. Achieving the vision presented in this document requires the collaboration of all stakeholders to create the roadmap and take action!

Near-zero emission industrial plants can already today be designed or retrofitted applying approaches characterized by elimination and capture of the generated carbon dioxide (CO2) resulting from combusting or converting carbon-containing fuels. Linde has developed a suite of “Blue” Technology Solutions for decarbonizing production processes using hydrocarbons. Linde will present on three categories: “Post-combustion CO2 capture”, “Pre-combustion CO2 capture and hydrogen fuel switching” and “Oxy-fuel combustion CO2 capture”.

Linde will include examples of how “Blue” decarbonization solutions can be applied across the power, chemicals, refining, mobility, and hydrogen energy carrier spaces. This paper will give an introduction into these fundamentally different solution approaches for industrial applications and walk the audience through how to choose the right solution for their application.

A wide range of decision criteria play a role when it comes to the selection of the most appropriate solution for given site-, project- and customer-specific constraints, including for example:

• Individual properties of CO2 emitters, like volume and CO2 concentration
• Emitter distribution and access with respect to available plot
• Capital expenses required for the modification of the existing assets and the new installations
• Considerations with respect to capital allocation (i.e. CO2 elimination units operated centrally by others)
• Impacts on the operation and dynamics of the foundation plant as well as reliability of the CO2 elimination units
• Impact on total thermal energy demand and utilities in general as well as energy integration potentials
• Aspects and long-term strategies associated with utilization of generated methane within the petrochemical site
• General flexibility towards combination with other CO2 reduction methods and various possible long-term strategies intended for the given site
• Possibility for staged implementation scenarios

Profound experience across multiple technology fields and industries, including petrochemical, hydrogen and CO2 processing plants, is required in order to identify the most suitable solutions for given constraints. At the example of decarbonizing world-scale industrial sites, the paper will highlight how an experienced licensor and operator can support the solution definition in such a multi-criteria decision process.

Building on ATCO Gas and Pipelines Ltd. and Certarus Ltd.’s long standing partnership supplying virtual pipeline solutions during natural gas outage events, ATCO and Certarus will detail how they were able to leverage this relationship and transition their expertise in into an evolving energy landscape to provide virtual pipeline and blending solutions for hydrogen and hydrogen blended natural gas. In this presentation ATCO will detail how they were able to supply strategic customers and stakeholders with a temporary supply of hydrogen blended natural gas as part of a community and stakeholder engagement campaign to broaden the awareness of hydrogen as a decarbonization strategy moving forward. ATCO will also discuss a pivot from hydrogen production to a hydrogen virtual pipeline solution and how this was effectively utilized during supply chain interruptions which could have had significant schedule delays and ultimately put Canada’s largest hydrogen and natural gas blending project on hold. Certarus will address how they utilized their virtual pipeline model to safely supply and blend hydrogen into existing natural gas grid connected systems. Virtual pipeline and blending solutions allow faster adoption of hydrogen as a low-carbon fuel source for decarbonization strategies by allowing companies like ATCO to evaluate the impact of hydrogen and natural gas blends on emissions and existing equipment/infrastructure performance.

This presentation will describe actions that developers of hydrogen production and utilization technologies can take to ensure high reliability in their products, at various technology readiness levels (TRLs). The presentation will use US DOE technology readiness level descriptions, and for key levels of technological readiness, describe design, verification and testing activities suitable for evaluating and improving the reliability of hydrogen-related technologies. Content will include: - Techniques to evaluate lifetime durability of components of hydrogen and fuel cell systems - Allocation of reliability requirements for system and component design specification, - Comparative tracking of Hydrogen Fuel Cell performance (lab vs. real-world) - Reliability assessment and growth programs for fleets of prototypes. - Tools and skills to collect vital information for reliability assessment and growth.

Unprecedented catalyst technology has been discovered for thermocatalytic production of hydrogen from water or methane under mild conditions. Thermal gasification of water is energy-intensive and primitive; current technology requires solar heating to 1200-2000 °C and the use of supply-limited lanthanide catalysts. The technology for thermocatalytic methane carbonization has progressed significantly over the past decade, but remains energy intensive and operationally unprofitable, requiring operating temperatures of ≥1000 °C, even with existing catalysts. Alberta’s blue hydrogen future needs disruptive technology. Dark Matter Materials Inc. (DMM), introduces an unprecedented family of earth-abundant metal catalysts capable of producing hydrogen from either methane or water under exceptionally mild conditions. “Dark hydrogen represents a new paradigm in catalytic water gasification and an economically viable pathway to methane carbonization. The Hamilton-Stryker catalysts comprise a new class of earth-abundant non-strategic metal nanocatalysts designed from first principles to activate O?"H and strong C?"H bonds by the lowest possible energy mechanisms. The catalysts are cost-effective and versatile: thermocatalytic water gasification can be driven by heat alone by incorporating an inexpensive metal reductant to scavenge the oxygen produced. The solution phase process is exothermic and initiates below 60 °C, Hydrogen production requires neither electricity nor sunlight and provides a ready source of off-grid hydrogen. This process results in little oxygen, providing a distinct advantage over complex and costly, polymer-electrolyte membrane (PEM) systems which separate oxygen from hydrogen. In this process, water is the energy carrier, not hydrogen, which is generated on site. The catalysts are water agnostic, tolerating greywater, saltwater, and produced water, including untreated bitumen tailings water. There is no comparable technology in the marketplace or on the horizon. The same catalysts can also carbonize alkanes, such as methane, at temperatures as low as 250 °C, representing a disruptive reduction in energy, dissipated heat, and infrastructure costs. As a considerable bonus, the carbon produced at these temperatures is anything but amorphous ?" most of it is isolated as graphene and luminescent carbon quantum dots (CQDs).

To achieve the transition to 100% zero-emission transport on a global level, transit bus fleets and operators will need both battery electric and fuel cell electric buses to meet route and service requirements. Today, fuel cell electric buses (FCEBs) have shown they are a true zero-emission 1:1 replacement for conventional diesel buses. Thanks to large scale deployments primed for global transition, FCEB projects in a range of cities around the world are already in operation and are demonstrating the potential this technology has for wider adoption across transport markets worldwide. The building blocks for heavy-duty fuel cell electric vehicles (FCEVs) are in place today. There is an excellent understanding of the vehicles, the fuelling and infrastructure that is required, as well as the maintenance setup thanks to the work undertaken on earlier FCEB projects. Hydrogen fuel cell technology is prepared for the transport sector to play its part in the battle against climate change ? delivering a viable and sustainable real-world alternative that reduces urban air and noise pollution, providing a zero-emission clean solution for public transport to enable the decarbonisation of municipalities worldwide. This presentation will track the journey of hydrogen-powered public transit vehicles and chart the trajectory of FCEV development ?" from early outliers of regional FCEB trial projects, through increasingly comprehensive and scaled-up deployments that are taking place today. It will also provide a comprehensive outlook on the scope of future global potential from policy and infrastructure to technology and training, to ensure the transition is practical, sustainable and scalable. The presentation will outline how technology, public service platforms and social acceptance will lead to efficient adoption of large-scale zero-emission powertrain solutions to enable transit decarbonisation. This will detail how alternative fuel will work in tandem to power multiple applications, delivering a hybrid architecture to offer a reliable and effective replacement to high-polluting diesel engines. Using real-world examples to demonstrate how the gap between current projects and large scale deployments can be successfully bridged, the presentation will look at established programs across North America in places such as Oakland, Palm Desert, Santa Ana and Canton; and highlight the work achieved by major industry players ?" including manufacturer New Flyer putting FCEBs on the road across the U.S., SunLine Transit Agency building entire fleets of hydrogen-powered FCEBS and even the California Energy Commission’s latest inventive initiative for vehicle-to-build bidirectional electric vehicle charging. With a forward-looking focus, the presentation will present the competitive positioning of fuel cells, as well as establishing how developing fuel cell product maturity will support and drive an industry-wide transition and how this shift can be effectively sustained through design, manufacture and product use.

One of largest uses of natural gas is for space and domestic hot water heating in publicly occupied homes, apartments, and businesses. A large network of distribution systems currently exists for delivering natural gas to millions of homes. The addition of hydrogen to this infrastructure potentially facilitates the large-scale supply of a “greener” fuel to the general public, provided the hydrogen can be accurately and reliably blended with natural gas in accordance with the highest safety and composition control specifications. SoCalGas’ Hydrogen Home is one of the first fully integrated demonstration project with solar panels, a battery, and electrolyzer to convert solar energy to hydrogen and a fuel cell to supply electricity for the home. Hydrogen is blended with natural gas and used in the home's heat pump HVAC unit, water heater, clothes dryer, and gas stove. The home functions and feels just like a regular home but uses reliable and clean energy 24 hours a day, 7 days a week, 365 days a year. Heating a home with hydrogen is a stepping stone in spooling up the hydrogen economy - by giving the gas somewhere to go, it helps Producers justify the expense of setting up production plants. Spartan Controls' Hydrogen Blending Solution safely blends hydrogen with natural gas for residential use. Now in operation, this presentation will present a look back on the lessons learned from blending hydrogen into one of the first Hydrogen homes.

Hydrogen Safety - Canadian Landscape and Future Approaches Ian Castillo, Sam Suppiah, Steven McGee, Rita Liang, Nirmal Gnanapragasam, Helmut Fritzsche, Lee Gardner, and Don Ryland, Canadian Nuclear Labs Alex Borovskis, Helixos Hydrogen is a key enabler for decarbonisation as countries pledge to reach net zero emissions by 2050. With hydrogen infrastructure expanding rapidly beyond its established applications, there is a national requirement for robust safety practices, solutions and regulations. Canadian Nuclear Laboratories (CNL), a leader in hydrogen safety with 50 years of experience, has established a comprehensive hydrogen safety program to investigate hydrogen behaviour encompassing gas mixing, transport, combustion, and mitigation techniques and products. Furthermore, as a national laboratory, CNL is uniquely placed to facilitate a forum on the emerging needs of the Canadian hydrogen safety landscape that identifies gaps, opportunities, and potential collaborations. Canadian Nuclear Laboratories organized a seminal workshop with over 75 participants from industry, regulators, universities, and other research centres with a two-fold goal in mind. First to look at current and future gaps, or missing skills that will present barriers or opportunities that can improve hydrogen safety, thus enabling broader deployment. And second, to discuss how these gaps and opportunities can be best addressed through existing or developing capabilities nationally or internationally, emphasizing synergistic and collaborative approaches. Taking a systematic and comprehensive approach, five themes emerged from the discussion: Safety challenges in the industrial production and handling of hydrogen, material-related safety issues, safety infrastructure and test facilities, nuclear hydrogen initiatives and stakeholder engagement and community consultation. This paper will present the results of the workshop, the methodology taken to analyse the results, the common trends and the capabilities available across the nation to address the challenges, in a succinct, and actionable manner. This paper will also touch on the solutions and identify potential partnerships to tackle these solutions through collaboration and innovation.

Quantitative reliability estimation is a leading technique for assessing the safety of pipeline systems. This technique incorporates structural reliability models, such as those in fitness-for-service standards, in a probabilistic framework to quantitatively predict future failure rates of structures. The results may then be used to perform reliability-based design and assessment (RBDA) or, if the consequences of failure are also estimated, for a quantitative risk assessment (QRA). While RBDA and QRA are well-established methods applied to pipelines carrying natural gas and conventional liquid hydrocarbons, their adaptation to hydrogen-containing pipelines (whether pure hydrogen or hydrogen-natural gas blends) is still in development. Due to the adverse effect of hydrogen on the fracture properties of pipeline steels, known as hydrogen embrittlement, quantitative reliability models for estimating the probability of pipeline failure in the presence of crack-like flaws are of key interest. This presentation will discuss ongoing work at C-FER Technologies to adapt quantitative reliability models currently used for the assessment of crack-like flaws in conventional pipelines for pipelines in hydrogen service. It will include an explanation of alterations to inputs and models for hydrogen service and will identify key knowledge gaps, with recommendations for how industry may proceed to address them.

This presentation will highlight how to capture the first-mover opportunities emerging in hydrogen production for traditionally hydrocarbon-dominated manufacturing centers. Existing hubs previously dedicated to the production of hydrocarbons hold strategic advantages in scaling into a global hydrogen energy hub ? specifically for manufacturing and deploying equipment key to future hydrogen production and distribution regionally and globally. Substantial activity related to gaining hydrogen hub funding is underway within the United States. In support of the Houston hydrogen hub, we have assessed which advantages make a regional hub attractive to companies. This included analysis and consultation of 100+ market players. It uncovered which existing and emerging strengths are of greatest importance, differentiating among players in the value chain. Once identified, these strengths were compared to other regions seeking to establish themselves as hydrogen hubs, but that do not have a recent history as a hydrocarbon hub. This comparison finds that established hydrocarbon hubs are attractive due to their sophisticated manufacturing base, energy-related ecosystems (including financial elements), and an industrial base ready to integrate electrolyzers and provide demand for hydrogen products. Hydrocarbon hubs have already displayed the ability to continuously adapt to a dynamic and competitive energy system; using innovation and collaboration to create efficiencies that drive down levelized costs of energy. Entrants and start-ups recognize these hubs as an ideal place to gain access to finance, market connections, and EPC support. Existing players in the O&G value chain understand they will need to get ahead of the transition already overtaking them. Key firms are already transitioning to electrolyzer and Balance of Plant (BoP) equipment production. The evaluation has also uncovered emerging pitfalls and industry pain points in investment decision making, material and component shortages, and supply chain weaknesses. In particular, key manufacturers within the hydrogen supply chain are confident they can hold market share from their existing manufacturing base yet moving slowly in the face of a rapidly expanding market. Establishment of a manufacturing hub requires effort in communicating relative strengths and willingness to grow in new directions. Specific actions and key areas of incentive and investments have been identified and have been successful in attracting manufacturers to the hub. These actions are accelerating the development of manufacturing hydrogen electrolyzers and provide a key pillar for extending the societal benefits of the hydrogen economy.

FuelCell Energy is a global leader in the manufacture of stationary fuel cell platforms which provide decarbonized power. The company is also developing Solid Oxide Electrolyzer Cell (SOEC) technology to produce hydrogen by using electricity to split water molecules into hydrogen and oxygen. SOEC has nearly 90 percent electrical efficiency, approximately 20% higher than other electrolysis technologies and this efficiency can be further increased if waste heat from industrial processes is available. When renewable electricity generated by wind or solar is used to power the SOEC no carbon dioxide is produced, in contrast to steam methane reforming processes. There is worldwide interest in electrolysis technologies for a wide range of uses including mobile, industrial, and energy storage applications. An overview of some of these applications and details of the SOEC under development at FuelCell Energy will be presented.

Objectives/ Scope: Many midstream operators are developing plans to introduce Hydrogen (H2) into natural gas networks in concentrations of 0 to 20%. It is important to keep the concentration in all locations in the network within these limits, to control H2 cracking of the pipelines themselves and because most burners are not designed for the different Wobbe and flame speed present with H2 flames. This paper presents a model which dynamically tracks H2 in a complex network and then blends it if the concentration is too high. Methods, Procedures, Process: The model is based on proven technology which has been used on gas of variable quality for 30 years. The key item now is the addition of H2 to the composition mix. The model is dynamic and responds to changes in the H2 concentration and flowrate. It is envisioned that the H2 supply to these networks will be variable (for example solar gene rated H2). This paper will present 6 case studies of showing how H2 effects an existing network. Included in the model for H2 Storage, if the network cannot handle the amount of H2 that is available. At the blending point, there are three upstream branches and two downstream branches and one storage location that is bidirectional. Results, Observations, Conclusions: The case studies will show that for even simple events like a customer trip, the high H2 packets can travel into branches that normally don't see H2. Also, as H2 travels through the pipeline things like the pressure drop increase, the compressor duty and outlet temperature increase. Novel/ Additive Information: The model tracks gas packets dynamically in the network (packet size is based on dispersion length) and calculates the density and energy content based on the local concentration. It then has a built in EOS based on GERG 2008 to calculate the density. Even with this complexity the model can run at speeds 100X for a network that has approximately over 1000 km of pipe with added capability to blend and store H2.

As a versatile, clean and safe energy carrier, hydrogen is expected to play a crucial role in the energy transition required to achieve net zero targets. The provision of low carbon hydrogen at scale is essential for mass decarbonisation efforts, as it is well-suited for use in hard-to-decarbonise areas such as heavy industry and transport. With a number of low carbon standards introduced across the globe (UK, US and EU), minimising the process carbon intensity is of the utmost importance to help project developers achieve the highest possible incentives for their hydrogen plant.

Johnson Matthey has developed a blue hydrogen process which delivers the lowest possible process carbon intensity with high CO2 capture rates and best-in-class economics. The process combines a gas heated reformer (GHR) and autothermal reformer (ATR), and this approach produces a higher hydrogen yield and is more energy efficient than existing steam methane reforming (SMR) technologies (currently the most deployed technology for H2 production). Crucially, this process makes decarbonisation via CCS easier and cheaper than using a steam methane reformer. The process can deliver a high CO2 capture rate (>99%), making it a high efficiency, low-cost solution which provides significant benefits compared with SMR and alternative autothermal reforming (ATR) technologies. The solution is based on established chemical process engineering and over 40 years of operating experience, and is designed to operate at scale, enabling carbon reduction for sectors including industry and dispatchable power

Compared with conventional SMR, the combined ATR/GHR flowsheet demonstrates:
• 10% lower natural gas consumption
• 10% less CO2 produced
• 75% lower capital cost for the CO2 capture system

Use of the combined GHR/ATR flowsheet will futureproof and de-risk projects by minimising the impact of increasing feedstock costs, increasing costs of CO2 transmission and storage, and any potential governmental scheme for carbon taxation. Working with partners and collaborators will further accelerate the deployment of large scale hydrogen plants. This process will enable gas companies to decarbonise their operations, accelerate the energy transition, and improve the sustainability and viability of hydrogen production in the future.

High temperature steam electrolysis (HTSE) is a preferred alternative to conventional electrolysis due to its lower energy requirement (~30%) [1]. HTSE can also co-electrolyse CO2 and steam (HTCE) producing syngas, a mixture of H2 and CO, a fundamental building block for making synthetic products [2] such as synthetic fuels and alcohols. Depending on the feed composition, the HTSE/HTCE electrolyser can: (1) be used for H2 or syngas production, and (2) enable production of syngas with varying ratio of H2 to CO. The unique property of a HTSE/HTCE to operate in H2 production mode and/or in co-electrolysis mode gives this technology great versatility and applicability. HTCE technology has unique appeal for reducing emissions in hard-to-abate industry. However, in co-electrolysis mode, the efficiency of the electrolyser, range of operating conditions and resistant to impurities in feed composition with real industrial feed parameters need to be studied in the laboratory as well as in an industrial setting for advancing the development and demonstration. Practical applications of the HTSE/HTCE technology are linked to the optimization of the ratios of H2 to CO of the syngas at the outlet of the electrolyser to match the requirements of the Fischer-Tropsch synthetic fuels process, and in being able to co-electrolyse CO2 emissions from different sources. A single cell CO2 co-electrolysis experimental program has been initiated in concurrence with a CFF-EIP proposal to NRCan to study the performance characteristics of a 5 kWe stack (Versa Power, FCE) for converting CO2 emissions at St Marys cement manufacturing facility in Ontario. The results of the single cell study, currently in progress, will feed into the planning of the stack testing campaign to optimize the as-produced syngas from the stack, aiming to simulate the syngas properties required for Expander’s proven Fischer-Tropsch process, which currently produces a drop-in Synthetic Diesel product near Calgary Alberta. This paper will present some of the early results of the lab experimental work and explore the merits of integration of the CO2 co-electrolysis technology with Fischer-Tropsch process to maximize efficient energy and water utilization in the integrated process. The impact of the source of power used for the electrolysis process on the carbon intensity of the Synthetic Diesel will also be investigated. [1] J. E. O’Brien, Thermodynamics and Transport Phenomena in High Temperature Steam Electrolysis Cells," Journal of Heat Transfer, vol. 134, p. 031017, (2012). [2] L. Dittrich, M. Nohl, E. E. Jaekel, S. Foit, L. G. J. de Haart and R. A. Eichel, "High-Temperature Co-Electrolysis: A Versatile Method to Sustainably Produce Tailored Syngas Compositions," Journal of The Electrochemical Society, vol. 166, pp. F971-F975, (2019).